ML083440696: Difference between revisions
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Prairie Island Indian Communi ty ATTN: Phil Mahowald Minnesota Department of Commerce | Prairie Island Indian Communi ty ATTN: Phil Mahowald Minnesota Department of Commerce | ||
Responses to NRC Requests for Additional Information Dated October 23, 2008 1 RAI SAMA 1.a Provide the following information regarding t he Probabilistic Risk Assessment (PRA) models used for the Severe Accident Mitigation Alter native (SAMA) analysis (for both units unless otherwise specified): | Responses to NRC Requests for Additional Information Dated October 23, 2008 1 RAI SAMA 1.a Provide the following information regarding t he Probabilistic Risk Assessment (PRA) models used for the Severe Accident Mitigation Alter native (SAMA) analysis (for both units unless otherwise specified): | ||
: a. Provide the core damage frequency (CDF) fo r each of the initiating event categories shown in Figures F.2-1 and F. | : a. Provide the core damage frequency (CDF) fo r each of the initiating event categories shown in Figures F.2-1 and F. | ||
2-2. (The percent contributio n to CDF reported in these figures does not provide sufficient resolution). | 2-2. (The percent contributio n to CDF reported in these figures does not provide sufficient resolution). | ||
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See the response to RAI SAMA 5.a below for a more thorough discussion of these two operator actions. | See the response to RAI SAMA 5.a below for a more thorough discussion of these two operator actions. | ||
RAI SAMA 1.b | RAI SAMA 1.b | ||
: b. Provide the CDF for anticipated transient without scram (ATWS) and station blackout events. NSPM Response to RAI SAMA 1.b The requested information is provided in the table below: | : b. Provide the CDF for anticipated transient without scram (ATWS) and station blackout events. NSPM Response to RAI SAMA 1.b The requested information is provided in the table below: | ||
CDF Contributor Unit 1 (per rx-yr) | CDF Contributor Unit 1 (per rx-yr) | ||
Unit 2 (per rx-yr) | Unit 2 (per rx-yr) | ||
Anticipated Transient Without Scram (ATWS) 1.63E-07 1.65E-07 Station Blackout (SBO) 8.52E-07 9.41E-07 RAI SAMA 1.c | Anticipated Transient Without Scram (ATWS) 1.63E-07 1.65E-07 Station Blackout (SBO) 8.52E-07 9.41E-07 RAI SAMA 1.c | ||
: c. The Environmental Report (E R) notes several differences between Unit 1 and 2, including auxiliary feedwater (AFW) pump breaker c ontrol power, Unit 1 replacement steam generators (SGs), and improved Unit 1 sump design. Provide a complete summary of differences between the units with a discu ssion of the estimated impact of these differences on CDF and the release frequencies. | : c. The Environmental Report (E R) notes several differences between Unit 1 and 2, including auxiliary feedwater (AFW) pump breaker c ontrol power, Unit 1 replacement steam generators (SGs), and improved Unit 1 sump design. Provide a complete summary of differences between the units with a discu ssion of the estimated impact of these differences on CDF and the release frequencies. | ||
Include the reasons for the difference in the emergency diesel generator common cause failure that was stated in Section F.2.1.2.4. | Include the reasons for the difference in the emergency diesel generator common cause failure that was stated in Section F.2.1.2.4. | ||
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As the configurations of the tw o units are nearly symmetrical, the majority of the Unit 2 model development process involved duplication of Unit 1 logic models for the frontline and support systems that were not already in the model as capable of being shared with or cross-tied to Unit 1. Event and logic gate descriptions within these new trees were then changed to reflect the appropriate Unit 2 equipment identifiers. The Rev. 2.0 PRA model was then produced by linking the Unit 1 and new Unit 2 logic models together to support more efficient analysis of equipment and operator failures t hat impact risk on both units. | As the configurations of the tw o units are nearly symmetrical, the majority of the Unit 2 model development process involved duplication of Unit 1 logic models for the frontline and support systems that were not already in the model as capable of being shared with or cross-tied to Unit 1. Event and logic gate descriptions within these new trees were then changed to reflect the appropriate Unit 2 equipment identifiers. The Rev. 2.0 PRA model was then produced by linking the Unit 1 and new Unit 2 logic models together to support more efficient analysis of equipment and operator failures t hat impact risk on both units. | ||
The following lists break down the changes listed in Section F.2.1.2.4 of the ER into those made to produce the Unit 1 portion of the Rev. | The following lists break down the changes listed in Section F.2.1.2.4 of the ER into those made to produce the Unit 1 portion of the Rev. | ||
2.0 model and those made to produce the Unit 2 portion of the Rev. 2.0 model: | |||
and those made to produce the Unit 2 portion of the Rev. 2.0 model: | |||
Changes Made to the Unit 1 Rev. | Changes Made to the Unit 1 Rev. | ||
1.2 Model to Obtain Unit 1, Rev. 2.0 (Interim) Model Removal of the boric acid storage tank (BAST) input to the safety injection (SI) pumps suction logic. The primary suction supply is now only the refueling water storage tank (RWST). Enhancement of the existing quantification methodology, in cluding incorporation of fault tree-based deletion of mutually exclus ive events, including multiple initiating events. Modification to the charging pump system f ault tree logic to include an operator action to restart the pumps after a LOOP event si nce they are not included in the sequencer logic. Use of the same common cause failure (CCF) event for the residual heat removal (RHR) pump discharge check valves in the injection, recirculation, and shutdown cooling modes. A new operator action to prevent load sequenc er failure due to loss of cooling to the 4kV safeguards bus rooms (Bus 15, Bus 16, Bus 25, and Bus 26 rooms) was incorporated into the model. | |||
to Obtain Unit 1, Rev. 2.0 (Interim) Model Removal of the boric acid storage tank (BAST) input to the safety injection (SI) pumps suction logic. The primary suction supply is now only the refueling water storage tank (RWST). Enhancement of the existing quantification methodology, in cluding incorporation of fault tree-based deletion of mutually exclus ive events, including multiple initiating events. Modification to the charging pump system f ault tree logic to include an operator action to restart the pumps after a LOOP event si nce they are not included in the sequencer logic. Use of the same common cause failure (CCF) event for the residual heat removal (RHR) pump discharge check valves in the injection, recirculation, and shutdown cooling modes. A new operator action to prevent load sequenc er failure due to loss of cooling to the 4kV safeguards bus rooms (Bus 15, Bus 16, Bus 25, and Bus 26 rooms) was incorporated into the model. | |||
In conjunction with this change, a factor for the sequencer failure at elevated temperatures was added to the fault tree logic for the safeguards bus. Update to the logic modeling for the supply/ | In conjunction with this change, a factor for the sequencer failure at elevated temperatures was added to the fault tree logic for the safeguards bus. Update to the logic modeling for the supply/ | ||
exhaust fans 21, 22, 23, 24 which supply air to the Unit 2 safeguards bus rooms. T he original modeling a ssumed that none of the fans were running (but one train is normally running). This modeling change assumed supply/exhaust fan sets 21 and 22 are normally running and supply/exhaust 23 and 24 are in standby. Therefor e, the failure to start logi c was only included for sets 23 and 24. The CCF to start basic events (BEs) for all four sets was removed from the model. An incorrect and non-conservative mutually exclusive event related to the Screenhouse Flood Zone 2 Initiating event (I-SH2FLD) was remo ved from the logic. This resulted in an increase in the contribution of the Sc reenhouse Flood Zone 2 (SH2FLD) event to the overall results. | exhaust fans 21, 22, 23, 24 which supply air to the Unit 2 safeguards bus rooms. T he original modeling a ssumed that none of the fans were running (but one train is normally running). This modeling change assumed supply/exhaust fan sets 21 and 22 are normally running and supply/exhaust 23 and 24 are in standby. Therefor e, the failure to start logi c was only included for sets 23 and 24. The CCF to start basic events (BEs) for all four sets was removed from the model. An incorrect and non-conservative mutually exclusive event related to the Screenhouse Flood Zone 2 Initiating event (I-SH2FLD) was remo ved from the logic. This resulted in an increase in the contribution of the Sc reenhouse Flood Zone 2 (SH2FLD) event to the overall results. | ||
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Failure of this action will also result in flooding beyond the CC pumps, impacting both trains of Safety Injection (S I) pumps, Residual Heat Removal (RHR) pumps, and Containment Sp ray (CS) pumps, as well as motor control centers (MCCs) supporting the Charging pumps and other safeguards equipment. The core damage sequence involves occurrence of the flooding initiating event followed by failure of the operators to isolate the break prior to loss of the second tr ain of Component Cooling (CC) pumps. This results in loss of reactor coolant pump (RCP) seal cooling, which eventually leads to an unrecoverable RCP seal LOCA as the ECCS pumps have been impacted by the flooding event. For both units, about 97% of the contribution to CDF from internal flooding involves events initiated by flooding of the 695' elevation of the Auxiliary Building (as described above). | Failure of this action will also result in flooding beyond the CC pumps, impacting both trains of Safety Injection (S I) pumps, Residual Heat Removal (RHR) pumps, and Containment Sp ray (CS) pumps, as well as motor control centers (MCCs) supporting the Charging pumps and other safeguards equipment. The core damage sequence involves occurrence of the flooding initiating event followed by failure of the operators to isolate the break prior to loss of the second tr ain of Component Cooling (CC) pumps. This results in loss of reactor coolant pump (RCP) seal cooling, which eventually leads to an unrecoverable RCP seal LOCA as the ECCS pumps have been impacted by the flooding event. For both units, about 97% of the contribution to CDF from internal flooding involves events initiated by flooding of the 695' elevation of the Auxiliary Building (as described above). | ||
The dominant internal flooding containment failure sequence involves the core damage scenario described above. Core damage occurs at high reactor pressure in this sequence. | The dominant internal flooding containment failure sequence involves the core damage scenario described above. Core damage occurs at high reactor pressure in this sequence. | ||
In-vessel recovery due to submergence of the lowe r reactor vessel head (by filling the reactor cavity) is not successful as all means of pum ping the RWST water into containment, including the CS pumps, have been impacted by the flooding in the Auxiliar y Building. Hot leg creep rupture occurs prior to vessel failure in this sequence, allowing the core debris to exit the vessel at low pressure. As the debris in t he cavity cannot be cooled, containment failure occurs due to basemat failure. This is consi dered a late containment failure mode. For both units, essentially all of the contribution to cont ainment failure release categories from internal flooding involves events initiated by flooding of the 695' elevation of the Auxiliary Building. Responses to NRC Requests for Additional Information Dated October 23, 2008 14 RAI SAMA 2.a Provide the following information relative to the Level 2 PRA analysis: | In-vessel recovery due to submergence of the lowe r reactor vessel head (by filling the reactor cavity) is not successful as all means of pum ping the RWST water into containment, including the CS pumps, have been impacted by the flooding in the Auxiliar y Building. Hot leg creep rupture occurs prior to vessel failure in this sequence, allowing the core debris to exit the vessel at low pressure. As the debris in t he cavity cannot be cooled, containment failure occurs due to basemat failure. This is consi dered a late containment failure mode. For both units, essentially all of the contribution to cont ainment failure release categories from internal flooding involves events initiated by flooding of the 695' elevation of the Auxiliary Building. Responses to NRC Requests for Additional Information Dated October 23, 2008 14 RAI SAMA 2.a Provide the following information relative to the Level 2 PRA analysis: | ||
: a. Describe the modeled risk benefit achieved fr om the removal of procedural guidance to operator initiation of containment spray recirculation as discussed in Section F.2.1.3.1. | : a. Describe the modeled risk benefit achieved fr om the removal of procedural guidance to operator initiation of containment spray recirculation as discussed in Section F.2.1.3.1. | ||
NSPM Response to RAI SAMA 2.a Credit for operation of the containment spray (CS) system in recirculation mode was removed in the Unit 1 Level 2 Revision 1 (1L2R1) analysi s so that the PRA model would reflect the as-built, as-operated plant. As described in Section F.2.1.3.1 of the ER, th e decision to make the procedure change was made based on t he results of licensing-basis calculations. There was no risk benefit realized as a resu lt of the procedure change. A specific sensitivity study to identify the significance of this change was not performed for the 1L2R1 model; however it could have had only a very small impact (risk in crease) on the overall results of the 1L2R1 analysis. The availability of t he spray recirculation function does not impact the CDF or LERF metrics for either unit. | NSPM Response to RAI SAMA 2.a Credit for operation of the containment spray (CS) system in recirculation mode was removed in the Unit 1 Level 2 Revision 1 (1L2R1) analysi s so that the PRA model would reflect the as-built, as-operated plant. As described in Section F.2.1.3.1 of the ER, th e decision to make the procedure change was made based on t he results of licensing-basis calculations. There was no risk benefit realized as a resu lt of the procedure change. A specific sensitivity study to identify the significance of this change was not performed for the 1L2R1 model; however it could have had only a very small impact (risk in crease) on the overall results of the 1L2R1 analysis. The availability of t he spray recirculation function does not impact the CDF or LERF metrics for either unit. | ||
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The PINGP Severe Accident Management Gui des (SAMGs) now specify use of CS recirculation (CSR) in the event of containm ent challenge post-core damage. Therefore, credit for the containment spray recirculation function was re-instituted in Level 2 Revision 2 (L2R2) SAMA update. A sensitiv ity study was performed for that model update to investigate the risk benefit of this function based on the current model. To perform the sensitivity case, the CSR function was set to TRUE (failed) in the modeling, and a full re-quantification of the model was performed. Compared to the baseline Level 2 results (provided in Sections F.2.3, F.2.4 and Figures F.2-5 and F.2-6), quantification of the CSR sens itivity case for both units produced very little change in the overall quantificat ion results, with only a slight (<1%) shift from the 1H-XX-X [2H-XX-X] release category to the 1H-DH-L [2H-DH-L] release category. | The PINGP Severe Accident Management Gui des (SAMGs) now specify use of CS recirculation (CSR) in the event of containm ent challenge post-core damage. Therefore, credit for the containment spray recirculation function was re-instituted in Level 2 Revision 2 (L2R2) SAMA update. A sensitiv ity study was performed for that model update to investigate the risk benefit of this function based on the current model. To perform the sensitivity case, the CSR function was set to TRUE (failed) in the modeling, and a full re-quantification of the model was performed. Compared to the baseline Level 2 results (provided in Sections F.2.3, F.2.4 and Figures F.2-5 and F.2-6), quantification of the CSR sens itivity case for both units produced very little change in the overall quantificat ion results, with only a slight (<1%) shift from the 1H-XX-X [2H-XX-X] release category to the 1H-DH-L [2H-DH-L] release category. | ||
This shift was due to an increase in core damage sequences leading to vessel failure at high RCS pressure (typically small LOCA with operator failures to cool down and depressurize the RCS and then to switch to recirculation) in which the containment fails on overpressure without the containment spray system capabl e of operating in recirculation mode. | This shift was due to an increase in core damage sequences leading to vessel failure at high RCS pressure (typically small LOCA with operator failures to cool down and depressurize the RCS and then to switch to recirculation) in which the containment fails on overpressure without the containment spray system capabl e of operating in recirculation mode. | ||
Responses to NRC Requests for Additional Information Dated October 23, 2008 15 RAI SAMA 2.b | Responses to NRC Requests for Additional Information Dated October 23, 2008 15 RAI SAMA 2.b | ||
: b. It appears that treatment of induced-steam generator tube rupture (SGTR) events was eliminated in Revision 1. | : b. It appears that treatment of induced-steam generator tube rupture (SGTR) events was eliminated in Revision 1. | ||
0 of the Level 2 PRA (per ER Sect ion F.2.1.3.1) but reintroduced in Revision 2.2 SAMA of the Level 2 PRA (per ER Sections F.2.3. | 0 of the Level 2 PRA (per ER Sect ion F.2.1.3.1) but reintroduced in Revision 2.2 SAMA of the Level 2 PRA (per ER Sections F.2.3. | ||
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and NUREG-1570 values, or are closer to the NUREG-1150 values. In one case (TI-SGTR, intact loop seal, both SGs depressurized), the WCAP value is higher than the NUREG-1570 value. | and NUREG-1570 values, or are closer to the NUREG-1150 values. In one case (TI-SGTR, intact loop seal, both SGs depressurized), the WCAP value is higher than the NUREG-1570 value. | ||
RAI SAMA 2.c | RAI SAMA 2.c | ||
: c. State the version of the modular accident analysis program (MAAP) code used for the SAMA analysis, and the PRA version in which the MAAP cases were last updated. | : c. State the version of the modular accident analysis program (MAAP) code used for the SAMA analysis, and the PRA version in which the MAAP cases were last updated. | ||
NSPM Response to RAI SAMA 2.c The version of the MAAP code used for t he SAMA analysis was MAAP 3.0B. The MAAP cases were those originally performed for the IPE analysis. | NSPM Response to RAI SAMA 2.c The version of the MAAP code used for t he SAMA analysis was MAAP 3.0B. The MAAP cases were those originally performed for the IPE analysis. | ||
Responses to NRC Requests for Additional Information Dated October 23, 2008 18 RAI SAMA 3.a Provide the following information regarding the tr eatment of external events in the SAMA analysis: | Responses to NRC Requests for Additional Information Dated October 23, 2008 18 RAI SAMA 3.a Provide the following information regarding the tr eatment of external events in the SAMA analysis: | ||
: a. Provide a summary of the dominant fire scenarios for the individua l plant examination of external events (IPEEE) fire model in terms of overall fire frequency, plant initiator, and structures, systems, and com ponents (SSCs) impacted. De monstrate for each fire scenario that no viable SAMA candidat es exist to reduce fire risk. | : a. Provide a summary of the dominant fire scenarios for the individua l plant examination of external events (IPEEE) fire model in terms of overall fire frequency, plant initiator, and structures, systems, and com ponents (SSCs) impacted. De monstrate for each fire scenario that no viable SAMA candidat es exist to reduce fire risk. | ||
NSPM Response to RAI SAMA 3.a A complete discussion of dominant fire scenarios for the IPEEE Fire risk analysis, including the requested information on frequency, initiato r and SSCs impacted, is provided in the IPEEE Rev. 1, Section B.1.4, and supporting table B.2.11.1. | NSPM Response to RAI SAMA 3.a A complete discussion of dominant fire scenarios for the IPEEE Fire risk analysis, including the requested information on frequency, initiato r and SSCs impacted, is provided in the IPEEE Rev. 1, Section B.1.4, and supporting table B.2.11.1. | ||
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Refer to Section F.5.1.6 of the ER for a di scussion of how the recommendations developed from the IPEEE insights were dispositioned. | Refer to Section F.5.1.6 of the ER for a di scussion of how the recommendations developed from the IPEEE insights were dispositioned. | ||
RAI SAMA 3.b | RAI SAMA 3.b | ||
: b. ER Section F.5.1.8 indica tes that the maximum averted cost-risk (MACR) for internal events was doubled to account for external ev ents contributions. However, ER Section F.5.1.7.2 indicates that the IPEEE fire CDF is about 5E-5 per year, which is approximately five times the internal event CDF. (This value is stated as being conservative in part due to not crediting automatic and manual fire suppression.) | : b. ER Section F.5.1.8 indica tes that the maximum averted cost-risk (MACR) for internal events was doubled to account for external ev ents contributions. However, ER Section F.5.1.7.2 indicates that the IPEEE fire CDF is about 5E-5 per year, which is approximately five times the internal event CDF. (This value is stated as being conservative in part due to not crediting automatic and manual fire suppression.) | ||
Furthermore, in a July 21, 2006, request for addi tional information (RAI) response related to an extension of the containment integrated leakage rate test (ML062060033), Nuclear Management Company, LLC estimated the seismic CDF for Prairie Island Nuclear Generating Plant (PINGP) to be 7.82E-6 per year. Provide additi onal justification for use of a multiplier of 2 given that the fire CDF is approximately five times the current internal events CDF, that credit for automatic and m anual fire suppression has been included for many of the dominant fire sequences, and that seismic and other external events also contribute to the total CDF. | Furthermore, in a July 21, 2006, request for addi tional information (RAI) response related to an extension of the containment integrated leakage rate test (ML062060033), Nuclear Management Company, LLC estimated the seismic CDF for Prairie Island Nuclear Generating Plant (PINGP) to be 7.82E-6 per year. Provide additi onal justification for use of a multiplier of 2 given that the fire CDF is approximately five times the current internal events CDF, that credit for automatic and m anual fire suppression has been included for many of the dominant fire sequences, and that seismic and other external events also contribute to the total CDF. | ||
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o Except for fires in the G-panel, small c ontrol room panel fires (those that are not large enough to propagate outside the control board zone in which they initiate) are assumed to cause the loss of all equipment within that panel zone. No credit for cable separation to allow partitioning of these cabinet fires further was given. | o Except for fires in the G-panel, small c ontrol room panel fires (those that are not large enough to propagate outside the control board zone in which they initiate) are assumed to cause the loss of all equipment within that panel zone. No credit for cable separation to allow partitioning of these cabinet fires further was given. | ||
o CRM Panel Zones 5, 6 fires (LOFW/AFW) | o CRM Panel Zones 5, 6 fires (LOFW/AFW) | ||
(~40% of total fire IPEEE CDF, almost 2E-5/yr) | (~40% of total fire IPEEE CDF, almost 2E-5/yr) | ||
Almost all sequences include failure of B&F or recirculation ANY size fire results in loss of entire cabinet (in this case, loss of all main FW and AFW). Local recovery of AFW was not credit ed, nor was any other means of feeding the SGs (see responses to RAI questions 8.a, 8.b, and 8.c). ANY size Panel Zone 6 fire was assumed to result in spurious actuation (open) of the SG PORVs, resulting in an MSLB-like plant response (including Instrument Air (IA) to containment valve auto-closure). This requires the operator to re-open IA to c ontainment isolation valves in order to prevent B&F failure (see conservative IA passive a ccumulator treatment described above). Responses to NRC Requests for Additional Information Dated October 23, 2008 25 o CRM Panel fires (LOOP/SBO) (~11% of total fire IPEEE CDF, >5E-6/yr) ANY size fire results in loss of at l east one train of offsite and onsite AC power to safeguards equipment. | Almost all sequences include failure of B&F or recirculation ANY size fire results in loss of entire cabinet (in this case, loss of all main FW and AFW). Local recovery of AFW was not credit ed, nor was any other means of feeding the SGs (see responses to RAI questions 8.a, 8.b, and 8.c). ANY size Panel Zone 6 fire was assumed to result in spurious actuation (open) of the SG PORVs, resulting in an MSLB-like plant response (including Instrument Air (IA) to containment valve auto-closure). This requires the operator to re-open IA to c ontainment isolation valves in order to prevent B&F failure (see conservative IA passive a ccumulator treatment described above). Responses to NRC Requests for Additional Information Dated October 23, 2008 25 o CRM Panel fires (LOOP/SBO) (~11% of total fire IPEEE CDF, >5E-6/yr) ANY size fire results in loss of at l east one train of offsite and onsite AC power to safeguards equipment. | ||
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Based on the above considerations for internal fires, seismic events, and other external events, the (x2) multiplier was chosen in calc ulating the value for the Modified Maximum Averted Cost Risk (MMACR). No higher multiplier is believed to be warranted given the current state of knowledge regardi ng external events at PINGP. | Based on the above considerations for internal fires, seismic events, and other external events, the (x2) multiplier was chosen in calc ulating the value for the Modified Maximum Averted Cost Risk (MMACR). No higher multiplier is believed to be warranted given the current state of knowledge regardi ng external events at PINGP. | ||
RAI SAMA 3.c | RAI SAMA 3.c | ||
: c. As stated in the IPEEE seismic analysis, several potential seismic outliers were dispositioned through an analysis process wh ich determined that the impacted function was not required or could be recovered, or that an alternate means for performing the associated function was available. For those outliers identified in IPEEE Section A.2.4.1.2, where recovery or an alternate means is credited, demonstrate that enhancing the ruggedness of the associated co mponents is not cost-beneficial. The outliers include: | : c. As stated in the IPEEE seismic analysis, several potential seismic outliers were dispositioned through an analysis process wh ich determined that the impacted function was not required or could be recovered, or that an alternate means for performing the associated function was available. For those outliers identified in IPEEE Section A.2.4.1.2, where recovery or an alternate means is credited, demonstrate that enhancing the ruggedness of the associated co mponents is not cost-beneficial. The outliers include: | ||
turbine-driven AFW pump trip and throttle va lves (recovered), diesel generator fuel oil storage tanks 122 and 124 (alternative tanks avai lable), the boric acid transfer pumps (alternate supply available), charging pum ps 12 and 23 (alternative charging pumps available), panel 117 (alternate power norma lly available), cooling water pump 121 (alternate pumps available), condensate storage tanks 11, 12 and 13 (recovered through the use of alternate sources (e.g., cooling water)), component cooling water pressure switches (alternate start signal available), and diesel-driven cooling water pump pressure switches (alternative start signal available). | turbine-driven AFW pump trip and throttle va lves (recovered), diesel generator fuel oil storage tanks 122 and 124 (alternative tanks avai lable), the boric acid transfer pumps (alternate supply available), charging pum ps 12 and 23 (alternative charging pumps available), panel 117 (alternate power norma lly available), cooling water pump 121 (alternate pumps available), condensate storage tanks 11, 12 and 13 (recovered through the use of alternate sources (e.g., cooling water)), component cooling water pressure switches (alternate start signal available), and diesel-driven cooling water pump pressure switches (alternative start signal available). | ||
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Per the work completed as described above, all out liers identified in Sect ion A.2.4.1.1 of the Prairie Island IPEEE have been resolved. Aside from work completed, no additional procedure changes or training was requi red to close identified outliers. | Per the work completed as described above, all out liers identified in Sect ion A.2.4.1.1 of the Prairie Island IPEEE have been resolved. Aside from work completed, no additional procedure changes or training was requi red to close identified outliers. | ||
RAI SAMA 3.d | RAI SAMA 3.d | ||
: d. Discuss the results of the seismic IPEEE fr om the standpoint of po tential SAMAs for the SSCs with the lowest seismic margins, and provide an assessment of whether any SAMAs to increase the seismic capacity of these limiting components woul d be cost beneficial (i.e., improvements to the component cool water heat exchanger anchorage). | : d. Discuss the results of the seismic IPEEE fr om the standpoint of po tential SAMAs for the SSCs with the lowest seismic margins, and provide an assessment of whether any SAMAs to increase the seismic capacity of these limiting components woul d be cost beneficial (i.e., improvements to the component cool water heat exchanger anchorage). | ||
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In some past SAMA evaluations, the MACCS2 Samp le Problem A core inventory values were utilized in lieu of plant specific core inventories. For those studies, the MACCS2 Sample Problem A core inventories were adjusted by us ing a ratio to account for differences between the Sample Problem A core power level and the SAMA plant specific power level. It has become recognized that in addition to differences in core power levels, changes in fuel enrichment and core exposure between current industry practices and those assumed for Sample Problem A should be accounted for via a plant specific core inventory. | In some past SAMA evaluations, the MACCS2 Samp le Problem A core inventory values were utilized in lieu of plant specific core inventories. For those studies, the MACCS2 Sample Problem A core inventories were adjusted by us ing a ratio to account for differences between the Sample Problem A core power level and the SAMA plant specific power level. It has become recognized that in addition to differences in core power levels, changes in fuel enrichment and core exposure between current industry practices and those assumed for Sample Problem A should be accounted for via a plant specific core inventory. | ||
Since a Prairie Island plant specific core invent ory for 40 of the 60 nuclid es was not available, plant specific values for the 40 nuclides were estimated in the following manner: | Since a Prairie Island plant specific core invent ory for 40 of the 60 nuclid es was not available, plant specific values for the 40 nuclides were estimated in the following manner: | ||
: 1. The 60 MACCS2 Sample Problem A core inv entory values were adjusted to account for differences between the Sample Problem A power level of 3412 MW th and the Prairie Island power level of 1650 MW th. 2. For each of the 20 nuclide values cont ained in the USAR, a comparison was made between the USAR value and the adjusted Sample Problem A value. The difference between the USAR nuclide val ue and the adjusted Sample Pr oblem A value differed for each nuclide. 3. The average change between the USAR values and the adjusted Sample Problem A values was calculated for these 20 nuclide values. On average, the USAR nuclide values were approximately 39 percent hi gher than the adjusted Sample Problem A values. 4. This factor of 1.39 was then applied to the 40 adjusted Sample Problem A values to estimate the plant specific core inventory of these 40 nuclides. | : 1. The 60 MACCS2 Sample Problem A core inv entory values were adjusted to account for differences between the Sample Problem A power level of 3412 MW th and the Prairie Island power level of 1650 MW th. 2. For each of the 20 nuclide values cont ained in the USAR, a comparison was made between the USAR value and the adjusted Sample Problem A value. The difference between the USAR nuclide val ue and the adjusted Sample Pr oblem A value differed for each nuclide. 3. The average change between the USAR values and the adjusted Sample Problem A values was calculated for these 20 nuclide values. On average, the USAR nuclide values were approximately 39 percent hi gher than the adjusted Sample Problem A values. 4. This factor of 1.39 was then applied to the 40 adjusted Sample Problem A values to estimate the plant specific core inventory of these 40 nuclides. | ||
The increase factor of 1.39 t hat was applied to the 40 adjusted Sample Problem A values was judged to adequately estimate the impacts associat ed with fuel enrichment and core exposure between the Sample Problem A core assumpti ons and those utilized by Prairie Island. Responses to NRC Requests for Additional Information Dated October 23, 2008 37 Although the change in core average exposure and f uel burnup strategies that make use of newer and more efficient fuel designs will have an impact on the radioisotopic source term, specific operating strategies and power uprates planned for the futu re are not fully realized at present. To capture this and other inherent uncertainties that are part of the SAMA methodology, the use of the 95 th percentile averted cost risk re sults for each Phase 2 SAMA was used to determine whether a particu lar SAMA was cost beneficial. The 95 th percentile results were meant to provi de a "bounding" assessment to determine those SAMAs that may be cost beneficial and worthy of a more detailed analysis via the utility's action tracking process for plant modifications. | The increase factor of 1.39 t hat was applied to the 40 adjusted Sample Problem A values was judged to adequately estimate the impacts associat ed with fuel enrichment and core exposure between the Sample Problem A core assumpti ons and those utilized by Prairie Island. Responses to NRC Requests for Additional Information Dated October 23, 2008 37 Although the change in core average exposure and f uel burnup strategies that make use of newer and more efficient fuel designs will have an impact on the radioisotopic source term, specific operating strategies and power uprates planned for the futu re are not fully realized at present. To capture this and other inherent uncertainties that are part of the SAMA methodology, the use of the 95 th percentile averted cost risk re sults for each Phase 2 SAMA was used to determine whether a particu lar SAMA was cost beneficial. The 95 th percentile results were meant to provi de a "bounding" assessment to determine those SAMAs that may be cost beneficial and worthy of a more detailed analysis via the utility's action tracking process for plant modifications. | ||
Responses to NRC Requests for Additional Information Dated October 23, 2008 38 RAI SAMA 5.a Provide the following information with regard to the selection and screening of Phase I SAMA candidates: | Responses to NRC Requests for Additional Information Dated October 23, 2008 38 RAI SAMA 5.a Provide the following information with regard to the selection and screening of Phase I SAMA candidates: | ||
: a. The top two events in the Level 1 importance listing (ER Table F.5-1a) involve failure of operator actions (Events OSLOCAXXCDY and OHRECIRCC2Y, with failure probabilities 1.9E-02 and 5.3E-02, respecti vely). Potential improvement s to operator training are mentioned in the table, but dism issed on the basis that there is a great deal of uncertainty regarding the operator failure probability estimates. Despite the uncertainties, improvement to operator trai ning would appear to be a potentially cost-beneficial SAMA given the high importance of t hese operator actions for both CDF and large early release frequency. In this regard prov ide the following: (1) a descrip tion of the current procedural guidance and training scope and fr equency, (2) the bases for t he human error probability values, including the role that timing, ex perience/training, and procedures play in determining these values, (3) a characterizati on of the uncertainty associated with these actions and discussion of why their uncertain ty may be greater than other events in the PRA, and (4) an evaluation of the costs and benefits of improving the training and/or procedures for these actions. | : a. The top two events in the Level 1 importance listing (ER Table F.5-1a) involve failure of operator actions (Events OSLOCAXXCDY and OHRECIRCC2Y, with failure probabilities 1.9E-02 and 5.3E-02, respecti vely). Potential improvement s to operator training are mentioned in the table, but dism issed on the basis that there is a great deal of uncertainty regarding the operator failure probability estimates. Despite the uncertainties, improvement to operator trai ning would appear to be a potentially cost-beneficial SAMA given the high importance of t hese operator actions for both CDF and large early release frequency. In this regard prov ide the following: (1) a descrip tion of the current procedural guidance and training scope and fr equency, (2) the bases for t he human error probability values, including the role that timing, ex perience/training, and procedures play in determining these values, (3) a characterizati on of the uncertainty associated with these actions and discussion of why their uncertain ty may be greater than other events in the PRA, and (4) an evaluation of the costs and benefits of improving the training and/or procedures for these actions. | ||
NSPM Response to RAI SAMA 5.a A summary of the operator actions is listed below: | NSPM Response to RAI SAMA 5.a A summary of the operator actions is listed below: | ||
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Although additional training wo uld not provide benefit, the im portant PRA information is transmitted to the Training Depar tment to be incorporated into the Prairie Island Training Center procedure which provides instructions and guidance for using PRA information in operator training programs. Spec ifically, PRA insights are used in the classroom training and in the development of simulato r training and evaluation. The procedure identifies the top two operator actions for both units as 0SLOCAXXCDY and 0HRECIRCC2Y. | Although additional training wo uld not provide benefit, the im portant PRA information is transmitted to the Training Depar tment to be incorporated into the Prairie Island Training Center procedure which provides instructions and guidance for using PRA information in operator training programs. Spec ifically, PRA insights are used in the classroom training and in the development of simulato r training and evaluation. The procedure identifies the top two operator actions for both units as 0SLOCAXXCDY and 0HRECIRCC2Y. | ||
RAI SAMA 5.b | RAI SAMA 5.b | ||
: b. ER Section F.5.1.5 indicates that two internal flood rela ted enhancements identified in the individual plant examination (Items 2 and 3 on page F.5-5) were implemented through piping modifications, design features, and periodic inspections, as described in Calculation ENG-ME-148, Rev. 1. The thrust of the argument appears to be that this has rendered the probability of cooling water system header rupture negligible. Provide a copy of this calculation/white paper. Justify that the potential enhancements would not be warranted given the dominant contributors to internal flooding CDF, as described in response to RAI 1.h. | : b. ER Section F.5.1.5 indicates that two internal flood rela ted enhancements identified in the individual plant examination (Items 2 and 3 on page F.5-5) were implemented through piping modifications, design features, and periodic inspections, as described in Calculation ENG-ME-148, Rev. 1. The thrust of the argument appears to be that this has rendered the probability of cooling water system header rupture negligible. Provide a copy of this calculation/white paper. Justify that the potential enhancements would not be warranted given the dominant contributors to internal flooding CDF, as described in response to RAI 1.h. | ||
NSPM Response to RAI SAMA 5.b A copy of ENG-ME-148, Revision 1, is included as . The objective of this paper is to document the qualifications, design featur es and periodic inspections in place which provide confidence that the probability of occurrence of a pipe rupture (double-ended guillotine break) is negligible. The break pos tulation is reviewed from a deterministic standpoint and is based on current Prairie Island lic ensing basis, plant material condition, and other factors. | NSPM Response to RAI SAMA 5.b A copy of ENG-ME-148, Revision 1, is included as . The objective of this paper is to document the qualifications, design featur es and periodic inspections in place which provide confidence that the probability of occurrence of a pipe rupture (double-ended guillotine break) is negligible. The break pos tulation is reviewed from a deterministic standpoint and is based on current Prairie Island lic ensing basis, plant material condition, and other factors. | ||
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5, the IPE identified two inte rnal flood enhancements (Items 2 and 3 on page F.5-5). These enhancements are related to flooding in the Auxiliary Feedwater (AFW) Pump Room due to the CL header pipe break. However (as reflected in the response to RAI Question 1.h), AFW Pump Room flooding is no longer a significant contributor to the PRA results. Therefore, potential enhancements would not be warranted. | 5, the IPE identified two inte rnal flood enhancements (Items 2 and 3 on page F.5-5). These enhancements are related to flooding in the Auxiliary Feedwater (AFW) Pump Room due to the CL header pipe break. However (as reflected in the response to RAI Question 1.h), AFW Pump Room flooding is no longer a significant contributor to the PRA results. Therefore, potential enhancements would not be warranted. | ||
RAI SAMA 5.c | RAI SAMA 5.c | ||
: c. ER Section F.5.1.7. | : c. ER Section F.5.1.7. | ||
1 states that a recommendation from the seismic margins analysis was to restrain or remove wall hung ladders and scaffolding. Describe the actions taken in response to this recommendation. | 1 states that a recommendation from the seismic margins analysis was to restrain or remove wall hung ladders and scaffolding. Describe the actions taken in response to this recommendation. | ||
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During a recent field walkdown, it was noted that ladders are still located near safety-related equipment such as 4160 VAC Bus 25 and D2. T he ladders are stored on plant storage racks per procedure; however, it was questioned whether additional re straints were warranted to secure the ladders. Investigation determined that there was no clear guidance for the location and construction of ladder storage. The conditi on has been entered into the corrective action program to further investi gate the issue and determine whet her current ladder storage standards are adequate. | During a recent field walkdown, it was noted that ladders are still located near safety-related equipment such as 4160 VAC Bus 25 and D2. T he ladders are stored on plant storage racks per procedure; however, it was questioned whether additional re straints were warranted to secure the ladders. Investigation determined that there was no clear guidance for the location and construction of ladder storage. The conditi on has been entered into the corrective action program to further investi gate the issue and determine whet her current ladder storage standards are adequate. | ||
RAI SAMA 5.d | RAI SAMA 5.d | ||
: d. ER Section 4.17.1 identif ies five criteria for screening out Phase I SAMA candidates, whereas ER Section F.5.2 identifies two such criteria, one of which involves the use of engineering judgment and expect ed maximum cost and dose benefits. Clarify which criteria were actually used in the SAMA screening process. | : d. ER Section 4.17.1 identif ies five criteria for screening out Phase I SAMA candidates, whereas ER Section F.5.2 identifies two such criteria, one of which involves the use of engineering judgment and expect ed maximum cost and dose benefits. Clarify which criteria were actually used in the SAMA screening process. | ||
NSPM Response to RAI SAMA 5.d Although the screening criteria listed may appear to be different between the two documents, they are meant to be equivalent with similar intent. Also, even though a particular screening criterion was listed, it does not imply that it was necessarily utilized, since it may not have been necessary or applicable. The following table attempts to resolve the apparent discrepancy between the two sections by showing their similarity. Responses to NRC Requests for Additional Information Dated October 23, 2008 43 ER Section F.5.2 ER Section 4.17.1 Applicability to the Plant: If a proposed SAMA does not apply to the Prairi e Island design, it is not retained. (1) Candidates not applicable to the PINGP design Engineering Judgment: Us ing extensive plant knowledge and sound engi neering judgment, potential SAMAs are evaluated based on their | NSPM Response to RAI SAMA 5.d Although the screening criteria listed may appear to be different between the two documents, they are meant to be equivalent with similar intent. Also, even though a particular screening criterion was listed, it does not imply that it was necessarily utilized, since it may not have been necessary or applicable. The following table attempts to resolve the apparent discrepancy between the two sections by showing their similarity. Responses to NRC Requests for Additional Information Dated October 23, 2008 43 ER Section F.5.2 ER Section 4.17.1 Applicability to the Plant: If a proposed SAMA does not apply to the Prairi e Island design, it is not retained. (1) Candidates not applicable to the PINGP design Engineering Judgment: Us ing extensive plant knowledge and sound engi neering judgment, potential SAMAs are evaluated based on their | ||
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SAMA candidate if the option has already been, or is planned to be, implemented, e.g., planned | SAMA candidate if the option has already been, or is planned to be, implemented, e.g., planned | ||
replacement of steam generators on Unit 2. | replacement of steam generators on Unit 2. | ||
(3) Candidates that have already been implemented at PINGP Table F.5-3 discusses the various SAMA options, and as applicable, recommends the | (3) Candidates that have already been implemented at PINGP Table F.5-3 discusses the various SAMA options, and as applicable, recommends the | ||
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effective, e.g., SAMA 18 was dispositioned by | effective, e.g., SAMA 18 was dispositioned by | ||
recommending the use of SAMA 15. | recommending the use of SAMA 15. | ||
(4) Candidates with benefits that have been achieved using other | (4) Candidates with benefits that have been achieved using other | ||
means RAI SAMA 5.e | means RAI SAMA 5.e | ||
: e. For each screened Phase I SAMA candidate (i.e., SAMAs 1, 6, 6a, 7, 8, 10, 11, 13, 14, 16, 17, 18, 19a, 21, 23, 24) ident ify the criteria used to scr een the SAMA. If engineering judgment was used as the criter ia (as opposed to the criter ia provided in ER Section 4.17.1), provide the estimated cost and dose benefit values used in the screening decision for each SAMA, as well as the basis for the engineering judgment decision. | : e. For each screened Phase I SAMA candidate (i.e., SAMAs 1, 6, 6a, 7, 8, 10, 11, 13, 14, 16, 17, 18, 19a, 21, 23, 24) ident ify the criteria used to scr een the SAMA. If engineering judgment was used as the criter ia (as opposed to the criter ia provided in ER Section 4.17.1), provide the estimated cost and dose benefit values used in the screening decision for each SAMA, as well as the basis for the engineering judgment decision. | ||
NSPM Response to RAI SAMA 5.e ER Table F.5-3 provides a description of how each SAMA was dispositioned in Phase I. | NSPM Response to RAI SAMA 5.e ER Table F.5-3 provides a description of how each SAMA was dispositioned in Phase I. | ||
Those SAMAs that required a mo re detailed cost-benefit analysi s were evaluated in Section F.6. Also see the response for RAI 5.f below. | Those SAMAs that required a mo re detailed cost-benefit analysi s were evaluated in Section F.6. Also see the response for RAI 5.f below. | ||
RAI SAMA 5.f | RAI SAMA 5.f | ||
: f. ER Section F.7.2.1 identifies five Phase 1 SAMAs that were origin ally screened out but subsequently screened in and further evaluated as a result of an uncertainty assessment (i.e., SAMAs 1, 10, 17, 19a, and 21). Describe the process and criter ia used to identify these five SAMAs. Explain why an uncertain ty evaluation for the remaining 11 screened out SAMAs is not appropriate. | : f. ER Section F.7.2.1 identifies five Phase 1 SAMAs that were origin ally screened out but subsequently screened in and further evaluated as a result of an uncertainty assessment (i.e., SAMAs 1, 10, 17, 19a, and 21). Describe the process and criter ia used to identify these five SAMAs. Explain why an uncertain ty evaluation for the remaining 11 screened out SAMAs is not appropriate. | ||
NSPM Response to RAI SAMA 5.f This response addresses both RAIs 5.e and 5.f: Responses to NRC Requests for Additional Information Dated October 23, 2008 44 Four of the five Phase 1 SAMAs (1, 10, 17, and 19a) were originally carried forward into the Phase 2 evaluation based on prel iminary implementatio n costs, but later refined estimates clearly made them not cost beneficial when compared with other Phase 1 SAMAs that were dispositioned as being too costly. Nonetheless, it was decided to retain their analysis by including them as a sensitivity calculation ra ther than delete the earlie r Phase 2 work. SAMA 21, although not seen as cost-beneficial, was retained as a sensitivity calculation only as an exercise to see what possible averted cost benefits might be realized since the SAMA option was viewed to have a large impact on LERF. The other 11 screened out Phase 1 SAMAs | NSPM Response to RAI SAMA 5.f This response addresses both RAIs 5.e and 5.f: Responses to NRC Requests for Additional Information Dated October 23, 2008 44 Four of the five Phase 1 SAMAs (1, 10, 17, and 19a) were originally carried forward into the Phase 2 evaluation based on prel iminary implementatio n costs, but later refined estimates clearly made them not cost beneficial when compared with other Phase 1 SAMAs that were dispositioned as being too costly. Nonetheless, it was decided to retain their analysis by including them as a sensitivity calculation ra ther than delete the earlie r Phase 2 work. SAMA 21, although not seen as cost-beneficial, was retained as a sensitivity calculation only as an exercise to see what possible averted cost benefits might be realized since the SAMA option was viewed to have a large impact on LERF. The other 11 screened out Phase 1 SAMAs | ||
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SAMA Identifier License Renewal Section / Comments 1 Section F.7.2.1.1 6 Section F.5.2.1 6a Section F.5.2.2 7 Table F.5-3 8 Section F.5.2.3 10 Section F.7.2.1.2 11 Table F.5-3; SAMA 10 viewed as alternative to this SAMA 13 Section F.5.2.4 14 Table F.5-3 16 Table F.5-3 17 Section F.7.2.1.3 18 Table F.5-3; SAMA 15 viewed as alternative 19a Section F.7.2.1.4 21 Section F.7.2.1.5 23 Table F.5-3; SAMAs 5 and 19a viewed as alternatives 24 Table F.5-3; SAMAs 16, 17, 21, and 22 viewed as alternatives | SAMA Identifier License Renewal Section / Comments 1 Section F.7.2.1.1 6 Section F.5.2.1 6a Section F.5.2.2 7 Table F.5-3 8 Section F.5.2.3 10 Section F.7.2.1.2 11 Table F.5-3; SAMA 10 viewed as alternative to this SAMA 13 Section F.5.2.4 14 Table F.5-3 16 Table F.5-3 17 Section F.7.2.1.3 18 Table F.5-3; SAMA 15 viewed as alternative 19a Section F.7.2.1.4 21 Section F.7.2.1.5 23 Table F.5-3; SAMAs 5 and 19a viewed as alternatives 24 Table F.5-3; SAMAs 16, 17, 21, and 22 viewed as alternatives | ||
RAI SAMA 5.g | RAI SAMA 5.g | ||
: g. Provide additional description of the SAMA 6a barriers described in Section F.5.2.2 in order to better justify the cost estimate of $2M per unit. | : g. Provide additional description of the SAMA 6a barriers described in Section F.5.2.2 in order to better justify the cost estimate of $2M per unit. | ||
NSPM Response to RAI SAMA 5.g As shown in USAR Figure 1.1-5, the critical equipment in the scope of SAMA 6a is all located on the same floor elevation of the Auxiliary Building. The equi pment involved includes (for each unit) two SI pumps, two CC pumps, severa l motor control centers, three charging pumps, and two RHR pumps located in pits below the floor level. The equipment is not | NSPM Response to RAI SAMA 5.g As shown in USAR Figure 1.1-5, the critical equipment in the scope of SAMA 6a is all located on the same floor elevation of the Auxiliary Building. The equi pment involved includes (for each unit) two SI pumps, two CC pumps, severa l motor control centers, three charging pumps, and two RHR pumps located in pits below the floor level. The equipment is not | ||
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In view of these considerations, it is reasonable to conclude that the cost of design, fabrication and construction of each enclosure, costs associ ated with future removal and replacement of each enclosure for equipment maintenance, and cost s of maintaining the sealed joints in each enclosure water tight, could easily reach $200,000 each, or more than $2,000,000 per unit. | In view of these considerations, it is reasonable to conclude that the cost of design, fabrication and construction of each enclosure, costs associ ated with future removal and replacement of each enclosure for equipment maintenance, and cost s of maintaining the sealed joints in each enclosure water tight, could easily reach $200,000 each, or more than $2,000,000 per unit. | ||
Responses to NRC Requests for Additional Information Dated October 23, 2008 46 RAI SAMA 6.a Provide the following information with regard to the Phase II cost-b enefit evaluations: | Responses to NRC Requests for Additional Information Dated October 23, 2008 46 RAI SAMA 6.a Provide the following information with regard to the Phase II cost-b enefit evaluations: | ||
: a. ER Section F.6 states that the PINGP-specific implemen tation cost estimates do not account for replacement power costs that may be incurred due to consequential shutdown time. Clarify whether contingency costs or inflation adjustments are included in the cost estimates. Describe the types of costs that are included within the estimated "life cycle" costs. NSPM Response to RAI SAMA 6.a Cost estimates for potential plant modificati ons identified in the SAMA analysis have been developed as order-of-magnitude cost estimates. Contingency cost or inflation adjustments were not included in these estimates. Each cost estimate is broken down into relevant work activities across the following major project phases: Study, Analysis, Design, Implementation, and Life Cycle. | : a. ER Section F.6 states that the PINGP-specific implemen tation cost estimates do not account for replacement power costs that may be incurred due to consequential shutdown time. Clarify whether contingency costs or inflation adjustments are included in the cost estimates. Describe the types of costs that are included within the estimated "life cycle" costs. NSPM Response to RAI SAMA 6.a Cost estimates for potential plant modificati ons identified in the SAMA analysis have been developed as order-of-magnitude cost estimates. Contingency cost or inflation adjustments were not included in these estimates. Each cost estimate is broken down into relevant work activities across the following major project phases: Study, Analysis, Design, Implementation, and Life Cycle. | ||
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Estimates in the 'Life Cycle' phase accounts fo r labor and materials requ ired for maintaining plant equipment in operable condition for 20 years. Life cycle costs do not include any contingency or inflation adjustments. Life cy cle costs are costs related to ensuring the operability of the equipment. | Estimates in the 'Life Cycle' phase accounts fo r labor and materials requ ired for maintaining plant equipment in operable condition for 20 years. Life cycle costs do not include any contingency or inflation adjustments. Life cy cle costs are costs related to ensuring the operability of the equipment. | ||
Responses to NRC Requests for Additional Information Dated October 23, 2008 47 RAI SAMA 6.b | Responses to NRC Requests for Additional Information Dated October 23, 2008 47 RAI SAMA 6.b | ||
: b. For SAMA 2, ER Section F.6.1 indicates a $300K implement ation cost for each unit but provides no basis for this value. It appears t hat this SAMA would involve the upgrade of one site diesel-driven fire pump and the addition of the associated piping connections and starting circuitry. As such, the cost would be shared by each unit. | : b. For SAMA 2, ER Section F.6.1 indicates a $300K implement ation cost for each unit but provides no basis for this value. It appears t hat this SAMA would involve the upgrade of one site diesel-driven fire pump and the addition of the associated piping connections and starting circuitry. As such, the cost would be shared by each unit. | ||
Provide additional information regarding the basis for the cost estimates for this SAMA. | Provide additional information regarding the basis for the cost estimates for this SAMA. | ||
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$2.4 million between bot h units. The cost estimate is comparable to the cost of a similar installation at Palisades. This higher cost would screen this SAMA from being cost beneficial. | $2.4 million between bot h units. The cost estimate is comparable to the cost of a similar installation at Palisades. This higher cost would screen this SAMA from being cost beneficial. | ||
RAI SAMA 6.c | RAI SAMA 6.c | ||
: c. For SAMA 20, ER Table F.5-3 indicates a | : c. For SAMA 20, ER Table F.5-3 indicates a | ||
$313K implementation cost for each unit to change normally-open motor-operated valve to normally-closed, including a $100K "life cycle" cost. Describe the physical changes that are included in this cost estimate. | $313K implementation cost for each unit to change normally-open motor-operated valve to normally-closed, including a $100K "life cycle" cost. Describe the physical changes that are included in this cost estimate. | ||
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Civil $60,000 4 Contract Labor Engr Design - Elec / | Civil $60,000 4 Contract Labor Engr Design - Elec / | ||
I&C $60,000 5 PINGP Support Engr / Ops / Maint $40,000 Implement 6 Labor Maintenance / Construction $50,000 7 Contract Labor Engineering $2,000 8 Materials Material & Material Mgmt $1,000 9 PINGP Support Engr / Ops / Lic $3,000 Life Cycle 10 Labor Ops / Maint for 20 years $100,000 GRAND TOTAL $368,000 Note: This estimate is for one unit only. The cost estimate for the second unit would save approximately 30% on the Design Phase. Therefore, the total cost for the second unit is $258,000. The sum of the two costs is $626K, or an average of $313K per unit. | I&C $60,000 5 PINGP Support Engr / Ops / Maint $40,000 Implement 6 Labor Maintenance / Construction $50,000 7 Contract Labor Engineering $2,000 8 Materials Material & Material Mgmt $1,000 9 PINGP Support Engr / Ops / Lic $3,000 Life Cycle 10 Labor Ops / Maint for 20 years $100,000 GRAND TOTAL $368,000 Note: This estimate is for one unit only. The cost estimate for the second unit would save approximately 30% on the Design Phase. Therefore, the total cost for the second unit is $258,000. The sum of the two costs is $626K, or an average of $313K per unit. | ||
RAI SAMA 6.d | RAI SAMA 6.d | ||
: d. For SAMA 22, it is stated t hat the PRA model does not take fu ll credit for the ability of the power-operated relief valve (PORV) accumulators, because their ability to supply sufficient air to support bleed and feed operation over the full range of reactor coolant system break sizes has not been verified (through testing or through engineering calc ulations). Describe the credit that is taken for the ac cumulators in the current model. | : d. For SAMA 22, it is stated t hat the PRA model does not take fu ll credit for the ability of the power-operated relief valve (PORV) accumulators, because their ability to supply sufficient air to support bleed and feed operation over the full range of reactor coolant system break sizes has not been verified (through testing or through engineering calc ulations). Describe the credit that is taken for the ac cumulators in the current model. | ||
NSPM Response to RAI SAMA 6.d Basic events are included in the PRA to model t he failure probability of the air accumulators for the pressurizer PORV to be able to open t he valves for bleed and feed with the instrument air supply to the valves failed. The current failure probability is 0.1. | NSPM Response to RAI SAMA 6.d Basic events are included in the PRA to model t he failure probability of the air accumulators for the pressurizer PORV to be able to open t he valves for bleed and feed with the instrument air supply to the valves failed. The current failure probability is 0.1. | ||
Responses to NRC Requests for Additional Information Dated October 23, 2008 49 RAI SAMA 6.e | Responses to NRC Requests for Additional Information Dated October 23, 2008 49 RAI SAMA 6.e | ||
: e. In ER Sections 4.17 and F.4.6, the modified MACR (MMACR) is indicated to be $1,114,000 and $2,980,000 for Unit 1 and 2, respec tively. In ER Section F.7.1 it is indicated to be $1,048,000 and $2,706,000. Address this discrepancy. | : e. In ER Sections 4.17 and F.4.6, the modified MACR (MMACR) is indicated to be $1,114,000 and $2,980,000 for Unit 1 and 2, respec tively. In ER Section F.7.1 it is indicated to be $1,048,000 and $2,706,000. Address this discrepancy. | ||
NSPM Response to RAI SAMA 6.e The correct values are $1,114,000 and $2,980,000 for Unit 1 and 2, respectively. The values listed in Section F.7.1 are the result of typographical erro rs. The MMACR values had been modified based on updated information, but the older values within Section F.7.1 were inadvertently not corrected. Th is section dealt with adjusting the Real Discount Rate (RDR) value from 3% to 7%. The end result is that this typographical error does not change any of the results or conclusions for any of the SAMA analyses or sensitivity cases. | NSPM Response to RAI SAMA 6.e The correct values are $1,114,000 and $2,980,000 for Unit 1 and 2, respectively. The values listed in Section F.7.1 are the result of typographical erro rs. The MMACR values had been modified based on updated information, but the older values within Section F.7.1 were inadvertently not corrected. Th is section dealt with adjusting the Real Discount Rate (RDR) value from 3% to 7%. The end result is that this typographical error does not change any of the results or conclusions for any of the SAMA analyses or sensitivity cases. | ||
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Responses to NRC Requests for Additional Information Dated October 23, 2008 50Unit 2 Summary of the Impact of the RDR Value on the Detailed SAMA Analyses SAMA ID Cost of Implementation Averted Cost Risk(3 percentRDR) Net Value (3 percentRDR) Averted Cost Risk(7 percentRDR) Net Value (7 percent RDR) Change inCost Effective-ness? 1 $4,250,000 $270,474 ($3,979,526)$193,762 ($4,056,238) No 2 $1,200,000 1 $123,092 ($1,076,908)$88,180 ($1,111,820) No 3 $250,000 $76,654 ($173,346) $54,910 ($195,090) No 5 $1,500,000 $222,610 ($1,277,390)$159,310 ($1,340,690) No 9 $62,500 $62,918 $418 $45,070 ($17,430) | Responses to NRC Requests for Additional Information Dated October 23, 2008 50Unit 2 Summary of the Impact of the RDR Value on the Detailed SAMA Analyses SAMA ID Cost of Implementation Averted Cost Risk(3 percentRDR) Net Value (3 percentRDR) Averted Cost Risk(7 percentRDR) Net Value (7 percent RDR) Change inCost Effective-ness? 1 $4,250,000 $270,474 ($3,979,526)$193,762 ($4,056,238) No 2 $1,200,000 1 $123,092 ($1,076,908)$88,180 ($1,111,820) No 3 $250,000 $76,654 ($173,346) $54,910 ($195,090) No 5 $1,500,000 $222,610 ($1,277,390)$159,310 ($1,340,690) No 9 $62,500 $62,918 $418 $45,070 ($17,430) | ||
Yes 10 $2,866,000 $48,630 ($2,817,370)$34,838 ($2,831,162) No 12 $900,000 $302,132 ($597,868) $216,350 ($683,650) No 15 $130,000 $19,324 ($110,676) $13,842 ($116,158) No 17 $2,362,000 $488,118 ($1,873,882)$349,330 ($2,012,670) No 19 $700,000 $60,514 ($639,486) $43,308 ($656,692) No 19a $1,935,000 $929,586 ($1,005,414)$665,408 ($1,269,592) No 20 $313,000 $54,646 ($258,354) $39,106 ($273,894) No 21 $3,000,000 $12,518 ($2,987,482)$8,958 ($2,991,042) No 22 $39,000 $67,650 $28,650 $48,420 $9,420 No 1Cost of implementation is revised as discussed in NSPM response to RAI SAMA 6.b. | Yes 10 $2,866,000 $48,630 ($2,817,370)$34,838 ($2,831,162) No 12 $900,000 $302,132 ($597,868) $216,350 ($683,650) No 15 $130,000 $19,324 ($110,676) $13,842 ($116,158) No 17 $2,362,000 $488,118 ($1,873,882)$349,330 ($2,012,670) No 19 $700,000 $60,514 ($639,486) $43,308 ($656,692) No 19a $1,935,000 $929,586 ($1,005,414)$665,408 ($1,269,592) No 20 $313,000 $54,646 ($258,354) $39,106 ($273,894) No 21 $3,000,000 $12,518 ($2,987,482)$8,958 ($2,991,042) No 22 $39,000 $67,650 $28,650 $48,420 $9,420 No 1Cost of implementation is revised as discussed in NSPM response to RAI SAMA 6.b. | ||
RAI SAMA 6.f | RAI SAMA 6.f | ||
: f. ER Table F.3-7 contains a number of entries that are inconsistent with values reported elsewhere in the ER. Specifically, the Unit 1 CDF is indicated to 9.85E-6 per year, whereas a value of 9.79E-6 per year is r eported elsewhere. The Unit 2 dose-risk is indicated to be 8.37 person-rem per year, wher eas a value of 8.43 is reported elsewhere. | : f. ER Table F.3-7 contains a number of entries that are inconsistent with values reported elsewhere in the ER. Specifically, the Unit 1 CDF is indicated to 9.85E-6 per year, whereas a value of 9.79E-6 per year is r eported elsewhere. The Unit 2 dose-risk is indicated to be 8.37 person-rem per year, wher eas a value of 8.43 is reported elsewhere. | ||
The offsite economic cost risk for Unit 1 and 2, is indicated to be 1.36E4 and 5.44E4, whereas values of 1.59E4 and 6.33E4 are reported elsewhere. | The offsite economic cost risk for Unit 1 and 2, is indicated to be 1.36E4 and 5.44E4, whereas values of 1.59E4 and 6.33E4 are reported elsewhere. | ||
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The slightly higher CDF values presented in Table F.3-7 were not used in t he SAMA quantification. The slightly higher release category frequencies were used, but as the differences are small, and it is the delta between release category values that is used as the basis fo r the SAMA evaluations, these differences are considered insignificant to the overall results of the evaluation. | The slightly higher CDF values presented in Table F.3-7 were not used in t he SAMA quantification. The slightly higher release category frequencies were used, but as the differences are small, and it is the delta between release category values that is used as the basis fo r the SAMA evaluations, these differences are considered insignificant to the overall results of the evaluation. | ||
Note that the release categories making up the LERF risk metric are more important to the SAMA results, as these categories are more likely to im pact onsite and offsite doses and cleanup costs. The over predi ction of the LERF metric produced by summing these release categories is less than 3/1000 of 1% for both units, which indicates that the actual frequencies for these release categories are very clos e to the approximations used in the analysis. | Note that the release categories making up the LERF risk metric are more important to the SAMA results, as these categories are more likely to im pact onsite and offsite doses and cleanup costs. The over predi ction of the LERF metric produced by summing these release categories is less than 3/1000 of 1% for both units, which indicates that the actual frequencies for these release categories are very clos e to the approximations used in the analysis. | ||
During performance of the Prairie Island anal ysis, three SECPOP2000 code errors were publicized, specifically: | During performance of the Prairie Island anal ysis, three SECPOP2000 code errors were publicized, specifically: | ||
: 1) incorrect column formatting of the output file, 2) incorrect 1997 economic database file end character resulting in the selection of data from wrong counties, and 3) gaps in the 1997 economic database numbering scheme resulting in the selection of data from wrong counties. All three errors were addressed and new MACCS2 results were generated. It was verified that these new results for MACCS2 served as the basis for all SAMA quantifications. However, the numbers that were presented in Table F.3-7 had not been updated to reflect the latest values from MACCS2. | : 1) incorrect column formatting of the output file, 2) incorrect 1997 economic database file end character resulting in the selection of data from wrong counties, and 3) gaps in the 1997 economic database numbering scheme resulting in the selection of data from wrong counties. All three errors were addressed and new MACCS2 results were generated. It was verified that these new results for MACCS2 served as the basis for all SAMA quantifications. However, the numbers that were presented in Table F.3-7 had not been updated to reflect the latest values from MACCS2. | ||
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(1) Unit 1 OECR ($/yr) Unit 2 Freq. (/yr) Unit 2 Dose-Risk (p-rem/ yr) | (1) Unit 1 OECR ($/yr) Unit 2 Freq. (/yr) Unit 2 Dose-Risk (p-rem/ yr) | ||
(1) Unit 2 OECR ($/yr) 1 H-XX-X 1.64E+01 3.39E+027.28E-061.19E-02 2.47E-03 8.52E-06 1.40E-02 2.89E-032 H-H2-E 2.11E+04 1.20E+102.32E-114.89E-05 2.78E-01 2.32E-11 4.89E-05 2.78E-013 L-H2-E 2.14E+04 1.32E+105.61E-081.20E-01 7.41E+026.52E-08 1.40E-01 8.60E+024 L-CL-E 3.40E+04 2.10E+108.40E-102.86E-03 1.76E+019.17E-10 3.12E-03 1.93E+015 H-OT-L 2.48E+03 5.70E+074.89E-091.21E-03 2.79E-01 5.87E-09 1.46E-03 3.35E-016 L-CC-L 2.23E+04 3.41E+092.82E-076.28E-01 9.61E+023.39E-07 7.56E-01 1.16E+037 H-DH-L 1.95E+02 1.22E+063.09E-086.03E-04 3.77E-02 3.14E-08 6.13E-04 3.83E-028 L-DH-L 6.22E+02 9.60E+061.92E-061.20E-01 1.85E+011.97E-06 1.22E-01 1.89E+01 9 SGTR 5.69E+04 5.03E+102.33E-071.32E+00 1.17E+041.17E-06 6.66E+00 5.89E+0410 ISLOCA 2.28E+05 7.47E+103.22E-087.35E-01 2.41E+033.22E-08 7.35E-01 2.41E+03FREQUENCY WEIGHTED TOTALS 9.85E-062.94E+00 1.59E+041.21E-05 8.43E+00 6.33E+04 (1) MAACS2 provides dose results in Sieverts (sv). The MAACS2 result is converted to rem (1 sv = 100 rem) for the Dose-Risk results to be used in Section F.4. | (1) Unit 2 OECR ($/yr) 1 H-XX-X 1.64E+01 3.39E+027.28E-061.19E-02 2.47E-03 8.52E-06 1.40E-02 2.89E-032 H-H2-E 2.11E+04 1.20E+102.32E-114.89E-05 2.78E-01 2.32E-11 4.89E-05 2.78E-013 L-H2-E 2.14E+04 1.32E+105.61E-081.20E-01 7.41E+026.52E-08 1.40E-01 8.60E+024 L-CL-E 3.40E+04 2.10E+108.40E-102.86E-03 1.76E+019.17E-10 3.12E-03 1.93E+015 H-OT-L 2.48E+03 5.70E+074.89E-091.21E-03 2.79E-01 5.87E-09 1.46E-03 3.35E-016 L-CC-L 2.23E+04 3.41E+092.82E-076.28E-01 9.61E+023.39E-07 7.56E-01 1.16E+037 H-DH-L 1.95E+02 1.22E+063.09E-086.03E-04 3.77E-02 3.14E-08 6.13E-04 3.83E-028 L-DH-L 6.22E+02 9.60E+061.92E-061.20E-01 1.85E+011.97E-06 1.22E-01 1.89E+01 9 SGTR 5.69E+04 5.03E+102.33E-071.32E+00 1.17E+041.17E-06 6.66E+00 5.89E+0410 ISLOCA 2.28E+05 7.47E+103.22E-087.35E-01 2.41E+033.22E-08 7.35E-01 2.41E+03FREQUENCY WEIGHTED TOTALS 9.85E-062.94E+00 1.59E+041.21E-05 8.43E+00 6.33E+04 (1) MAACS2 provides dose results in Sieverts (sv). The MAACS2 result is converted to rem (1 sv = 100 rem) for the Dose-Risk results to be used in Section F.4. | ||
Responses to NRC Requests for Additional Information Dated October 23, 2008 52 RAI SAMA 6.g | Responses to NRC Requests for Additional Information Dated October 23, 2008 52 RAI SAMA 6.g | ||
: g. ER Section F.7.2 presents the approach used to address the impact of uncertainty on SAMA results. For PINGP, this approach involves quantifying the Level 1 model uncertainty (and uncertainty multiplier) separ ately for each SAMA evaluation case. (In previous licensee renewal uncertainty analys es, licensees determined and applied a single uncertainty multiplier based on the uncertainty distribution in the baseline risk model.) The ER indicates that for thos e SAMAs whose modeling required the addition of new basic events, no new uncertainty distributions were assigned since the design and implementation of the SAMA wa s defined by the analysis. It appears that this approach may have had the unintended consequences of narrowing the uncertainty for those SAMAs that provide a significant risk reduction (because the added basic events are point estimates, the more they show up in the cu tsets the tighter the distribution becomes.) In addition, the actual uncertainty is associated with the diffe rence between the base model and the model with the improvement. The appr oach used in the ER assigns that uncertainty distribution to the model with the improvement even though two different distributions are being subtract ed. As a result, the actual unc ertainty distribution may be broader than indicated in the ER. Demonstr ate that the approach used to estimate uncertainty is appropriate. Describe the impac t on SAMA results if a single uncertainty multiplier (based on the uncertainty in the baseline model) were used in lieu of the SAMA-specific uncertainty multipliers. | : g. ER Section F.7.2 presents the approach used to address the impact of uncertainty on SAMA results. For PINGP, this approach involves quantifying the Level 1 model uncertainty (and uncertainty multiplier) separ ately for each SAMA evaluation case. (In previous licensee renewal uncertainty analys es, licensees determined and applied a single uncertainty multiplier based on the uncertainty distribution in the baseline risk model.) The ER indicates that for thos e SAMAs whose modeling required the addition of new basic events, no new uncertainty distributions were assigned since the design and implementation of the SAMA wa s defined by the analysis. It appears that this approach may have had the unintended consequences of narrowing the uncertainty for those SAMAs that provide a significant risk reduction (because the added basic events are point estimates, the more they show up in the cu tsets the tighter the distribution becomes.) In addition, the actual uncertainty is associated with the diffe rence between the base model and the model with the improvement. The appr oach used in the ER assigns that uncertainty distribution to the model with the improvement even though two different distributions are being subtract ed. As a result, the actual unc ertainty distribution may be broader than indicated in the ER. Demonstr ate that the approach used to estimate uncertainty is appropriate. Describe the impac t on SAMA results if a single uncertainty multiplier (based on the uncertainty in the baseline model) were used in lieu of the SAMA-specific uncertainty multipliers. | ||
NSPM Response to RAI SAMA 6.g The approach used that accounted for the unce rtainty associated with each specific SAMA option on a case-by-case basis was deemed to be more precise in capturing the specific uncertainty associated with those particular generat ed cutsets. Although t he practice of using a single multiplier has been used for other License Renewal applications, the use of a single multiplier for the 95 th percentile utilizing baseline model CDF cutsets tends to provide a multiplier that may not necessarily represent the individual uncertainty associated with each particular SAMA. That is, in using a single multiplier, some SAMAs could be perceived as not being cost beneficial if the overall multiplier was too low. Likewise, an individual SAMA may be mistakenly perceived as being cost beneficial if t he single multiplier is too high. Therefore, it was deemed more appropria te to evaluate the 95 th percentile estimates using those cutsets that pertain to the actual SAMA of interest to provide for better resolution and a more refined estimate of the 95 th percentile cost benefits for each indivi dual SAMA. Theref ore, the use of individual multipliers based on each SAMA option's 95 th percentile results was considered technically sound. | NSPM Response to RAI SAMA 6.g The approach used that accounted for the unce rtainty associated with each specific SAMA option on a case-by-case basis was deemed to be more precise in capturing the specific uncertainty associated with those particular generat ed cutsets. Although t he practice of using a single multiplier has been used for other License Renewal applications, the use of a single multiplier for the 95 th percentile utilizing baseline model CDF cutsets tends to provide a multiplier that may not necessarily represent the individual uncertainty associated with each particular SAMA. That is, in using a single multiplier, some SAMAs could be perceived as not being cost beneficial if the overall multiplier was too low. Likewise, an individual SAMA may be mistakenly perceived as being cost beneficial if t he single multiplier is too high. Therefore, it was deemed more appropria te to evaluate the 95 th percentile estimates using those cutsets that pertain to the actual SAMA of interest to provide for better resolution and a more refined estimate of the 95 th percentile cost benefits for each indivi dual SAMA. Theref ore, the use of individual multipliers based on each SAMA option's 95 th percentile results was considered technically sound. | ||
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Unit 1 95th Percentile Results Using Global Uncertainty Multiplier SAMA ID Cost of Implementation Ratio of 95th to Base CDF Unit 1 Averted Cost-Risk Net Value SAMA 1 $4,250,000 2.95 $791,490 -$3,458,510 SAMA 2 $1,200,000 1 2.95 $364,026 -$835,974 SAMA 3 $250,000 2.95 $221,161 -$28,839 SAMA 5 $1,500,000 2.95 $224,070 -$1,275,930 SAMA 9 $62,500 2.95 $185,135 $122,635 SAMA 10 $2,866,000 2.95 $138,292 -$2,727,708 SAMA 12 $900,000 2.95 $549,356 -$350,644 SAMA 15 $130,000 2.95 $0 -$130,000 SAMA 17 $2,362,000 2.95 $259,736 -$2,102,264 SAMA 19 $700,000 2.95 $178,006 -$521,994 SAMA 19a $1,935,000 2.95 $973,096 -$961,904 SAMA 20 $313,000 2.95 $159,064 -$153,936 SAMA 21 $3,000,000 2.95 $33,300 -$2,966,700 SAMA 22 $39,000 2.95 $45,291 $6,291 1. Results reflect cost correction discussed in the response to RAI SAMA 6.b | Unit 1 95th Percentile Results Using Global Uncertainty Multiplier SAMA ID Cost of Implementation Ratio of 95th to Base CDF Unit 1 Averted Cost-Risk Net Value SAMA 1 $4,250,000 2.95 $791,490 -$3,458,510 SAMA 2 $1,200,000 1 2.95 $364,026 -$835,974 SAMA 3 $250,000 2.95 $221,161 -$28,839 SAMA 5 $1,500,000 2.95 $224,070 -$1,275,930 SAMA 9 $62,500 2.95 $185,135 $122,635 SAMA 10 $2,866,000 2.95 $138,292 -$2,727,708 SAMA 12 $900,000 2.95 $549,356 -$350,644 SAMA 15 $130,000 2.95 $0 -$130,000 SAMA 17 $2,362,000 2.95 $259,736 -$2,102,264 SAMA 19 $700,000 2.95 $178,006 -$521,994 SAMA 19a $1,935,000 2.95 $973,096 -$961,904 SAMA 20 $313,000 2.95 $159,064 -$153,936 SAMA 21 $3,000,000 2.95 $33,300 -$2,966,700 SAMA 22 $39,000 2.95 $45,291 $6,291 1. Results reflect cost correction discussed in the response to RAI SAMA 6.b | ||
Unit 2 95th Percentile Results Using Global Uncertainty Multiplier SAMA ID Cost of Implementation Ratio of 95th to Base CDF Unit 2 Averted Cost-Risk Net Value SAMA 1 $4,250,000 2.78 $751,691 -$3,498,309 SAMA 2 $1,200,000 1 2.78 $342,092 -$857,908 SAMA 3 $250,000 2.78 $213,034 -$36,966 SAMA 5 $1,500,000 2.78 $618,669 -$881,331 SAMA 9 $62,500 2.78 $174,859 $112,359 SAMA 10 $2,866,000 2.78 $135,151 -$2,730,849 SAMA 12 $900,000 2.78 $839,673 -$60,327 SAMA 15 $130,000 2.78 $53,704 -$76,296 SAMA 17 $2,362,000 2.78 $1,356,558 -$1,005,442 SAMA 19 $700,000 2.78 $168,178 -$531,822 SAMA 19a $1,935,000 2.78 $2,583,469 $648,469 SAMA 20 $313,000 2.78 $151,870 -$161,130 SAMA 21 $3,000,000 2.78 $34,790 -$2,965,210 SAMA 22 $39,000 2.78 $188,010 $149,010 1. Results reflect cost correction discussed in the response to RAI SAMA 6.b Responses to NRC Requests for Additional Information Dated October 23, 2008 55 RAI SAMA 8.a For certain SAMAs considered in the ER, there may be lower-cost alternatives that could achieve much of the risk reduction at a lower co st. In this regard, discuss whether any lower-cost alternatives to those Phase II SAMAs considered in the ER would be viable and potentially cost-beneficial. Eval uate the following SAMAs or indicate if the particular SAMA has already been considered. If the latter, indicate whether the SAMA has been implemented or has been determined to not be cost-beneficial at PINGP. | Unit 2 95th Percentile Results Using Global Uncertainty Multiplier SAMA ID Cost of Implementation Ratio of 95th to Base CDF Unit 2 Averted Cost-Risk Net Value SAMA 1 $4,250,000 2.78 $751,691 -$3,498,309 SAMA 2 $1,200,000 1 2.78 $342,092 -$857,908 SAMA 3 $250,000 2.78 $213,034 -$36,966 SAMA 5 $1,500,000 2.78 $618,669 -$881,331 SAMA 9 $62,500 2.78 $174,859 $112,359 SAMA 10 $2,866,000 2.78 $135,151 -$2,730,849 SAMA 12 $900,000 2.78 $839,673 -$60,327 SAMA 15 $130,000 2.78 $53,704 -$76,296 SAMA 17 $2,362,000 2.78 $1,356,558 -$1,005,442 SAMA 19 $700,000 2.78 $168,178 -$531,822 SAMA 19a $1,935,000 2.78 $2,583,469 $648,469 SAMA 20 $313,000 2.78 $151,870 -$161,130 SAMA 21 $3,000,000 2.78 $34,790 -$2,965,210 SAMA 22 $39,000 2.78 $188,010 $149,010 1. Results reflect cost correction discussed in the response to RAI SAMA 6.b Responses to NRC Requests for Additional Information Dated October 23, 2008 55 RAI SAMA 8.a For certain SAMAs considered in the ER, there may be lower-cost alternatives that could achieve much of the risk reduction at a lower co st. In this regard, discuss whether any lower-cost alternatives to those Phase II SAMAs considered in the ER would be viable and potentially cost-beneficial. Eval uate the following SAMAs or indicate if the particular SAMA has already been considered. If the latter, indicate whether the SAMA has been implemented or has been determined to not be cost-beneficial at PINGP. | ||
: a. Procedure for manually controlling the degree of SG depr essurization and reclosing the SG PORVs in the event core damage is immi nent, in order to prevent or reduce the challenge to SG tube integrity. | : a. Procedure for manually controlling the degree of SG depr essurization and reclosing the SG PORVs in the event core damage is immi nent, in order to prevent or reduce the challenge to SG tube integrity. | ||
NSPM Response to RAI SAMA 8.a Procedural guidance similar to th at suggested in this SAMA is already in place for events involving extreme damage to the plant (such as may occur during a security-related incident). | NSPM Response to RAI SAMA 8.a Procedural guidance similar to th at suggested in this SAMA is already in place for events involving extreme damage to the plant (such as may occur during a security-related incident). | ||
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Due to the guidance to the operations and emergency response staff already in place, implementation of this proposed SAM A would have no beneficial impact. | Due to the guidance to the operations and emergency response staff already in place, implementation of this proposed SAM A would have no beneficial impact. | ||
RAI SAMA 8.b | RAI SAMA 8.b | ||
: b. Procedure for enhancing manual operation of turbine-driven Auxiliary Feedwater (AFW) pumps including alternate water sources, and operator aids for using local flow indication to maintain SG level. | : b. Procedure for enhancing manual operation of turbine-driven Auxiliary Feedwater (AFW) pumps including alternate water sources, and operator aids for using local flow indication to maintain SG level. | ||
Responses to NRC Requests for Additional Information Dated October 23, 2008 56NSPM Response to RAI SAMA 8.b The use of alternate water sources is alr eady addressed in the post-accident procedures requiring operation of the AFW pumps, including the TDAFWP (e.g., Caution statements state that if Condensate Storage Tank (CST) level decreases to less than 10,000 gallons, then alternate water sources for AFW pumps will be nec essary). Local manual operation of the TDAFWP may be required during a Station Blackout (SBO) scenario. An abnormal operating procedure provides direction necessary to pe rform these actions. This procedure also contains a step notifying the oper ator to refer to other proc edures for possible sources of makeup to the CST (as CST water le vel is depleted by pump operation). | Responses to NRC Requests for Additional Information Dated October 23, 2008 56NSPM Response to RAI SAMA 8.b The use of alternate water sources is alr eady addressed in the post-accident procedures requiring operation of the AFW pumps, including the TDAFWP (e.g., Caution statements state that if Condensate Storage Tank (CST) level decreases to less than 10,000 gallons, then alternate water sources for AFW pumps will be nec essary). Local manual operation of the TDAFWP may be required during a Station Blackout (SBO) scenario. An abnormal operating procedure provides direction necessary to pe rform these actions. This procedure also contains a step notifying the oper ator to refer to other proc edures for possible sources of makeup to the CST (as CST water le vel is depleted by pump operation). | ||
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Due to the guidance to the operations and emergency response staff already in place, implementation of this proposed SAM A would have no beneficial impact. | Due to the guidance to the operations and emergency response staff already in place, implementation of this proposed SAM A would have no beneficial impact. | ||
RAI SAMA 8.c | RAI SAMA 8.c | ||
: c. Procedure and equipment for us ing a portable pump to provi de feedwater to the SGs with suction from either the external fire ring header or intake canal. | : c. Procedure and equipment for us ing a portable pump to provi de feedwater to the SGs with suction from either the external fire ring header or intake canal. | ||
NSPM Response to RAI SAMA 8.c The suggested action is the subject of an EDMG procedure for injecting water into the steam generators. Such an action would be consid ered by the operators and emergency response personnel following an event invo lving loss of heat sink (see the response to RAI SAMA 8.a above for a discussion of the potential for use of the EDMG procedures in response to non-extreme damage scenarios). A portable, di esel-powered pump and instructions for connecting the pump to supply water to the SGs fr om various sources (including the river) is in place, and emergency response personnel hav e been trained on the use of the equipment and on the procedures. | NSPM Response to RAI SAMA 8.c The suggested action is the subject of an EDMG procedure for injecting water into the steam generators. Such an action would be consid ered by the operators and emergency response personnel following an event invo lving loss of heat sink (see the response to RAI SAMA 8.a above for a discussion of the potential for use of the EDMG procedures in response to non-extreme damage scenarios). A portable, di esel-powered pump and instructions for connecting the pump to supply water to the SGs fr om various sources (including the river) is in place, and emergency response personnel hav e been trained on the use of the equipment and on the procedures. | ||
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Therefore, implementation of the suggested SAMA would not be cost beneficial at PINGP. | Therefore, implementation of the suggested SAMA would not be cost beneficial at PINGP. | ||
RAI SAMA 8.g | RAI SAMA 8.g | ||
: g. Installing a connection flange and valve on safety injection (SI) pump flow test return line to the refueling water storage tank to enable cross-connection of SI pumps to AFW piping via a temporary connection/hose. | : g. Installing a connection flange and valve on safety injection (SI) pump flow test return line to the refueling water storage tank to enable cross-connection of SI pumps to AFW piping via a temporary connection/hose. | ||
NSPM Response to RAI SAMA 8.g As described in the response to RAI SAMA 8. | NSPM Response to RAI SAMA 8.g As described in the response to RAI SAMA 8. | ||
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Given the alternate supplies and strategies already available to the operators, implementation of the suggested strategy would not be cost beneficial at PINGP. | Given the alternate supplies and strategies already available to the operators, implementation of the suggested strategy would not be cost beneficial at PINGP. | ||
RAI SAMA 8.h | RAI SAMA 8.h | ||
: h. Modifying the charging and volume control system to allow cross-tie of the charging pumps from opposite unit using temporary connections. | : h. Modifying the charging and volume control system to allow cross-tie of the charging pumps from opposite unit using temporary connections. | ||
Responses to NRC Requests for Additional Information Dated October 23, 2008 60NSPM Response to RAI SAMA 8.h The risk-significant function supported by th e charging pumps is to provide RCP seal injection, preventing an RCP seal leak from occurring. The most probable situation in which all three charging pumps fail is a single unit station blackout (SBO) event. Due to the ability to crosstie the train-related AC buses between units at PINGP, the potent ial for a single unit SBO to occur is lower than at single unit plant s and at multiple unit plants without this capability. Core damage sequences in which the charging pumps on the opposite unit may be available for cross-tie to the affected unit have a frequency of approx imately 2.3E-6/rx-yr on both units, and are dominated by non-SBO-related RCP seal LOCAs. This is considered an upper bound frequency; in some of these sequenc es power may be lost to the opposite unit standby charging pumps, or ot her equipment or operator failu res may prevent them from being used. These factors were not investigated fully for this response. | Responses to NRC Requests for Additional Information Dated October 23, 2008 60NSPM Response to RAI SAMA 8.h The risk-significant function supported by th e charging pumps is to provide RCP seal injection, preventing an RCP seal leak from occurring. The most probable situation in which all three charging pumps fail is a single unit station blackout (SBO) event. Due to the ability to crosstie the train-related AC buses between units at PINGP, the potent ial for a single unit SBO to occur is lower than at single unit plant s and at multiple unit plants without this capability. Core damage sequences in which the charging pumps on the opposite unit may be available for cross-tie to the affected unit have a frequency of approx imately 2.3E-6/rx-yr on both units, and are dominated by non-SBO-related RCP seal LOCAs. This is considered an upper bound frequency; in some of these sequenc es power may be lost to the opposite unit standby charging pumps, or ot her equipment or operator failu res may prevent them from being used. These factors were not investigated fully for this response. | ||
| Line 704: | Line 700: | ||
Unit Base Averted Cost-Risk (ACR) 95 th Percentile ACR Unit 1 $74,956 $179,894 Unit 2 $76,654 $183,970 Total $151,610 $363,864 SAMA 3 involved installing a bypass around t he motor-operated valve that must open to supply charging pump suction flow from the RWST upo n loss of VCT level. This line would include an air-operated valve, whereas the suggested SAMA investigated here would include two manual isolation valves. The additional, new piping installed un der SAMA 3 would need to be far shorter in length than would this SAMA, and the piping design and installation Responses to NRC Requests for Additional Information Dated October 23, 2008 61 requirements would be less as SAMA 3 involv ed installation on the suction side of the charging pumps. The SAMA 3 cost estimate was $250,000 per unit. If the proposed SAMA could be installed for this amoun t, then the modification would only be cost-beneficial at the 95 th percentile ACR for both units combined. Ho wever, based on the considerations outlined above, the cost to implement this modifica tion would be expected to exceed the SAMA 3 implementation costs. Theref ore, implementation of the suggested SAMA is not considered to be cost beneficial for PINGP. | Unit Base Averted Cost-Risk (ACR) 95 th Percentile ACR Unit 1 $74,956 $179,894 Unit 2 $76,654 $183,970 Total $151,610 $363,864 SAMA 3 involved installing a bypass around t he motor-operated valve that must open to supply charging pump suction flow from the RWST upo n loss of VCT level. This line would include an air-operated valve, whereas the suggested SAMA investigated here would include two manual isolation valves. The additional, new piping installed un der SAMA 3 would need to be far shorter in length than would this SAMA, and the piping design and installation Responses to NRC Requests for Additional Information Dated October 23, 2008 61 requirements would be less as SAMA 3 involv ed installation on the suction side of the charging pumps. The SAMA 3 cost estimate was $250,000 per unit. If the proposed SAMA could be installed for this amoun t, then the modification would only be cost-beneficial at the 95 th percentile ACR for both units combined. Ho wever, based on the considerations outlined above, the cost to implement this modifica tion would be expected to exceed the SAMA 3 implementation costs. Theref ore, implementation of the suggested SAMA is not considered to be cost beneficial for PINGP. | ||
RAI SAMA 8.i | RAI SAMA 8.i | ||
: i. Purchase or manufacture of a gagging device that could be used to close a stuck-open SG safety value on the ruptured steam generator prior to core damage in SGTR events NSPM Response to RAI SAMA 8.i Two recent license renewal applicants addressed this SAMA as part of their analysis (either on initial submittal or in response to an RAI). | : i. Purchase or manufacture of a gagging device that could be used to close a stuck-open SG safety value on the ruptured steam generator prior to core damage in SGTR events NSPM Response to RAI SAMA 8.i Two recent license renewal applicants addressed this SAMA as part of their analysis (either on initial submittal or in response to an RAI). | ||
Beaver Valley found it to be cost beneficial at the upper bound of a sensitivity analysi s, whereas Indian Point found it to be cost beneficial in the base case. Both plants used a $50,000 esti mated implementation cost for this SAMA. | Beaver Valley found it to be cost beneficial at the upper bound of a sensitivity analysi s, whereas Indian Point found it to be cost beneficial in the base case. Both plants used a $50,000 esti mated implementation cost for this SAMA. | ||
Revision as of 05:19, 12 July 2019
| ML083440696 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 11/21/2008 |
| From: | - No Known Affiliation |
| To: | Division of License Renewal |
| References | |
| Download: ML083440696 (67) | |
Text
1 PrairieIslandNPEm Resource From: Vincent, Robert [Robert.V incent@xenuclear.com]
Sent: Friday, November 21, 2008 9:58 AM To: Nathan Goodman; Richard Plasse Cc: Eckholt, Gene F.; Davis, Marlys E.
Subject:
SAMA RAI Response Letter Attachments:
Final Response to NRC RAI Letter of 10-23-2008 wo Encl 2.docI see that the pdf files were too large for you to receive. Let me break the pdf file up and send it to you in pieces.
In the interim, here is the WORD version without Enclosure 2. Enclosure 2 is a set of images that add about 12 MB to the file. It will be included in the pdf version.
Bob Vincent X7259
Hearing Identifier: Prairie_Island_NonPublic Email Number: 169 Mail Envelope Properties (9FA1D9F2F220C04F95D9394E3CF02DABB2E5D4)
Subject:
SAMA RAI Response Letter Sent Date: 11/21/2008 9:58:18 AM Received Date: 11/21/2008 9:58:32 AM From: Vincent, Robert Created By: Robert.Vincent@xenuclear.com Recipients: "Eckholt, Gene F." <Gene.Eckholt@xenuclear.com>
Tracking Status: None "Davis, Marlys E." <Marlys.Davis@xenuclear.com>
Tracking Status: None "Nathan Goodman" <Nathan.Goodman@nrc.gov> Tracking Status: None "Richard Plasse" <Richard.Plasse@nrc.gov> Tracking Status: None
Post Office: enex02.ft.nmcco.net Files Size Date & Time MESSAGE 332 11/21/2008 9:58:32 AM Final Response to NRC RAI Letter of 10-23-2008 wo Encl 2.doc 886848 Options Priority: Standard Return Notification: No Reply Requested: No Sensitivity: Normal Expiration Date: Recipients Received:
1717 Wakonade Drive East Welch, Minnesota 55089-9642 Telephone: 651.388.1121 November 21, 2008 L-PI-08-095 10 CFR 51 10 CFR 54
U S Nuclear Regulatory Commission
ATTN: Document Control Desk
Washington, DC 20555-0001
Prairie Island Nuclear Generating Plant Units 1 and 2
Dockets 50-282 and 50-306
License Nos. DPR-42 and DPR-60
Responses to NRC Requests for Additional Information Dated October 23, 2008 Regarding Application for Renewed Operating Licenses
By letter dated April 11, 2008, Norther n States Power Company, a Minnesota Corporation, (NSPM) submitted an Application for Renewed Operating Licenses (LRA) for the Prairie Island Nuclear Generating Plan t (PINGP) Units 1 and 2. In a letter dated October 23, 2008, the NRC transmitted Requests for Additional Information (RAIs) regarding that application. This lette r provides responses to those RAIs. provides the text of each RAI followed by the NSPM response. Enclosure 2 provides a copy of analysis ENG-ME-148, Revision 1, requested in RAI SAMA 5.b.
If there are any questions or if additional information is needed, please contact Mr. Eugene Eckholt, License Renewal Project Manager. Summary of Commitments This letter contains no new commitment s or changes to exis ting commitments.
I declare under penalty of perjury that the foregoing is true and correct.
Executed on November 21, 2008.
//S// Michael D. Wadley
Michael D. Wadley
Site Vice President, Prairie Island Nu clear Generating Plant Units 1 and 2 Northern States Power Company - Minnesota
Enclosures (2)
Document Control Desk Page 2 cc: Administrator, Region III, USNRC License Renewal Environment al Project Manager, USNRC Resident Inspector, Prairie Island, USNRC
Prairie Island Indian Communi ty ATTN: Phil Mahowald Minnesota Department of Commerce
Responses to NRC Requests for Additional Information Dated October 23, 2008 1 RAI SAMA 1.a Provide the following information regarding t he Probabilistic Risk Assessment (PRA) models used for the Severe Accident Mitigation Alter native (SAMA) analysis (for both units unless otherwise specified):
- a. Provide the core damage frequency (CDF) fo r each of the initiating event categories shown in Figures F.2-1 and F.
2-2. (The percent contributio n to CDF reported in these figures does not provide sufficient resolution).
NSPM Response to RAI SAMA 1.a The requested information is provided in the two tables below
- Figure F.2-1 data:
PINGP Unit 1 CDF by Initiating Event Small LOCA 49% 4.82E-06 Loss of Cooling Water 18% 1.76E-06 Loss of Offsite Power 11% 1.04E-06 Loss of Main Feedwater4% 3.89E-07 Medium LOCA 3% 3.39E-07 Loss of CCW 3% 2.89E-07 Large LOCA 3% 2.76E-07 Internal Flooding 2% 2.39E-07 Normal Transient 2% 2.37E-07 SGTR 2% 1.94E-07 Other 2% 2.12E-07 Total 100%
1 9.79E-06 1. Individual contributors do not add to 100% due to rounding.
Figure F.2-2 data:
PINGP Unit 2 CDF by Initiating Event Small LOCA 45% 5.40E-06 Loss of Cooling Water 15% 1.77E-06 Loss of Offsite Power 10% 1.16E-06 SGTR 9% 1.13E-06 Medium LOCA 4% 5.35E-07 Loss of Main Feedwater3% 4.09E-07 Loss of Train A DC 3% 4.01E-07 Large LOCA 3% 3.05E-07 Loss of CCW 2% 2.90E-07 Normal Transient 2% 2.83E-07 Internal Flooding 2% 2.41E-07 Other 1% 1.73E-07 Total 100%
1 1.21E-05 1. Individual contributors do not add to 100% due to rounding. Responses to NRC Requests for Additional Information Dated October 23, 2008 2 The dominant initiating event cont ributor to the CDF for both units is the Small LOCA initiating event. In all such events, a means of prov iding long term cooling to the core must be provided. The PRA model credits two met hods for Small LOCAs: RCS cooldown and depressurization to allow use of the RHR system in shutdown cooling mode, and transfer to high-head recirculation. Both methods require operator action directed by the EOPs, and high-head recirculation is strictly a manual ac tion at PINGP (no automatic switchover to recirculation). Therefore, on a Small LOCA, failures of two operator response actions are modeled as leading to core damage. Also, in sequences where the RCS cooldown and depressurization action has failed, the probability of success of the transfer to recirculation operator action is considered to be dependent on the fact that the RCS cooldown and depressurization action has already failed.
See the response to RAI SAMA 5.a below for a more thorough discussion of these two operator actions.
- b. Provide the CDF for anticipated transient without scram (ATWS) and station blackout events. NSPM Response to RAI SAMA 1.b The requested information is provided in the table below:
CDF Contributor Unit 1 (per rx-yr)
Unit 2 (per rx-yr)
Anticipated Transient Without Scram (ATWS) 1.63E-07 1.65E-07 Station Blackout (SBO) 8.52E-07 9.41E-07 RAI SAMA 1.c
- c. The Environmental Report (E R) notes several differences between Unit 1 and 2, including auxiliary feedwater (AFW) pump breaker c ontrol power, Unit 1 replacement steam generators (SGs), and improved Unit 1 sump design. Provide a complete summary of differences between the units with a discu ssion of the estimated impact of these differences on CDF and the release frequencies.
Include the reasons for the difference in the emergency diesel generator common cause failure that was stated in Section F.2.1.2.4.
NSPM Response to RAI SAMA 1.c AFW Pump Breaker Control Power At PINGP, the main fe edwater regulating and r egulating bypass valves for both units are air operated valves that fail closed on loss of contro l power. The control power for these valves is supplied from Train A DC power. Therefore, a loss of Train A DC power occurring during at-power operation of either unit will result in a reactor trip (on that unit) with loss of main feedwater. However, breaker control power for the Unit 2 motor driven AFW (MDAFW) pump Responses to NRC Requests for Additional Information Dated October 23, 2008 3 is supplied from Train A DC pow er, while breaker control power for the Unit 1 MDAFW pump is supplied from Train B DC power.
On loss of Unit 2 Train A DC power, if a random failure of the Unit 2 turbine-driven AFW pump occurs, then operator action is required to either locally cross-tie the Unit 1 MDAFW pump discharge to allow the pump to supply the Unit 2 SGs, or (failing that) to initiate bleed an d feed cooling of the RCS. A conditional failure probability for failure of the bleed and feed oper ator action is applied in the PRA model. The likelihood of success of this action is assumed to be partia lly dependent on the success or failure of the action to align and initiate flow from the Unit 1 MDAFW pump.
As a result of the MDAFW pump control power asymmetry, the Loss of Train A DC initiating event contributes more significantly to the Unit 2 CDF (4.01E-7/rx-yr) than it does to the Unit 1 CDF (3.84E-8/rx-yr). The Loss of Train B DC initiating event contributes more significantly to the Unit 1 CDF (1.04E-8/rx-yr) t han it does to the Unit 2 CDF (9.
95E-11/rx-yr). This is due to the fact that the MDAFW pump on Unit 1 is impacted by the Loss of Train B DC (no impact to the AFW system on Unit 2 for Lo ss of Train B DC). Note that the effects of the asymmetry between the Unit 1 and Unit 2 DC power support functions are much less significant for other initiating events, because the DC power trains ar e highly reliable and the probability of train failures over the typical PRA mi ssion time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is low.
The AFW pump control power asymmetry contribut es to a higher potenti al for induced SGTR on Unit 2. On a loss of Unit 2 Train A DC power, the loss of main feedwater and inability of one AFW pump to start automatically increases t he potential for the event to degrade into a core damage event at high pressure due to loss of heat sink (dry SG). This increases both the frequency of the Large Early Release Frequency (LERF) risk me tric for Unit 2 and the L-SR-E release category for Unit 2 by approxim ately 1.18E-9/rx-yr.
Other than through the increase in the potential for induced SGTR, the AFW control power asymmetry does not influence the LERF metric significantly because one train of containment systems remains available to provide containment pressure and temperature control, and all containment penetrations with DC power dependencie s are either closed or fail in the closed position on loss of DC power. The asymmetry also increases Unit 2 non-LERF release categories X-XX-
X (no vessel failure, no containment failure), L-XX-X (vessel failure at low pressure, no containment failure) and L-DH-L (vessel failure at low pressure, late containment failure due to failure to remove decay heat from containment) release category frequencies over their Unit 1 equivalent frequencies; howe ver, the impact to these categories have a much smaller impact on the overall SAMA results.
The table below provides the differences in release category frequencies between Units 1 and 2 based on the AFW control power asymmetry (the differences for release categories not listed were insignificant). De scriptions of the release categori es are provided in Section F.2.4 of the ER.
Responses to NRC Requests for Additional Information Dated October 23, 2008 4 Differences Between Unit 1 and Unit 2 Release Category Frequencies Due to AFW Control Power Asymmetry Release Category Unit 1 Frequency (per rx-yr)
Unit 2 Frequency (per rx-yr) Difference (U2 - U1) L-SR-E 8.42E-11 1.26E-09 1.18E-09 L-XX-X 2.93E-08 2.86E-07 2.57E-07 L-DH-L 1.44E-08 4.98E-08 3.54E-08 X-XX-X 8.51E-10 5.22E-08 5.13E-08 Unit 1 and Unit 2 Emer gency Diesel Generators
The Unit 1 emergency diesel generators (EDGs) ar e the original EDGs, in place since original plant construction. Originally, these EDGs provided backup onsite 4160V AC power for both units; however, in response to the SBO Rule, PINGP installed two new diesel generators dedicated to perform this function for Unit 2. The original capability to supply AC power from an EDG to its train-related 4kV safeguards bus on the opposite unit has been retained. However, the Unit 2 EDGs differ significantly from the Unit 1 EDGs in manufacturer, design, capacity, and in the external systems required to support their operation. Therefore, common-cause failure of EDGs across the units (f or example, between D1 on Unit 1 and D5 on Unit 2) is not modeled in the PINGP PRA model. Common-cause failure of EDGs within units (for example, between D1 and D2 on Unit 1, and between D5 and D6 on Unit 2) is modeled. In addition, the EDG sets of the two units have different operating and performance histories. Therefore, the plant-specific failure data for the Unit 1 and Unit 2 EDGs are not pooled, to allow the model to co rrectly reflect differences in performance between these EDG sets. As a result of these differences, the random and common-cause failure to start and failure to run basic event values used in the PRA model for the Unit 2 EDGs are somewhat higher than they are for the Un it 1 EDGs. Despite these diffe rences, due to the independent design of the EDGs between units combined with the ability to cross-tie the 4kV buses across units, the contribution to the CDF from events initiated by a loss of all AC power is less than 10% for both units, and the contribution to offsite releases is very low (see response to RAI
SAMA 1.b above and Section F.5.2.3 of the ER).
The EDG sets for each unit are already install ed and operational, and ar e already modeled as an integral part of the PRA for both units. A quantitative esti mate of the impact of the design and operating differences on CDF and release frequencies is not available. The extensive effort it would take to quantify the impact of th is asymmetry to the PR A results would not be beneficial (i.e., a SAMA to replace the EDGs on one of the units to match the EDGs on the other unit would not be cost-beneficial).
Unit 1 Replacement Steam Generators
As described in the ER, the Un it 1 steam generator replacement project was completed in 2004, while the Unit 2 steam gener ator replacement has not been completed. From a reactor safety standpoint, the primary difference betw een the new Unit 1 SGs and the Unit 2 SGs is that the Unit 1 SGs are now expected to have a lower potential for tube rupture during plant operation, which is modeled in the PRA by the Steam Generator Tube Rupture (SGTR) Responses to NRC Requests for Additional Information Dated October 23, 2008 5initiating event frequency (Unit 1 SGTR frequency
= 7.98E-4/rx-yr per loop, Unit 2 SGTR frequency = 4.50E-3/rx-yr per loop). The potent ial for SG-related equipment failures and component performance modeled in other areas of the PRA (LOCA frequencies, secondary side break frequencies, impact on operator action timing, etc.) we re assumed to be the same as the previous SGs. Also note that the analysis does not re flect a possibly lower potential for pressure- and temperature-induced SGTR on Unit 1 due to the replacement SGs.
As core damaging events resulting from SGTR are a significant component of the LERF and a primary means of producing offsite releases relevant to the SAMA analysis, the differences in the SAMA quantification results due to the differences between th e Unit 1 and Unit 2 SGs are well-documented in the ER. Differences in the baseline Rev. 2.2 SAMA PRA model results for CDF and LERF due to the SG design asymme try are presented in Sections F.2.2, F.2.3 and F.2.4 and in the figures present ed in Section F.10 of the ER.
Containment Sump Design
The containment sump configurations for both Unit 1 and Unit 2 have recently been modified to address the concerns of Generic Letter 2004-02. The Unit 1 model discussed in Section F.2.2.1 of the ER reflects the installed strai ner sump modification. As described in Section F.2.2.2 of the ER, the Unit 2 SAMA probabilistic analysis result s were quantified using the Unit 2, Level 1 Rev. 2.2 (SAM A) model. At the time of the Rev. 2.2 SAMA model update, the containment sump strainer modifications on Unit 2 had not been completed. However, during the Unit 2 refueling outage in the fall of 2006 (prior to th e submittal of the LRA), the containment sump modifications were completed. Therefore, Section F.7.4 of the ER was included to discuss the results of an analysis to address the sensitivit y of the SAMA analysis results to this plant configuration change.
With the containment sump modifications assumed to be installed, the calculated Unit 2 CDF metric dropped from 1.21E-5/rx-yr to 1.13E-5
/rx-yr, and the LERF me tric dropped from 1.75E-7/rx-yr to 1.72E-7/rx-yr. T he release frequencies for late containment failure categories stayed essentially the same, while many of the release frequencies for early containment failure drop. The improved containment sump design is assumed to reduce the potential for debris blockage and failure of ECCS recirculati on from the sump; this has the effect of lowering the frequency of core damage sequenc es at high RCS pressure due to sump recirculation failure. The reduction in the fr equencies of these high pressure core damage sequences reduces the potential for high pressu re melt ejection (HPME) and reduces the potential for a number of early c ontainment failure modes. Also , the frequencies of the most significant containment-intact categories dropped, reflecting the improved likelihood of long term core cooling success and lower core dam age frequency. The table below provides the change in release category frequencies. Descripti ons of the release categories are provided in Section F.2.4 of the ER.
Responses to NRC Requests for Additional Information Dated October 23, 2008 6 Unit 2 Release Category Baseline Frequency (per rx-yr) Sensitivity Case Frequency (per rx-yr) Change 2X-XX-X 5.67E-06 4.94E-06 -13% 2L-XX-X 2.84E-06 2.75E-06 -3% 2L-DH-L 1.97E-06 1.97E-06 0% 2GLH 1.03E-06 1.03E-06 0% 2L-CC-L 3.39E-07 3.39E-07 0% 2GEH 9.87E-08 9.87E-08 0% 2L-SR-E 4.34E-08 4.02E-08 -7% 2X-H2-E 4.03E-08 3.40E-08 -16% 2ISLOCA 3.22E-08 3.22E-08 0% 2H-DH-L 3.14E-08 3.14E-08 0% 2L-H2-E 2.49E-08 2.42E-08 -3% 2H-XX-X 2.03E-08 2.03E-08 0% 2H-OT-L 5.87E-09 5.87E-09 0% 2X-CI-E 7.32E-10 6.55E-10 -11% 2L-CI-E 1.85E-10 1.85E-10 0% 2H-H2-E 2.32E-11 2.32E-11 0% 2H-CI-E 0.00E+00 0.00E+00 0% 2X-DH-L 0.00E+00 0.00E+00 0% Note: "Sensitivity Case Frequency" indicates frequency with sump modifications installed; sensitivity analysis is described in ER Section F.7.4.
As the modifications have now been comple ted on both units, this design asymmetry no longer exists between the units. If the SAMA analysis was completely re-performed to incorporate the Unit 2 modification, the results would not differ in any meaningful way from the sensitivity analysis results described in Section F.7.4 of the ER RAI SAMA 1.d
- d. In Section F.2.1.2.4 of the ER, the descripti on of the changes made in PRA Revision 2.0 does not distinguish between changes made to the Unit 1 model to produce Unit 1, Revision 2.0, and changes to the Unit 1 model to develop the initial Unit 2 model (i.e., Unit 2, Revision 2.0). Provide a separ ate listing of each set of changes.
NSPM Response to RAI SAMA 1.d Section F.2.1.2.4 of the ER lists all of the si gnificant changes made to the Unit 1 PRA model to produce the Unit 1, Rev. 2.0 model from the Unit 1, Rev.
1.2 model. A sequential process was followed, in which the necessary updates and changes to the Unit 1 model were made, followed by development of t he Unit 2 model from the (re vised and updated) Unit 1 model.
It should be noted that a significant portion of the Unit 2 system logic models already existed in the Unit 1, Rev. 1.2 PR A model, as a number of systems and equipment normally identified Responses to NRC Requests for Additional Information Dated October 23, 2008 7 with Unit 2 are either shared with Unit 1 during normal operati on or can be used to support Unit 1 safety functions in response to an ev ent (see the response to RAI SAMA 1.e below).
As the configurations of the tw o units are nearly symmetrical, the majority of the Unit 2 model development process involved duplication of Unit 1 logic models for the frontline and support systems that were not already in the model as capable of being shared with or cross-tied to Unit 1. Event and logic gate descriptions within these new trees were then changed to reflect the appropriate Unit 2 equipment identifiers. The Rev. 2.0 PRA model was then produced by linking the Unit 1 and new Unit 2 logic models together to support more efficient analysis of equipment and operator failures t hat impact risk on both units.
The following lists break down the changes listed in Section F.2.1.2.4 of the ER into those made to produce the Unit 1 portion of the Rev.
2.0 model and those made to produce the Unit 2 portion of the Rev. 2.0 model:
Changes Made to the Unit 1 Rev.
1.2 Model to Obtain Unit 1, Rev. 2.0 (Interim) Model Removal of the boric acid storage tank (BAST) input to the safety injection (SI) pumps suction logic. The primary suction supply is now only the refueling water storage tank (RWST). Enhancement of the existing quantification methodology, in cluding incorporation of fault tree-based deletion of mutually exclus ive events, including multiple initiating events. Modification to the charging pump system f ault tree logic to include an operator action to restart the pumps after a LOOP event si nce they are not included in the sequencer logic. Use of the same common cause failure (CCF) event for the residual heat removal (RHR) pump discharge check valves in the injection, recirculation, and shutdown cooling modes. A new operator action to prevent load sequenc er failure due to loss of cooling to the 4kV safeguards bus rooms (Bus 15, Bus 16, Bus 25, and Bus 26 rooms) was incorporated into the model.
In conjunction with this change, a factor for the sequencer failure at elevated temperatures was added to the fault tree logic for the safeguards bus. Update to the logic modeling for the supply/
exhaust fans 21, 22, 23, 24 which supply air to the Unit 2 safeguards bus rooms. T he original modeling a ssumed that none of the fans were running (but one train is normally running). This modeling change assumed supply/exhaust fan sets 21 and 22 are normally running and supply/exhaust 23 and 24 are in standby. Therefor e, the failure to start logi c was only included for sets 23 and 24. The CCF to start basic events (BEs) for all four sets was removed from the model. An incorrect and non-conservative mutually exclusive event related to the Screenhouse Flood Zone 2 Initiating event (I-SH2FLD) was remo ved from the logic. This resulted in an increase in the contribution of the Sc reenhouse Flood Zone 2 (SH2FLD) event to the overall results.
Responses to NRC Requests for Additional Information Dated October 23, 2008 8 Changes Made to the Unit 1 Rev. 2.0 (Interim) Model to Obtain Units 1 and 2, Rev. 2.0 Model Addition of Unit 2 frontline and support system logic modeling. Addition of Unit 2 accident sequence logic modeling. Inclusion of CDF and LERF calculations for Unit 2.
- e. The peer review of the PRA was performed in September 2000 , several years prior to the development of the Unit 2 PRA.
In this regard, provide a descrip tion of the quality controls, including any internal and external peer review s, applied to the devel opment of the Unit 2 PRA. NSPM Response to RAI SAMA 1.e The ER provides supporting information based on the PINGP plant-specif ic PRA model. A summary of information related to demonstr ating the technical adeq uacy of the PRA is presented below. Information presented includes: peer-review of the Prairie Island model, expansion of the model to include Unit 2 ri sk metrics, the Prairie Island PRA calculation process and documentation, and additional inter nal reviews that have been performed.
Peer-Reviewed PRA Model
The PINGP PRA model has undergone a Westi nghouse Owners Group (WOG) Peer Review Certification performed in S eptember 2000. The most curre nt PRA model at the time (Revision 1.1) was reviewed, which includ ed only Unit 1 core damage frequency (CDF) and large early release frequency (LERF) model resu lts. The Unit 2 CDF and LERF risk metrics had not yet been incorporated in the model and ther efore were not included in the peer review process. However, the expa nsion of the model to inclu de Unit 2 risk metrics has not invalidated the peer review fi ndings, and the results of the peer review process have been incorporated into the Unit 2-specific portions of the modeling that were not available at the time of the peer review. The expansion of the model is discusse d below (and in the response to question 1.d. above).
The PRA model that was peer-reviewed did include modeling of the equipment shared between the units. This includes the following plant systems:
4160 VAC Power, Cooling Water (known as Service Water at other plants), Instrument Air, Auxiliary Feedwater (AFW) crossties, Safeguards Chilled Water, and Ventilation supporti ng shared equipment.
All of the above models were complete models at the time of the peer review. For example, the Unit 2 4160 VAC power equipment addressed in the Unit 1 PRA models subject to peer review included the following: Responses to NRC Requests for Additional Information Dated October 23, 2008 9 Unit 2 safeguards 4160 VAC buses, Emergency diesel generators, Manual and automatic vo ltage restoration (Safeguards load sequencers), and Support systems required for the Unit 2 safeguards AC power system and EDGs.
The logic models added to the PRA model since the peer certification review have not included any significant changes to thes e core portions of the PRA model.
Expansion of Existing PRA Model to Include Unit 2 Risk Metrics After the peer review was completed, the PINGP PRA model was expanded to include Unit 2 quantification of CDF and LERF risk metrics.
This is considered to be a significant enhancement to the PINGP in-house risk analysis capability. This expansion allows PINGP to more accurately model the impact to Unit 2 risk due to physical and operational differences that exist between the units. These differences include different EDG se t designs, safeguards AC bus and electrical system location (spatial) differences, cooling water pump power supply differences and steam generator replacement. In addition, availab ility of straightforward Unit 2 model risk metrics greatly improves config uration risk assessments for Maintenance Rule (MR) evaluations (10 CFR 50.65(a)(4)), and other Unit 2 risk evaluatio ns, since the operators and scheduling personnel are not r equired to translate Unit 1 results (while accounting for differences between the units) to perform those evaluations.
The Unit 2-specific portions of the PINGP PRA model are essentially a mirror-image of the corresponding Unit 1 model portions (which were peer reviewed), with plant-specific differences included as necessary to make sure that Unit 2 risk is a ccurately modeled. The only differences between the Unit 1 and Unit 2 symmetric system fault trees are the basic event names, descriptions (which reflect Unit 2 equipment), and support system linkages such as power supplies that are specific to Unit 2 equipment. Examples of Unit 2-specific fault tree modeling include the Safety Inject ion, Residual Heat Removal, Component Cooling, Chemical and Volume Control systems, and secondary system s such as Main Feedwater, Condensate and Main Steam systems.
The methodology and assumptions used in the Unit 1 portion of the model are applied in the same way in the Unit 2 portion of the model unless physical differences exist between units.
In addition, the updates that have been performed to address peer review issues have been applied to the modeling for both units.
Upon expansion to include Unit 2 CDF and LERF risk metric quantification, the model was subjected to a series of reviews intended to identify incorrect modeling assumptions and errors in modeling. Due to the symmetry of design and similar operat ion between the units, one of the best ways to identify model problems is to compare the quantified output from one unit to the other, and verify any unexpected results to be accurate. Results from the model for Unit 2 were consistent with the results for Unit 1 risk metrics (which were peer reviewed), including similar cutsets with similar frequencies, similar importance measure results, and so forth. In addition, clear quantification differences between the units appeared where they were expected (where dissimilariti es between the units exist, su ch as the AFW control power asymmetry described in the response to RAI SAMA 1.c above). Some of the evaluations performed on the results for both units include: Responses to NRC Requests for Additional Information Dated October 23, 2008 10 Cutset Review (CDF and LERF). Initiating Event Distribution (CDF and LERF). Dominant Accident Sequences. Model Asymmetry Review. Accident Class Definition and LERF Calculation. Important Operator Actions. Importance Measures (Component, train and system level). Important Equipment Failu res and Unavailability. Important Common Cause Failures.
The quantification review was also documented in accordance with the PRA Calculation File System process (see below).
PINGP PRA Calculation File System Process
The inclusion of the Unit 2 CDF and LERF portions into the PINGP model was documented using the PRA Calculation File System process. This process utilizes a preparer (who is responsible for performing the model revision s and providing documentation that supports the changes), and a reviewer (who is responsible for per forming a verification of the revisions to ensure assumptions and input and output data ar e correct, and to ensur e that documentation is accurate). The PRA Calculation File System process ensures the quality and completeness of the modeling c hanges and the documentat ion. The peer ce rtification team reviewed the PRA Calculation File System proc ess and (together with th e other elements of the maintenance and update process) found it to be adequate for risk informed applications, contingent on closeout of recommendations rela ted to the maintena nce and update process (MU). The Findings and Observat ions (F&O) related to the MU element have been resolved.
As described above, the PRA Calculation File System process was used during the expansion of the model to include Unit 2 risk metr ics. In addition, alt hough not required for all PRA calculations, many porti ons of the expanded, dual-unit PRA model evaluation were reviewed and approved by the Fleet Lead PR A Engineer and PING P PRA Supervisor.
It can be demonstrated that the model used for the SAMA analysis is up to date in that it represents the current plant design and configuration, and represents current operating practices to the extent required to support the submittal. This demonstration is achieved through a PRA maintenance plan that includes a commitment to update t he model periodically to reflect changes that impact the significant accident sequences. The Fleet PRA program requires that the PRA model receive an update regularly, with a frequency approximately once every other operating cycle (for PINGP that is every thr ee to four years). Model elements to be updated during a periodic update in clude data (may be limited to a subset of the most risk significant equipment) and selected initiating events. Model changes may also result from required reviews of procedures for changes to Human Erro r Probabilities (HEPs) and testing intervals; internal and external plant operating experience; changes to Technical Specifications; changes to design bases or other calculations that may affect assumptions in the model; and an assessment of open industry and NRC issues that may affect the PRA and its use for applications.
Responses to NRC Requests for Additional Information Dated October 23, 2008 11 Key assumptions and approximations relevant to the SAMA analysis were used to identify sensitivity studies needed for input to the decision making associated with the analysis. The peer certification review included a focus on t he key model assumptions. The Rev. 2.2 SAMA model development included a param etric uncertainty analysis, tr uncation level review, and a number of sensitivity studies to determine the importance of key assumptions (including credit for containment spray recirculation, potential for containment failure prior to vessel failure, and the failure probability values used for early containment phenomena in the Level 2 analysis). The ER includes the results of a number of sensitivity studies that exercise key assumptions relative to the methodology used for determi nation of the cost-benefit associated with identified SAMAs, including the uncertaint y associated with PRA model parameters.
Additional Assurance of PRA Quality
At PINGP, the PRA progr am is controlled by the Fleet Pr ogram Engineerin g group, and is subject to internal and external assessment to ensure fleet program standards are met and program health is maintained. Since the WO G Peer Certification review, the PINGP PRA model has been reviewed three times as part of the self-assessment process. Maintenance Rule program processes, which rely on the quality of the PRA model underlying the assessment of equipment importance and online ma intenance risk, were reviewed by the site Nuclear Oversight (i.e., Quality Assurance) group in 2003. In additi on, engineering self assessments of the PRA by PRA st aff from other fleet facilities were conducted in 2004 and in 2007. The 2007 assessment also included other external resources. Each of these assessments included the completed 2-unit PRA model.
- f. The model changes identified in Section F.2.1.2 of the ER do not include changes to the reactor coolant pump seal loss-of-coolant a ccident (LOCA) model. Describe the current seal LOCA model, including the conditional seal LOCA pr obabilities used in the model.
NSPM Response to RAI SAMA 1.f The RCP seal LOCA model used for the Prairie Island model is the Westinghouse RCP seal LOCA model described in WCAP-10541, "Reactor Coolant Pump Seal Performance Following a Loss of all AC Power," Revision 2, Nove mber 1986 (Proprietary).
WCAP-10451 models core uncovery due to a seal failure as a functi on of time from a loss of seal cooling and includes effects of restoration of offsite power. The probability of an RCP seal leak as a function of time was analyzed for two conditions: one with RCS cooldown and one without RCS cooldown.
- g. The discussion in Section F.2.2.2 of the ER not es that the Level 1 model used for the SAMA evaluation included one addi tional correction that had a slight impact on CDF, but does not describe this correction. Provide a description of this change and its impact on CDF. Responses to NRC Requests for Additional Information Dated October 23, 2008 12NSPM Response to RAI SAMA 1.g The correction to the model was made to refl ect the fact that the containment sump modifications (as described in Sections F.2.2.2 of the ER and in the response to RAI SAMA 1.c above) were not yet install ed on Unit 2. The Rev. 2.2 m odel had previously (erroneously) modeled the sump modifications as if they were in place in both units. The impact of this change on the Unit 2 CDF is provided in Secti on F2.2.2 of the ER (final CDF increased approximately 8E-7/yr, to 1.21E-5/yr).
- h. Provide the CDF and containment release c haracteristics for internal flood events, and a breakdown and summary of the top flood scenarios.
NSPM Response to RAI SAMA 1.h The table below provides, for each unit, the r equested information regarding the contribution to CDF from internal flooding scenarios.
Internal Flooding Contribution to CDF/LERF Risk Metrics and Release Category Frequencies Risk Metric/
Release Category Int. Flood Unit 1 Frequency (per rx-yr)
% Unit 1 CDF Int. Flood Unit 2 Frequency (per rx-yr)
% Unit 2 CDF CDF 2.39E-072.4% 2.41E-07 2.0% 1GEH 0.00E+000.0% 0.00E+00 0.0% 1GLH 0.00E+000.0% 0.00E+00 0.0% 1H-CI-E 0.00E+000.0% 0.00E+00 0.0% 1H-DH-L 0.00E+000.0% 0.00E+00 0.0% 1H-H2-E 2.32E-110.0% 2.32E-11 0.0% 1H-OT-L 4.63E-090.0% 4.63E-09 0.0% 1H-XX-X 1.18E-100.0% 1.18E-10 0.0% 1ISLOCA 0.00E+000.0% 0.00E+00 0.0% 1L-CC-L 2.27E-072.3% 2.27E-07 1.9% 1L-CI-E 0.00E+000.0% 0.00E+00 0.0% 1L-DH-L 8.86E-100.0% 8.87E-10 0.0% 1L-H2-E 1.61E-090.0% 1.61E-09 0.0% 1L-SR-E 1.19E-090.0% 1.19E-09 0.0% 1L-XX-X 6.83E-090.1% 6.80E-09 0.1% 1X-CI-E 0.00E+000.0% 0.00E+00 0.0% 1X-DH-L 0.00E+000.0% 0.00E+00 0.0% 1X-H2-E 0.00E+000.0% 0.00E+00 0.0% 1X-XX-X 5.55E-110.0% 5.55E-11 0.0%
Responses to NRC Requests for Additional Information Dated October 23, 2008 13 The dominant internal flooding sequences for both units involve flooding of the 695' elevation of the Auxiliary Building. T he worst case flooding scenario (which is assumed for all flooding events associated with this initiating event) is due to a Cooling Water (CL) header rupture in the Component Cooling Water (CC) heat exchanger area, whic h is assumed to fail one train of CC pumps on both units as they are located bel ow the associated CL header in that room. This is considered a dual-unit initiating event.
The other train of CC pumps will continue to function if operator action to identify and isolate the ruptured CL header prior to submergence of the CC pump electrical connections is successful.
Failure of this action will also result in flooding beyond the CC pumps, impacting both trains of Safety Injection (S I) pumps, Residual Heat Removal (RHR) pumps, and Containment Sp ray (CS) pumps, as well as motor control centers (MCCs) supporting the Charging pumps and other safeguards equipment. The core damage sequence involves occurrence of the flooding initiating event followed by failure of the operators to isolate the break prior to loss of the second tr ain of Component Cooling (CC) pumps. This results in loss of reactor coolant pump (RCP) seal cooling, which eventually leads to an unrecoverable RCP seal LOCA as the ECCS pumps have been impacted by the flooding event. For both units, about 97% of the contribution to CDF from internal flooding involves events initiated by flooding of the 695' elevation of the Auxiliary Building (as described above).
The dominant internal flooding containment failure sequence involves the core damage scenario described above. Core damage occurs at high reactor pressure in this sequence.
In-vessel recovery due to submergence of the lowe r reactor vessel head (by filling the reactor cavity) is not successful as all means of pum ping the RWST water into containment, including the CS pumps, have been impacted by the flooding in the Auxiliar y Building. Hot leg creep rupture occurs prior to vessel failure in this sequence, allowing the core debris to exit the vessel at low pressure. As the debris in t he cavity cannot be cooled, containment failure occurs due to basemat failure. This is consi dered a late containment failure mode. For both units, essentially all of the contribution to cont ainment failure release categories from internal flooding involves events initiated by flooding of the 695' elevation of the Auxiliary Building. Responses to NRC Requests for Additional Information Dated October 23, 2008 14 RAI SAMA 2.a Provide the following information relative to the Level 2 PRA analysis:
- a. Describe the modeled risk benefit achieved fr om the removal of procedural guidance to operator initiation of containment spray recirculation as discussed in Section F.2.1.3.1.
NSPM Response to RAI SAMA 2.a Credit for operation of the containment spray (CS) system in recirculation mode was removed in the Unit 1 Level 2 Revision 1 (1L2R1) analysi s so that the PRA model would reflect the as-built, as-operated plant. As described in Section F.2.1.3.1 of the ER, th e decision to make the procedure change was made based on t he results of licensing-basis calculations. There was no risk benefit realized as a resu lt of the procedure change. A specific sensitivity study to identify the significance of this change was not performed for the 1L2R1 model; however it could have had only a very small impact (risk in crease) on the overall results of the 1L2R1 analysis. The availability of t he spray recirculation function does not impact the CDF or LERF metrics for either unit.
Rather, it primarily supports long term containment heat removal for high pressure melt ejection (HPME) accident sequences. These sequences are a subset of the "late containment failure, vessel failure at high pressure" sequence grouping that had a collective frequency of <2% of the total containment failure frequency in the 1L2R1 analysis (1.69E-7/rx-year).
Note that MAAP analyses performed for the IPE showed these sequences (without credit for CS recirculation) take on the order of 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> to result in failure of containment on overpressure, increasing the potential for recovery of failed equipment and reducing the overall source term of any releases. In addi tion, the frequency of sequences in which the CS recirculation function is required and remains availa ble is very low, as this function requires successful operation of the low pressure RHR reci rculation function. T herefore, many of the same sequences that lead to HPME (those initiat ed by or that involve loss of plant cooling water, component cooling water, electric power, et c.) also result in failure of RHR recirculation and ultimately, CS recirculation. These facts i ndicate that the overa ll importance of the CS recirculation function is actually less than the impact described above.
The PINGP Severe Accident Management Gui des (SAMGs) now specify use of CS recirculation (CSR) in the event of containm ent challenge post-core damage. Therefore, credit for the containment spray recirculation function was re-instituted in Level 2 Revision 2 (L2R2) SAMA update. A sensitiv ity study was performed for that model update to investigate the risk benefit of this function based on the current model. To perform the sensitivity case, the CSR function was set to TRUE (failed) in the modeling, and a full re-quantification of the model was performed. Compared to the baseline Level 2 results (provided in Sections F.2.3, F.2.4 and Figures F.2-5 and F.2-6), quantification of the CSR sens itivity case for both units produced very little change in the overall quantificat ion results, with only a slight (<1%) shift from the 1H-XX-X [2H-XX-X] release category to the 1H-DH-L [2H-DH-L] release category.
This shift was due to an increase in core damage sequences leading to vessel failure at high RCS pressure (typically small LOCA with operator failures to cool down and depressurize the RCS and then to switch to recirculation) in which the containment fails on overpressure without the containment spray system capabl e of operating in recirculation mode.
Responses to NRC Requests for Additional Information Dated October 23, 2008 15 RAI SAMA 2.b
- b. It appears that treatment of induced-steam generator tube rupture (SGTR) events was eliminated in Revision 1.
0 of the Level 2 PRA (per ER Sect ion F.2.1.3.1) but reintroduced in Revision 2.2 SAMA of the Level 2 PRA (per ER Sections F.2.3.
1 and F.2.3.2). Clarify the evolution of the treatment of induced-SGTR ev ents. Describe the approach to modeling pressure-induced and thermally-induced SGTRs in the version of the PRA used for the SAMA analyses, including the conditional tube rupture probability and the likelihood of a stuck open SG safety valve.
NSPM Response to RAI SAMA 2.b Induced SGTR events were eliminated in Revisi on 1.0 of the Level 2 PRA model, and were re-introduced in the Level 2 model update used fo r the SAMA analysis, as described in the ER report sections referenced in the question. In the IPE analysis, the potential for induced SGTR events was modeled as dominated by the procedurally-directed operator action to delay core uncovery by starting a reactor cool ant pump to pump the remaining water in the loop seal into the reactor vessel. This action, if performed on an RCS loop in which the SG is dry and depressurized, was seen as having the pot ential for inducing creep rupture of the SG tubes. An IPE recommendation to revise the procedure such that this action is only performed if the SG tubes are verified to be adequately covered with wate r was implemented.
This led to an incorrect assumption that t he remaining risk from induced SGTR events was negligible.
The current understanding of these complex accident scenarios across the industry has developed significantly in recent years (NUREG-1570, NUREG/CR-6595, Rev.
1, etc.). The treatment of induced SGTR in the Rev. 2.2 SAMA models follows the guidance of WCAP-16341-P, "Simplified Level 2 M odeling Guidelines." WCAP-16341-P is an analysis performed specifically for Westinghouse plants, and was performed with the knowle dge of the results of the other two reference docum ents; therefore, this docum ent was used as the primary reference document for modeling pressu re- and temperature-induced SGTR.
Consistent with the WCAP, all core damage accident class sequences in which core damage occurs at high reactor pressure, and the steam generators are dry at the time of core damage (i.e., secondary cooling with Auxiliary Feedwater and Main Feedwater has failed), are assumed to have the potential to lead to pressure-induced SGTR (PI-SGTR).
In addition, all "high-dry" sequences in which the RCS is not depressurized prior to vessel failure are assumed to have the potential to lead to temperature-induced SGTR (TI-SGTR).
Depressurization can occur either intentiona lly, through operator action via the SAMGs, or unintentionally, from a large RCP seal LOCA, or from a prim ary relief valve becoming stuck open during cycling to relieve RCS pressure during the event.
In addition, in order to progr ess to induced SGTR, it was assumed that the secondary side must be depressurized, either through failure of a relief valve upstream of the MSIV to close or remain closed (SG PORV or safety valve), or through the initiating event (main steam line break or main feedwater line break initiati ng events), or the prim ary side must have experienced overpressure (accident class REP - ATWS core damage events at high pressure). Core damage sequence s initiated by these events were treated as having the Responses to NRC Requests for Additional Information Dated October 23, 2008 16 potential to lead to induced SGTR events. Note that the term SG PORV is used at PINGP, while the WCAP and NUREG-1570 use the term Atmospheric Dump Valve (ADV). The acronym "ADV" will be used hereafter in this di scussion to avoid confusion of these valves with the RCS PORVs.
The potential for failure of a main steam safety valve (MSSV) to close is an input to the PI-SGTR conditional probability calc ulation. SG depressurization will occur when a MSSV fails to reseat during cycling. The analysis assumes that the number of challenges to the MSSVs is dependent on whether SG depressurization was attempted by the operators and whether ADV closure was successful (individual MSSV failure to reseat probability values applied were 4.5E-3 for the initial lift, and 3.93E-4 per cycle dur ing valve cycling). It is assumed that four MSSVs are actuated at event initiation. Following the initial discharge, the challenges will likely occur to only one MSSV per SG at the lo west pressure setpoint. Based on WCAP-16341-P, the number of steam cycl es expected prior to a SG dryout is between 60 and 80 if no action is taken. If an ADV is o pened by the operator, the MSSVs will experience significantly less demands, thus the MSSV will have a lower probability to stick open. For each of these cases (operator action and no oper ator action) the probabi lity per SG for an MSSV to stick open is then calculated by multip lying the number of MSSVs assumed to be challenged times the failure prob ability of the valve to reseat, and adding to that value the number of assumed relief valve cycl es multiplied by the failure rate per demand that the valve sticks open during cycling operation. The probability of any or all SGs at low pressure was determined by using an event tree to identify the algebraic expressions in terms of the likelihood per SG. The probabili ty of a steam generator depressurizing was also assumed to be equal for both stea m generators.
The WCAP-16341-P methodology uses an event tree approach to determining the potential for PI-SGTR and TI-SGTR. For high pressure core damage sequences, the PI-SGTR probability is defined by: 1) the number of SG s at the plant, 2) the success or failure of operator action to use an ADV to prevent lifting a main steam safety valv e, 3) whether or not an ADV has stuck open, and 4) whether or not a main steam safety valve has stuck open.
The TI-SGTR probability is defined by: 1) the num ber of SGs at the plant, 2) the number of SGs depressurized during accident progression, 3) the condition of the RCP loop seals, and 4) whether a cleared loop seal occurs in an intact or depressuri zed SG. WCAP-16341-P provides generic (by reactor class) induced SG TR branch probabilities that take into account an analysis of the potential for SG depressuriza tion and considerations specific to the WOG SAMGs that would lead to conditions necessary for pressure- and temperature-induced SGTR. The probability values used in the PRA model are 2-loop PWR values, assuming an "average" tube condition (mid-life operation with thorough SG tube in spection process).
Due to the proprietary natur e of WCAP-16341-P, NSPM is unable to provide the SG depressurization and the PI-SGTR and TI-SGTR probability values recommended in the report in this RAI response. During a conference call between NSPM and NRC staff held on August 23, 2008 to clarify the draft RAI questions, the staff suggested that NSPM indicate in its response whether the values were "closer to" the similar values identified in NUREG-1150 or in NUREG-1570.
NUREG-1570, Table 2.6 provides the breakdown of the probabilities assumed for having 0, 1, or more SGs depressurized at the time of core uncovery for two NUREG-1150 plants (Surry and Sequoyah), and also provides the staff assumptions for thes e probabilities for the Responses to NRC Requests for Additional Information Dated October 23, 2008 17NUREG-1570 analysis. The WCAP-15341-P values calculated for 2-loop PWRs (based on the methods described above) are closer to t he NUREG-1150 Sequoyah resu lts. This is due to the lower MSSV initial lift and cycling failure-to-close rates applied, and credit for minimizing the required number of MSSV lifts if the operator successfully uses the ADVs during the event.
WCAP-16341-P provides PI-SGT R and TI-SGTR event tree branch probabilities that are based on review of NUREG-1570, EPRI analysis, and plant specific analyses for two Combustion Engineering plants.
No treatment of PI-SGTR was identified in NUREG-1150; however, Appendix C, Section C.6.2 provides re sults of an expert e licitation on TI-SGTR probability in which two of the th ree panel experts believed that this probability was less than 5E-4, based on their belief that the RCS hot leg would fail first in these scenarios. In Section 5.1 of NUREG-1570, the probability of a PI-S GTR is estimated to be 0.0549 and 0.107 for events/APET branches involving depressurization of one and two SG s, respectively, that are assumed to have "moderate" degr adation. NUREG-1570, Table 5.2, provides a TI-SGTR value for the intact SG loop (no SGs depressu rized) of 0.0058 (Case 1R), a value for one depressurized loop of 0.0835 (Case 3R), and a va lue for all 3 SGs depressurized of 0.0399 (Case 7R). Upon loop seal clearing on an RCP seal LOCA, a value of 0.121 is provided for the intact SG and 1.0 for the depressurized SG (Case 9R).
The WCAP PI-SGTR values are roughly about an order of magnitude lower than the NUREG-1570 values. The WCAP TI-SGTR values are generally mid-way between the NUREG-1150
and NUREG-1570 values, or are closer to the NUREG-1150 values. In one case (TI-SGTR, intact loop seal, both SGs depressurized), the WCAP value is higher than the NUREG-1570 value.
- c. State the version of the modular accident analysis program (MAAP) code used for the SAMA analysis, and the PRA version in which the MAAP cases were last updated.
NSPM Response to RAI SAMA 2.c The version of the MAAP code used for t he SAMA analysis was MAAP 3.0B. The MAAP cases were those originally performed for the IPE analysis.
Responses to NRC Requests for Additional Information Dated October 23, 2008 18 RAI SAMA 3.a Provide the following information regarding the tr eatment of external events in the SAMA analysis:
- a. Provide a summary of the dominant fire scenarios for the individua l plant examination of external events (IPEEE) fire model in terms of overall fire frequency, plant initiator, and structures, systems, and com ponents (SSCs) impacted. De monstrate for each fire scenario that no viable SAMA candidat es exist to reduce fire risk.
NSPM Response to RAI SAMA 3.a A complete discussion of dominant fire scenarios for the IPEEE Fire risk analysis, including the requested information on frequency, initiato r and SSCs impacted, is provided in the IPEEE Rev. 1, Section B.1.4, and supporting table B.2.11.1.
For the ER SAMA analysis, fire area-specific SAMA candidates were not developed. The Fire IPEEE was performed using a Fire PRA built on the Unit 1 Level 1 Revision 1 (1L1R1) PRA model. As described in Section F.2.1.2.1, the 1L1R1 model was completed in 1996 and was the first major revision of the PRA model since the IPE. This was a Unit 1-only, Level 1-only model, and did not include an estima te of the LERF metric for Un it 1. In the twelve years since the 1L1R1 model was impl emented, numerous plant modifications, procedure changes and risk analysis methodology changes have been incorporated, and model enhancements have been made in response to industry peer certification comments. As a result, significant changes to the calculated CDF and distri bution of dominant accident sequences and contributors are evident when comparing the re sults of the 1L1R1 and Unit 1 Rev. 2.2 SAMA models. Section F.2 of the ER shows the c hanges that have been reflected in the Level 1 and Level 2 PRA models since the 1L1R1 model was implemented. Also, methodologies associated with Fire PRA have been improved ov er the ten years since the Fire IPEEE was developed. The Fire PRA methodologies used in the Fire IPEEE analysis differ from current industry methodology (NUREG/CR-6850, etc.). Also, as discussed in the response to RAI SAMA 3.b, the Fire IPEEE results include significant conservative assumptions, even in the sequences that were found to domi nate the risk profile. The fire CDF of 4.9E-5/yr reported in the Fire IPEEE is considered to be a conserva tive upper bound for that (1998-vintage) risk model. Due to these considerati ons, it was concluded that an ev aluation of fire area-specific SAMA candidates using the IPEEE would not provide valid results.
From the Fire IPEEE, Section B.1.4, the CDF from internal fires is spread across five accident classes: 1. [66%] Accident class TEH is comprised of transient (i.e., fire) initiated events with loss of secondary heat removal (loss of MFW and AFW) and failure of bleed and feed. Reactor pressure is high at the time of core damage. Core damage occurs within approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of the loss of heat removal. 2. [19%]The SEH accident class for the IPEEE consists of RCP seal LOCA initiated events, or events that progress similar to small LOCAs due to fire-induced spurious equipment actuation, in which high head safety injection is not capable of preventing core damage. Reactor pressure is high at the time of core damage, which occurs relatively early (see TEH). Responses to NRC Requests for Additional Information Dated October 23, 2008 193. [11%]The BEH accident class involves fire s that cause the loss of offsite power, and onsite power is not successfully restored prior to core damage. Only one initiating fire was determined to lead to loss of offsite power , a large fire in the control room "G" control panel. A fire large enough in this panel could affect both trains of offsite power, and the recovery of both offsite and onsite power from the control room. In this event, credit is given for operator response to lo cally restore onsite AC power from the emergency diesel generators according to established plant procedures. 4. [2%]Accident class SLH is similar to the SEH class, except that high head safety injection is successful. Long term recirculatio n cooling of the RCS then fails, leading to late core damage at high pressure. 5. [2%]Accident class TLH is characterized by transient initiated events with loss of secondary heat removal, successful bleed and feed but failure of recirculation. Reactor pressure is high at the time of core dam age, which occurs on the order of 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> after the loss of secondary cooling.
Each of these accident classes correspond to a ccident classes used in the internal events PRA models. Except for the fi re suppression response, most of the equipment and operator actions necessary to mitigate most fire-induc ed transients and LOCAs are the same as those that are necessary to mitigate transients and LOCAs caused or in duced by internal initiating events. Therefore, all SAMAs identified in the ER with risk benefits that are not limited only to containment bypass events, LOCA events lar ger than a small LOCA, and reduction of the frequency of internal initiating events, will also act to reduce the core damage risk associated with internal fires (to various degrees, depending on the SAMA). Of the SAMAs described in the ER, the only SAMAs that do not also act to reduce internal fires risk are:
The SAMAs that only limit the impact of internal flooding events (SAMAs 6, 6a and 13);
and The SAMAs that only improve the risk associated with ISLOCA events (SAMAs 19 and 20). All of the other SAMAs identified in the ER would also function to reduce the risk of events initiated by internal fires.
The above considerations notwiths tanding, a number of additional SAMAs that attempt to specifically address the risk fr om internal fires were developed in response to this RAI question. Many of these SAMAs are general in nature, as a focus on individual fires or fire areas may not be appropriate given the number of changes to the plant, procedures and risk analysis models that have occurred since the IPEEE was issued. The following table describes these alternatives and their disposition for PINGP:
Phase 1 SAMA ID# SAMA Title Result of Potential Enhancement Screening Basis Disposition 1 Enhance control of transient combustibles and ignition sources SAMA would minimize risk associated with important fire areas by decreasing the Already implemented Procedures to control the use, location and amount of combustible material and ignition sources are in place at PINGP. Deficiencies are captured in the Corrective Action Program. Responses to NRC Requests for Additional Information Dated October 23, 2008 20 Phase 1 SAMA ID# SAMA Title Result of Potential Enhancement Screening Basis Disposition frequency of fires and their consequences. 2 Enhance fire brigade awareness SAMA would minimize risk associated with important fire areas by decreasing the duration and consequences of fires. Already implemented Credit for manual fire suppression was given only for fires in the Control Room and Relay Room in the Fire IPEEE. A procedure provides specific instructions on the organization of fire brigades, training and qualification of individual fire brigade members, individual responsibilities in regard to fires, and procedures for extinguishing fires. Operations emergency responses for fires located in specific locations is covered in subsections of this procedure and in the site Emergency Plan Individual Fire Brigade members are required to actively participate
in at least two (2) drills per year. PRA insights, including dominant fire sequences from the Fire IPEEE analysis, are included in the operations initial and requalification training programs 3 Upgrade fire compartment barriers SAMA would minimize risk associated with important fire areas. Already implemented PINGP fire compartment barriers are monitored and maintained operable to reduce fire propagation. Operability requirements and surveillance frequencies are identified in plant procedures. Barriers found to be inoperable are required to have a fire watch or patrol established (assuming operable fire detectors) on one side of the affected barrier within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. Other compensatory measures may be established in lieu of these requirements if they are determined to be more effective (the use of such measures is controlled according to procedure and requires an evaluation that includes risk insights). 4 Enhance procedures to allow specific operator actions SAMA would reduce the risk associated with important fire areas by reducing the consequences of fires.
Already implemented PINGP safe shutdown procedures are available for use to accomplish safe shutdown in response to fires. The purpose of these procedures is to outline those actions necessary to safely shut down the plant in the event that the Control Room must be evacuated, or there is a fire in the Relay Room or other plant area affecting the operation of equipment needed for safe shutdown. Operations emergency response for fires located in specific locations is covered in subsections of these procedures and in the site Emergency Plan. 5 Enhance procedures associated with plant shutdown from This SAMA would allow alternate system control in the event that the Control Room Already implemented PINGP procedures outline those actions necessary to safely shut down the plant in the event that the Control Room becomes uninhabitable due to a fire. Responses to NRC Requests for Additional Information Dated October 23, 2008 21 Phase 1 SAMA ID# SAMA Title Result of Potential Enhancement Screening Basis Disposition the Hot Shutdown Panel becomes uninhabitable.
6 Isolate combustible sources for seismic or other events This SAMA would reduce risk by limiting the volume of flammable or combustible materials that may emanate from piping systems damaged during seismic events.
Already implemented See discussion of item #1 above. In addition, the IPEEE analysis included a review of seismic/fire interactions. As part of the seismic assessment walkdown, it was verified that hydrogen or other flammable gas or liquid storage vessels in areas with safety related equipment are not subject to leakage under seismic conditions. The potential failure of vessels containing flammable or combustible liquids or gases could cause a fire hazard in the plant following an earthquake. As a part of the seismic walkdowns, a survey of tanks and vessels that may contain flammable fluids was performed. The IPEEE review concluded that these issues are not significant contributors to fire-induced core damage at Prairie Island. 7 Restrain or locate cabinets containing
flammable materials to reduce the
likelihood of overturning caused by seismic or other events This SAMA would reduce risk by reducing the potential for cabinets overturning and spilling flammable liquid contents.
Already implemented See discussion of Item #6 above. 8 Ensure that the quantity of combustible materials in critical process areas is monitored This SAMA would reduce risk by reducing the potential for a prolonged fire to develop in safety-related areas.
Already implemented PINGP has controls governing the fire-safe use and storage of combustible materials within the process buildings. The Fire Hazard Analysis documents the analyzed combustible loading in each fire area. Plant procedures require a Combustible Control Permit (CCP) for any work involving a fire hazard, and prior to temporary or permanent storage of combustible material the additional combustible loading must be analyzed through the CCP process. 9 Limit switches and torque switches would not be bypassed during a fire induced hot short for Control Room
and Relay This SAMA would address the reconfiguration of the MOVs control circuits and protect the motor
operator via the limit and torque switches due to the fire induced Already implemented PINGP has reconfigured the control circuits of a number of Appendix R motor-operated valves to address hot short concerns of NRC Information Notice IN 92-18. Responses to NRC Requests for Additional Information Dated October 23, 2008 22 Phase 1 SAMA ID# SAMA Title Result of Potential Enhancement Screening Basis Disposition Room fire events hot short. 11 Relocate instrument air compressors out of the AFW pump rooms This SAMA would reduce risk by reducing the potential for fire ignition and development of large fires in AFW pump rooms.
Potential risk benefits to both units. High implementation cost This modification with potential as a fire-related risk mitigation measure is currently in progress. This is a very complex and expensive plant modification that may not be cost-justifiable based on risk-reduction alone. The site MMACR from ER Section F.4.6 was just over $4 million; the current cost estimate for this modification is >$4 million.
Instrument Air is not lost in most of the top internal events CDF and LERF sequence cutsets. Fire IPEEE showed fires in AFW/IA compressor room to contribute only 16.7% of fire CDF. 12 Re-route cables that currently exist in risk-significant fire areas This SAMA would reduce risk by reducing the consequences of a fire in risk-significant fire areas. High implementation cost Re-route of individual cables can provide highly targeted risk reduction for certain fire scenarios. However, the risk reduction is unlikely to offset the high cost of these modifications.
Refer to Section F.5.1.6 of the ER for a di scussion of how the recommendations developed from the IPEEE insights were dispositioned.
- b. ER Section F.5.1.8 indica tes that the maximum averted cost-risk (MACR) for internal events was doubled to account for external ev ents contributions. However, ER Section F.5.1.7.2 indicates that the IPEEE fire CDF is about 5E-5 per year, which is approximately five times the internal event CDF. (This value is stated as being conservative in part due to not crediting automatic and manual fire suppression.)
Furthermore, in a July 21, 2006, request for addi tional information (RAI) response related to an extension of the containment integrated leakage rate test (ML062060033), Nuclear Management Company, LLC estimated the seismic CDF for Prairie Island Nuclear Generating Plant (PINGP) to be 7.82E-6 per year. Provide additi onal justification for use of a multiplier of 2 given that the fire CDF is approximately five times the current internal events CDF, that credit for automatic and m anual fire suppression has been included for many of the dominant fire sequences, and that seismic and other external events also contribute to the total CDF.
Responses to NRC Requests for Additional Information Dated October 23, 2008 23NSPM Response to RAI SAMA 3.b Internal Fires
From the results of the PINGP IPEEE, it can be reasonably concluded that the majority of the external events risk at PINGP is due to internal fires. Both t he IPE CDF (5.0E-5/rx-yr) and the fire CDF from the IPEEE (4.9E-5/rx-yr) are comparable and of the sa me magnitude. These two analyses were performed within four year s of each other in the mid-1990s, and were based on conservative modeling methodologies consistent with state-of-the-knowledge at the time. In addition, the purpose of the Fire IPEEE analysis was to meet Generic Letter 88-20 requirements (identify vulnerabilities to severe accidents initiated by internal fires), and was not to determine the internal fires CDF to a high degree of accuracy. The analysis contained numerous conservative assumptions for which (i n alignment with the original purpose of the analysis and available analysis resources) further refinement was unnecessary. The fire IPEEE CDF can be considered to be an estimate of the upper bound risk of internal fires that existed at that time, based on then-available methodologies.
Therefore, it is not appropria te to compare a conservative CDF estimate for fire hazards based on the IPEEE to the present-day internal events CDF, which is based on more refined modeling techniques and analyses. In fact, the IPEEE CDF due to fires would be expected to decline along with the CDF due to in ternal events, since the plant response to fire damage is not unlike the plant response to plant transients due to equipment failures and other internal events. Since the Fire IPEEE analysis was completed, the conditional core damage probability (CCDP) associated with normal (or general) plant transient-initiated events on Unit 1 (as calculated for the updated in ternal events PRA model) has fallen by 46%. This fact, independent of fire PRA methodology improvements now available, supports NSPM's belief that the current, actual Fire CDF is significantly lower than the value calculated for the IPEEE.
As stated above, there were a num ber of significant, conservative assumptions included in the Fire IPEEE that could be refined using currently available methodo logies to determine a more realistic estimate of the current fire CDF.
All fires (any size) were conservatively assumed to result in shutdown of both units.
One impact of this conservatism relates to the ability to credit cr oss-tie of the motor-driven AFW pump (MDAFWP) from the opposite unit to the st eam generators (SGs) of the unit experiencing the fire. A limitation on this crosstie was included in the fault tree for AFW such that if a dual unit initiati ng event occurred and the opposite unit turbine-driven AFW pump (TDAFWP) failed, the oppos ite unit MDAFWP could not be cross-tied to the fire-affected unit as it would be required to support the SGs on its own unit.
As all fires were conservatively assumed to result in shutdown of both units, credit for this crosstie is limited if random or fire-associated failures impacting the opposite unit TDAFWP were assumed to occur.
Credit given in IPEEE for automatic and manual suppression was limited. A large portion of IPEEE fire CDF could be significa ntly reduced through additional application of credit for automatic or manual suppression. In the IPEEE, credit was only applied to cutsets representing <13% of the internal fires CDF. Responses to NRC Requests for Additional Information Dated October 23, 2008 24 o No credit was given for the ability of fire brigade to extinguish local fires before shutdown of the plant would be required.
o Credit only applied to Control Room, Relay Room, and certain AFW pump room fires. Only automatic fire suppressi on was credited in t he AFW pump rooms.
o No detailed analysis of Human Error Probabili ties (HEPs) for failure of manual fire suppression was performed for fires in any fire area.
No credit was given to the availability of the RCS PORV passive air accumulators located inside containment to provide suppo rt for bleed and feed (B&F) cooling of the RCS. For any fire that is assumed to impact the instrument ai r (IA) system, B&F is assumed to fail. This is an important consideration in a num ber of dominant IPEEE fire areas (FA) in which main feedwater or AFW is also impacted.
For example, the response to the fires occurring in FA 13 (Control Room panel zones 5 & 6) and FA 32 (AFW pump room) described below are signif icantly impacted by this conservative treatment. Credit is now given in the internal events PRA analysis for the availability of this equipment (see response to RAI question 6.d).
Detailed fire modeling was not performed in a number of fire areas that did not screen out of the analysis, including the Bus 16 and Bus 111 switchgear rooms and three large fire areas covering the entire floor elevation for a given unit in the Auxiliary and Turbine buildings.
The Fire IPEEE results showed that fires originating in two Unit 1 plant fire areas contributed approximately 82% of the total inte rnal fires CDF. No other indi vidual fire areas contributed more than 4.5% of the CDF. Conservative assumptions in the IPEEE analysis specific to these areas include:
Control Room (CRM) - FA 13 (65.3%, 3.22E-5/yr):
o Except for fires in the G-panel, small c ontrol room panel fires (those that are not large enough to propagate outside the control board zone in which they initiate) are assumed to cause the loss of all equipment within that panel zone. No credit for cable separation to allow partitioning of these cabinet fires further was given.
o CRM Panel Zones 5, 6 fires (LOFW/AFW)
(~40% of total fire IPEEE CDF, almost 2E-5/yr)
Almost all sequences include failure of B&F or recirculation ANY size fire results in loss of entire cabinet (in this case, loss of all main FW and AFW). Local recovery of AFW was not credit ed, nor was any other means of feeding the SGs (see responses to RAI questions 8.a, 8.b, and 8.c). ANY size Panel Zone 6 fire was assumed to result in spurious actuation (open) of the SG PORVs, resulting in an MSLB-like plant response (including Instrument Air (IA) to containment valve auto-closure). This requires the operator to re-open IA to c ontainment isolation valves in order to prevent B&F failure (see conservative IA passive a ccumulator treatment described above). Responses to NRC Requests for Additional Information Dated October 23, 2008 25 o CRM Panel fires (LOOP/SBO) (~11% of total fire IPEEE CDF, >5E-6/yr) ANY size fire results in loss of at l east one train of offsite and onsite AC power to safeguards equipment.
o CRM Panel Zones 7, 8 and Panel 1PLP (LOCA) (~4% of total fire IPEEE CDF, >2E-6/yr)
ANY size fire results in spurious openi ng of RCS PORVs and block valve failure to operate.
AFW Pump Room - FA 32 (16.7%, 8.23E-6/yr) o Although fire water suppression was credited fo r certain fires in this fire area, only about 12% of FA 32 CDF involved unsuccessful suppression (1.01E-6/yr, 2.05% of
overall fire CDF).
o Fire water suppression credit was applied using a simple point value (2E-2) taken from EPRI FIVE analysis; PING P did not have a plant-specific fault tree model for this system (would be expected to provide a lower, more realistic unavailability value). It is recognized that a re-analysi s of internal fires risk, if performed today (based on the current state of knowledge r egarding fire risk and methodologie s now available), may show that some of the assumptions and methodologies used in the Fire I PEEE were potentially non-conservative. However, it is believed likely that these considerations would not outweigh the scope and magnitude of the conservatisms included in the IPEEE (the most significant of which are described above). Therefore, NSPM believes that it is reasonable to assume that the CDF due to fire would still be com parable to the internal events CDF.
Seismic Events
In addressing the seismic portion of t he IPEEE, a reduced-scope seismic margins assessment was performed in accordance with EPRI NP-6041-SL, "Assessment of Nuclear Power Plant Seismic Margin (Revision 1)." Section F.5.1.7.1 of the Environmental Report stated that there were no identified significant plant vu lnerabilities to severe accidents attributable to seismic event s at Prairie Island.
Although PINGP does not have a completed seismic PRA, a bounding estimate of seismic risk was developed in support of anot her NRC submittal. Using a methodology known as the "Simplified Hybrid Method" to quantify the results of a seismic margins analysis (SMA) methodology, a core damage frequency estimate of 7.82E-6/yr was obtained. The purpose of that calculation was only to provide a cons ervative upper bound estimate of seismic CDF to support that particular submittal, not to obtain a realistic measure of seismic risk at PINGP.
The Simplified Hybrid Method uses only two pl ant-specific details, the High Confidence Low Probability of Failure (HCLPF) of the seismic Safe Shutdown Equipment List (SSEL) component determined to be the most limiting in the SMA, and t he seismic hazard curve for PINGP. Mathematical formu lae developed from comparisons of other-plant SMAs and Responses to NRC Requests for Additional Information Dated October 23, 2008 26industry seismic PRAs were then used to determi ne the seismic CDF estima te for PINGP. It is very difficult to conclude much about the tr ue seismic CDF value or distribution of seismic risk based on the results of this simplified method.
However, as calculated, the seismic CDF estimate is below the internal events CDF level
currently calculated for either unit. Also, as described in the ER Se ction F.5.1.6 and in the response to RAI 3.c, plant impr ovements that lower the risk due to seismic events were made as a result of both the IPEEE and SQUG efforts. Therefore, it is believed that the true seismic CDF is even lower than that calculat ed by the Simplified Hybrid Method.
Other External Events:
In addition to internal fires and seismic events, the PINGP IPEEE included an assessment of a variety of other external hazards: High Winds Tornadoes External Flooding Transportation and Nearby Industrial Facility Accidents Other External Hazards
The PINGP IPEEE analysis of these hazards was accomplished by reviewing the plant environs against regulatory r equirements regarding these hazards. Based upon this review, it was concluded that PINGP meets the applicable Standard Review Plan requirements and therefore has an acceptably low risk with respect to these hazards. As such, these hazards were determined in the PINGP IPEEE to be negligib le contributors to ov erall plant risk.
Based on the above considerations for internal fires, seismic events, and other external events, the (x2) multiplier was chosen in calc ulating the value for the Modified Maximum Averted Cost Risk (MMACR). No higher multiplier is believed to be warranted given the current state of knowledge regardi ng external events at PINGP.
- c. As stated in the IPEEE seismic analysis, several potential seismic outliers were dispositioned through an analysis process wh ich determined that the impacted function was not required or could be recovered, or that an alternate means for performing the associated function was available. For those outliers identified in IPEEE Section A.2.4.1.2, where recovery or an alternate means is credited, demonstrate that enhancing the ruggedness of the associated co mponents is not cost-beneficial. The outliers include:
turbine-driven AFW pump trip and throttle va lves (recovered), diesel generator fuel oil storage tanks 122 and 124 (alternative tanks avai lable), the boric acid transfer pumps (alternate supply available), charging pum ps 12 and 23 (alternative charging pumps available), panel 117 (alternate power norma lly available), cooling water pump 121 (alternate pumps available), condensate storage tanks 11, 12 and 13 (recovered through the use of alternate sources (e.g., cooling water)), component cooling water pressure switches (alternate start signal available), and diesel-driven cooling water pump pressure switches (alternative start signal available).
For those outliers stated as being resolved Responses to NRC Requests for Additional Information Dated October 23, 2008 27 through the closure of USI A-46 (IPEEE Section A.2.4.1.1), c onfirm that all corrective actions have been completed, and that their us e is supported by procedures and training, as appropriate.
The outliers identified in IPEEE Section A.2.4.1.2, and the di scussion of whether increasing their seismic ruggedness would be cost benefic ial, are provided in the following table
- IPEEE Seismic Outlier (Section A.2.4.1.2)
IPEEE Disposition Basis Comments Turbine Driven Auxiliary Feedwater Pump (TDAFWP) trip and throttle valves Recovered From the PINGP seismic hazard curve presented in NUREG-1488 Appendix A, the expected frequency of exceedance of the PINGP SSE (0.12g) is approximately 1E-4/yr. The TDAFWP is seismic category 1 equipment and would be expected to remain available following an SSE event; however, assuming TDAFWP overspeed device is tripped, and 1E-2 probability of random failure of the MDAFWP on the affected unit, the frequency of seismic events requiring recovery of the TDAFWP is at most 1E-6/yr. Identification and recovery of the TDAFWPs is likely in this event (see below). In addition, the cross-tie from the opposite unit MDAFWP may be available, as would RCS bleed and feed capability. Any releases (due to core damage sequences developing from additional unrelated equipment failures) would not be expected to bypass containment. Therefore the potential risk reduction for enhancing the ruggedness of this equipment is not expected to justify the cost.
Identification and recovery of a TDAFWP overspeed trip activation following a seismic event is likely due to the numerous cues and procedural guidance available to the operators responding to the event: a) The procedure for visual inspection of equipment and structures after earthquake directs the operator to check local alarms, breakers and protective devices for actuation/trips for horizontal pumps. b) On any reactor trip, procedures direct verification of AFW flow. c) TDAFWP overspeed trip operation is annunciated in the Control Room. For example, for Unit 1, the alarm response procedure directs the operator to determine the cause of the trip, and refers the operator to the procedure for resetting the overspeed trip.
Diesel Generator (DG) Fuel Oil Storage Tanks (FOSTs) 122 and 124 Alternative tanks available The DG FOSTs are safety-related equipment and the D5 and D6 FOSTs were found to be seismically rugged in the IPEEE as were the Unit 1 and Unit 2 fuel oil transfer pumps and day tanks.
The 121 and 123 FOSTs were determined by the SQUG
program to be acceptable to SSE levels. Therefore, this equipment would be expected to remain available following an SSE event.
Responses to NRC Requests for Additional Information Dated October 23, 2008 28IPEEE Seismic Outlier (Section A.2.4.1.2)
IPEEE Disposition Basis Comments However, assuming the supply from the 122 and 124 tanks had failed due to failure of buried piping (the IPEEE concern), the affected DGs would still operate without operator action for 1 - 2
hours (IPEEE Section A.2.4.1.2). Four safety related storage tanks are provided for supplying fuel oil to the two diesel generator sets D1 and D2. Each tank is equipped with a transfer pump to pump fuel from the tank to the day tank of either DG set. The valve pit contains necessary valving and piping arrangements for transferring fuel oil from any one storage tank to any other tank. Procedures direct the performance of this transfer. Based on the discussion below, the likelihood of successful recovery of the fuel supply through operator action following the event is high. Assuming a 1E-1 probability of failure to restore the fuel oil supply to an affected EDG, and a 1E-1 probability of random failure of the unaffected EDG, the frequency of seismic events requiring recovery of the fuel oil supply to an EDG is at most 1E-6/yr. In addition, the cross-tie from the opposite unit AC buses and EDGs (performed from the Control Room) would be available. Even if the cross-tie failed, only one train of AC power is necessary for successful prevention of core damage. Any releases (due to core damage sequences developing from additional unrelated equipment failures) would not be expected to bypass containment. Therefore the potential risk reduction for enhancing the ruggedness of this equipment is not expected to justify the cost.
Identification and recovery of an affected DG fuel oil supply following a seismic event is likely due to the cues and procedural guidance available to the operators responding to the event: a) The procedure for visual inspection of equipment and structures after earthquake directs the operator to check for damage, leaking or flooding from low pressure storage tanks and connected piping, and buried piping. b) Procedures direct the transfer of fuel oil from any Unit 1 DG FOST or the heating boiler FOST.
Boric Acid (BA) transfer pumps Alternate supply available At the time of the IPEEE, the ECCS design was such that the initial suction supply for the high head SI pumps was from the Boric Acid Storage Tanks (BASTs). The normal suction supply
is now provided by the RWST. The BA transfer pumps' only function credited in the PRA is to supply BA from the BASTs for boration of the RCS following an ATWS event. This is one of a number of potential means of pr oviding long term shutdown of the reactor; its failure probability is dominated by failure of the operator to perform the actions. The overall long term shutdown function contributed to sequences containing less than 1% of the total internal events CDF for either unit, and less than 1/2 of 1% of the total internal events LERF for either unit (i.e., this function did not survive the SAMA Phase 1 screening process described in the ER Sections F.5.1.1 and F.5.1.2). Therefore, the potential Responses to NRC Requests for Additional Information Dated October 23, 2008 29IPEEE Seismic Outlier (Section A.2.4.1.2)
IPEEE Disposition Basis Comments risk reduction for enhancing the ruggedness of this equipment is not expected to justify the cost.
Charging Pumps 13 and 23 Alternative charging pumps available The availability of individual charging pumps is not a risk significant contributor to the internal events CDF or LERF risk metrics for either unit. No individual charging pump failure basic events survived the SAMA Phase 1 screening process described in the ER (Sections F.5.1.1 and F.5.1.2). Therefore, the potential risk reduction for enhancing the ruggedness of this equipment is not expected to justify the cost.
Panel 117 Alternate power normally available As stated in the IPEEE report, Section A.2.4.1.2, Panel 117 provides only a backup 120V AC supply function to other normally-energized AC panels. Therefore, the availability of Panel 117 is not a risk significant contributor to the internal events CDF or LERF risk metrics for either unit. No Panel 117 failure basic events survived the SAMA Phase 1 screening process described in the ER Sections F.5.1.1 and F.5.1.2. Therefore, the potential risk reduction for enhancing the ruggedness of this equipment is not expected to justify the cost. 121 Cooling Water (CL) pump Alternate pumps available Since the IPEEE was issued, the anchorage and shaft columns of the Diesel Cooling Water Pumps and the 121 Cooling Water Pump have been determined to have HCLPF capacities greater than 0.3g (the IPEEE RLE). Therefore, the potential risk reduction for enhancing the ruggedness of this equipment is not expected to justify the cost.
Condensate Storage Tanks (CSTs) 11, 21 and 22 Recovered through the use of alternate sources (e.g., Cooling Water) The CSTs are not qualified to the IPEEE RLE of 0.3g, but may survive the SSE. Calculations qualify the 21 and 22 CSTs to the SSE using SQUG methodology. Assuming the CSTs fail on the seismic event, and no operator action occurs to stop the AFW
pumps, the pumps will trip automatically on low suction pressure.
From the PINGP seismic hazard curve presented in NUREG-1488 Appendix A, the expected frequency of exceedance of the PINGP SSE (0.12g) is approximately 1E-4/yr. The Cooling Water suction supply lines and MOVs to the AFW pumps (MV-32025, MV-32026, MV-32027, and MV-32030) on both units are seismic category 1 equipment and would be expected to remain available following an SSE event, and were found to be seismically rugged to RLE in the IPEEE. These valves are operated from switches located in the control room. Successful operation of only one valve, supplying one AFW pump with suction from the CL system, and restart of the pump is required for successful delivery of AFW to at least one SG. Assuming a 1E-2 probability of operator failure to align at least one AFW pump to its suction supply and restart the pump from the control
room, and random failure of the pump of 1E-2, the frequency of seismic events involving an initial loss of heat sink is at most 2E-6/yr (1E-4*(1E-2 + 1E-2) = 2E-6/yr). Identification and recovery of failed pumps is likely in this event due to operator local investigation for equipment damage prompted by procedure (see TDAFWP discussion above). In addition, the cross-tie from the Responses to NRC Requests for Additional Information Dated October 23, 2008 30IPEEE Seismic Outlier (Section A.2.4.1.2)
IPEEE Disposition Basis Comments opposite unit MDAFWP may be available, and RCS bleed and feed capability would remain available. Therefore the frequency of a complete loss of decay heat removal leading to core damage on this event would be less than 1E-7/yr. Any releases (due to core damage sequences developing from additional unrelated equipment failures) would not be expected to bypass containment. Therefore the potential risk reduction for enhancing the ruggedness of this equipment is not expected to justify the cost.
Component Cooling (CC) pressure switches Alternate start signal available The CC pump pressure switches are not seismically qualified. Therefore, an automatic start of the standby CC pump (should the running pump fail) may not occur. If the seismic event results in a small LOCA, an SI-signal would be generated that would produce an automatic start signal for the pumps. However, assuming this condition does not exist, in this event the operators would be made aware of the status of the CC system pumps early in the event as the earthquake response procedure directs the operators to verify that at least one CC pump is running. Assuming the running CC pump stops on a seismically-induced loss of offsite power, it will restart following the safeguard 4kV bus load restoration permissive signal.
However, a low pressure signal will be required to restart the pump, which may not be received if the pressure switch has failed. If the pump fails to restart, a low flow/pressure condition will occur in the system requiring operator response. From the PINGP seismic hazard curve presented in NUREG-1488 Appendix A, the expected frequency of exceedance the PINGP SSE (0.12g) is approximately 1E-4/yr. Assuming a probability of 1E-2 for the running CC pump failure to start, and that the
standby pump pressure switch fails on the seismic event, operator response will be required to restart one pump. A Human Error Probability (HEP) of 1E-2 for operator action to start one CC pump from the control room to restore system pressure is assumed. This results in an expected frequency of loss of all CC pumps of roughly 1E-4*(1E-2 + 1E-2) = 2E-6/yr.
However, the charging system will remain available providing cooling to the RCP seals, and preventing loss of RCS inventory.
If Cooling Water (CL) is lost to the Unit 1 EDGs, then cross-tie of
the Unit 2 4kV power supplies to Unit 1 may be required to prevent RCP seal degradation (this is not an issue for Unit 2 as the Unit 2 EDGs are air-cooled). Assuming another 1E-2 for operator failure to cross-tie the power supplies yields an upper-
bound frequency of 2E-8/yr (2E-6*(1E-2) = 2E-8/yr) for core damage due to this event. Any releases (due to core damage sequences developing from additional unrelated equipment failures) would not be expected to bypass containment. Therefore the potential risk reduction for enhancing the ruggedness of this equipment is not expected to justify the cost. Responses to NRC Requests for Additional Information Dated October 23, 2008 31IPEEE Seismic Outlier (Section A.2.4.1.2)
IPEEE Disposition Basis Comments Diesel Driven Cooling Water (DDCL) pump pressure switches Alternative start signal available The DDCL pump pressure switches are not seismically qualified, but would likely chatter during such an event. Any chattering would likely result in actuation of the diesel-driven pump, a safe condition. Also, if the seismic event results in a small LOCA, an SI-signal would be generated that would produce an automatic start signal for the pumps. However, assuming these conditions do not exist, in this event the operators would be made aware of the condition of the CL system early in the event as managing the CL system flow is a major focus of the procedural response to an earthquake. Assuming the running horizontal motor-driven pumps stop on a seismically-induced loss of offsite power, a low flow/pressure condition will occur in the system requiring operator response. From the PINGP seismic hazard curve presented in NUREG-1488 Appendix A, the expected frequency of exceedance of the PINGP SSE (0.12g) is approximately 1E-4/yr. Assuming that the pressure switches fail on the seismic event, an HEP of 1E-2 for operator action to start 2/3 CL pumps from the control room to restore system pressure is assumed. Combining this with random pump failure probabilities of 1E-2 each results in an expected frequency of loss of all CL pumps of roughly 1E-4*[(1E-2) + 3*(1E-2) 2] = 1E-6/yr. In this event, equipment and procedural gui dance are available to prevent the loss of CL conditi on from deteriorating into an RCP seal LOCA condition. At least two charging pumps on
each unit would remain available to supply RCP seal
injection and seal cooling (only one is required to meet the
seal cooling function; howev er, an operator would have to restart the pump from the control room following the assumed loss of offsite power and load rejection/restoration sequence). Assuming the CL pumps are not eventually
restarted, failure of the operat or to restore a charging pump could result in an unrecoverable RCP seal LOCA due to the
unavailability of CL to support high head injection and
recirculation. Note that an SI-signal would be expected to occur on any significant RCP seal LOCA, and would
provide the automatic restart of the CL pumps necessary to recover from the event.
Assuming no recovery of CL pum ps in the short term, and successful operator response to restart charging pumps for
RCP seal injection flow, the eventual concern will be loss of
heat sink in the SGs (due to loss of CSTs on the seismic event and loss of the backup su pply from CL). This condition will drive the oper ators to a procedure for responding to a loss of secondar y heat sink. After all attempts to restore a means of providing secondary heat Responses to NRC Requests for Additional Information Dated October 23, 2008 32IPEEE Seismic Outlier (Section A.2.4.1.2)
IPEEE Disposition Basis Comments removal have failed, the operators are directed to attempt decay heat removal using RCS bleed and feed. However, the first step in this process is to manually actuate SI. This action will start the CL pumps necessary to support bleed and feed cooling and high head re circulation. Applying a 1E-2 probability to this sequenc e for failure of the operators to perform bleed and feed cooling per the emergency procedures results in an over all core damage frequency of (1E-6)*(1E-2) = 1E-8/yr. An y releases (due to core damage sequences developing from additional unrelated equipment failures) would not be expected to bypass containment (note that induced SGTR sequences developing from this event would have a total frequency of less than 1E-9/yr). Therefore the potential risk reduction for enhancing the ruggedness of this equipment is not
expected to justify the cost.
Components listed in Section A.
2.4.1.1 of the PINGP IPEEE pr ovide a summary of the SQUG outliers that pertain to the I PEEE scope. In a letter from NRC to Northern States Power dated August 5, 1998, Resolution of Unresolved Safety Issue (USI) A-46 for Prairie Island Nuclear Generating Plant, Units 1 and 2 (TAC NOS. M69474 and M69475), the NRC issued a Safety Evaluation stating that the NRC had received notification that all outliers had been resolved, except for four (4) equipment outliers. The four (4) remaining equipment outliers were committed to be resolved by Prairie Island during the Unit 2 outage in December 1998 and the Unit 1 outage in May 1999. Of those remaining equipment out liers, three (3) were related to components listed in section A.2.4.1.1 of the Prairie Island IPEEE. The equipment included control valves CV-39409, CV-39401, and Motor Control Center MCC-2LA2.
Per Attachment 2 of the letter sent to the NRC from NSP dat ed November 17, 1997, Response to Request for Additional Information on the Prairie Island Nuclear Generating Plant, Units 1 and 2, Resolution of Unresolved Safety Issue A-46 (TAC Nos. M69474 and M69475), NSP notified the NRC of equipment outliers, resolution descriptions, and resolution timeline, if not already completed. The acti ons taken to resolve the three outliers are described below and are consist ent with statements in the November 17, 1997 letter.
CV-39409 Control valve CV-39409 was identified as an outlier because contact with surrounding conduits could break the solenoid tap connecti on. The airline to valve CV-39409 was relocated such that the airline is greater than two (2) inches from other electrical conduits in the area. This modification was completed du ring the 1R20 refueling outage in May of 1999.
CV-39401 Control valve CV-39401 was identified as an outlier because contact with surrounding conduits could break the solenoid tap connection. The airline and associated solenoid valve for CV-39401 were rerouted so that the airline and solenoid valve are a minimum of two (2) Responses to NRC Requests for Additional Information Dated October 23, 2008 33 inches away from existing conduits. Also, the electrical junction box associated with the solenoid valve for CV-39401 was relocated such that the box is greater than two (2) inches from other electrical conduits in the area. These modifications were completed during the 1R20 refueling outage in May of 1999.
MCC-2LA2 Motor Control Center MCC-2LA2 was identified as an outlier because it was observed that the MCC rocked about its weak axis when bumped, making the welding at the base suspect. New angle support braces were in stalled at the base of MCC-2LA2 to increase the structural stability of the MCC. This modification was completed during the 2R19 refueling outage in November 1998.
Per the work completed as described above, all out liers identified in Sect ion A.2.4.1.1 of the Prairie Island IPEEE have been resolved. Aside from work completed, no additional procedure changes or training was requi red to close identified outliers.
- d. Discuss the results of the seismic IPEEE fr om the standpoint of po tential SAMAs for the SSCs with the lowest seismic margins, and provide an assessment of whether any SAMAs to increase the seismic capacity of these limiting components woul d be cost beneficial (i.e., improvements to the component cool water heat exchanger anchorage).
The seismic IPEEE for PINGP used a seismic margins approach in the identification of vulnerabilities to severe accidents. The focus of the analysis was on determining the survivability of key plant equipment and safety functions, and the assurance of available success paths for safe plant shutdown followi ng the RLE seismic event. Quantitative risk analysis techniques supporting the determinati on of CDF and LERF risk metrics were not performed. An analysis to quantit atively determine the potential decrease in dose risk to the public from improving the anc horage of the CC heat exchangers is currently not available.
In the initial IPEEE submittal, a 0.12g RLE (the SSE for PINGP) was used as the basis for the seismic margins analysis. In response to the IPEEE seismic RAI questions, the equipment on the Safe Shutdown Equipment List developed for the analysis was reviewed to a 0.3g RLE.
The evaluation at the 0.3g RLE concluded that all important safety functions could be accomplished following a seismic event. All of these functions were found to be supported by components with HCLPFs greater than or equal to 0.3g, with the exception of the Component Cooling (CC) heat exchangers. The CC heat exchangers HCLPFs of 0.
28g were considered to be very close to the 0.3g threshold, and we re thus considered to be adequate. With the exception of the CC heat exchangers (discussed below), based on the IPEEE analysis results and recommendations implemented, it was concluded that there is no benefit to be achieved from evaluation and implementation of additional SAMAs from a seismic risk perspective.
The RLE was assumed to result in the failure of plant systems that are not seismically rugged, such as the equipment supporting delivery of o ffsite power to the pl ant, and Instrument and Station Air system equipment. In addition, the analysis assumed the occurrence of a Responses to NRC Requests for Additional Information Dated October 23, 2008 34 concurrent small LOCA due to the seismic even
- t. This assumption is conservative, because all piping that interfaces with the RCS is considered to be seismically rugged. The Component Cooling (CC) heat excha ngers play a key role in the recovery from this postulated set of events. However, even if it is assumed that the RLE result s in loss of all four of the CC heat exchangers, equipment remain s available to support at least the containment function, such that the dose to the public from any offs ite releases from these events are small.
Figure 1 of the IPEEE RAI response for seismic issues 1 shows the success paths available for prevention of core damage following a seismic event according to the IPEEE Seismic Margin Analysis (SMA) methodology. If it is assumed that the CC heat exchanger function is failed on the seismic event, then the CC system function shown in the diagram is assumed to be failed. Although from the diagram it may appear that the CC function is required for success for both paths shown, this is not the case fo r the loss of offsite power (LOOP) success path.
In this case, core damage is prevented as AC power (through the onsite emergency diesel generator supply), DC power, Cooling Water (C L), Reactor Protection (RPS) and Control Rods, RCP seal injection through the Chemical and Volume Control S ystem (CVCS) charging pumps, and the Auxiliary Feedwater (AFW) system remain availabl
- e. The CC function, which is to provide cooling to the RCP seals, is accomplished by the CVCS System.
If a Small LOCA is conservatively assumed to occur with the seismic event, then core damage will be assumed to occur, because the re maining functions shown on the diagram all depend on the CC function. Ultim ately, this dependency comes fr om the requirement for a CC supply to the SI pump oil coolers and the RHR heat exchangers. However, even in this case, the capability for RCS depressurization and RWST injection with the RHR pumps remains available, such that the potential for early core dam age and vessel failure at high pressure is low. Also, the containment f an coil units remain available for long term containment pressure control. T herefore, the potential for signific ant offsite releases (early or late) from success paths that require the CC function is low.
As described above, an analysis to quantitatively determine the potential decrease in dose risk to the public from improv ing the anchorage of the CC heat exchangers is not available. While the existing anchorage of the CC heat exchangers does not ensure the survivability of these components at the 0.3g RLE, it is very cl ose (0.28g). Assumption of failure of all CC heat exchangers at the RLE is conservative. Also, simplifying and bounding assumptions made in the IPEEE seismic margins analysis, such as the assumption of a concurrent LOOP, loss of instrument air and small LOCA on occurr ence of the RLE, are conservative. Each of these assumed events would individually have a conditional probability of occurrence below 1.0; the conditional probabi lity of all of these events occurring w ould be significantly lower. In addition, as the charging function remains availabl e, the small LOCA of concern in this event would be one involving leakage gr eater than available charging pump makeup. Given the seismic capability of RCS equip ment, piping and piping connected to the RCS, a small LOCA of this size occurring following a seismic event is clearly not a certainty, even at the RLE.
1 Letter from NSP to NRC dated February 28, 2000, "Response to Request for Additional Information Regarding Report NSPLMI-96001, Individual Plant Examination of External Events (IPEEE), Related to Generic Letter 88-20" (ML003691712).
Responses to NRC Requests for Additional Information Dated October 23, 2008 35 A plant modification to improv e the anchorage of the CC heat ex changers to withstand higher level seismic events would be expensive (estimates for a similar projec t from another recent License Renewal applicant's Environmental Repor t indicate the costs could exceed $500 K).
Based on the above considerations, it is conc luded that the averted dose benefit achieved from this proposed modification would not e xceed its estimated implementation cost.
Responses to NRC Requests for Additional Information Dated October 23, 2008 36 RAI SAMA 4 ER Section F.3.5 indicates that the core r adionuclide inventory used in the MACCS2 analysis is based on results of a plant-specific calculation assuming a core average exposure of 50,000 MWD/MTU, combined with core inventory information from MACCS2 Sample Problem A adjusted to account for the PINGP power level. Describe t he plant specific calculation (which appears to be in addition to the calculation described in the updated safety analysis report (USAR)). Describe the purpose and developm ent of the additional adj ustment factor of 1.39 (based on differences between the PINGP USAR calcul ation and MACCS2 Sample Problem A values). Confirm that the resulting core inventory reflects the PINGP-specific fuel burnup/management as the plant is expected to be operated during the renewal period, including any planned fuel management changes (pow er uprates, extended burnup fuel, etc.).
As discussed in ER Section F.3.5, MACCS2 require s input for 60 nuclides. These 60 nuclides are listed in Table F.3-3. Plant specific core inventory values for 20 significant nuclides (including the Cs and I nuclides) required by MACCS 2 were available from data contained in the USAR. For the remaining 40 core invent ory nuclides, plant specific estimates were judged to be required.
In some past SAMA evaluations, the MACCS2 Samp le Problem A core inventory values were utilized in lieu of plant specific core inventories. For those studies, the MACCS2 Sample Problem A core inventories were adjusted by us ing a ratio to account for differences between the Sample Problem A core power level and the SAMA plant specific power level. It has become recognized that in addition to differences in core power levels, changes in fuel enrichment and core exposure between current industry practices and those assumed for Sample Problem A should be accounted for via a plant specific core inventory.
Since a Prairie Island plant specific core invent ory for 40 of the 60 nuclid es was not available, plant specific values for the 40 nuclides were estimated in the following manner:
- 1. The 60 MACCS2 Sample Problem A core inv entory values were adjusted to account for differences between the Sample Problem A power level of 3412 MW th and the Prairie Island power level of 1650 MW th. 2. For each of the 20 nuclide values cont ained in the USAR, a comparison was made between the USAR value and the adjusted Sample Problem A value. The difference between the USAR nuclide val ue and the adjusted Sample Pr oblem A value differed for each nuclide. 3. The average change between the USAR values and the adjusted Sample Problem A values was calculated for these 20 nuclide values. On average, the USAR nuclide values were approximately 39 percent hi gher than the adjusted Sample Problem A values. 4. This factor of 1.39 was then applied to the 40 adjusted Sample Problem A values to estimate the plant specific core inventory of these 40 nuclides.
The increase factor of 1.39 t hat was applied to the 40 adjusted Sample Problem A values was judged to adequately estimate the impacts associat ed with fuel enrichment and core exposure between the Sample Problem A core assumpti ons and those utilized by Prairie Island. Responses to NRC Requests for Additional Information Dated October 23, 2008 37 Although the change in core average exposure and f uel burnup strategies that make use of newer and more efficient fuel designs will have an impact on the radioisotopic source term, specific operating strategies and power uprates planned for the futu re are not fully realized at present. To capture this and other inherent uncertainties that are part of the SAMA methodology, the use of the 95 th percentile averted cost risk re sults for each Phase 2 SAMA was used to determine whether a particu lar SAMA was cost beneficial. The 95 th percentile results were meant to provi de a "bounding" assessment to determine those SAMAs that may be cost beneficial and worthy of a more detailed analysis via the utility's action tracking process for plant modifications.
Responses to NRC Requests for Additional Information Dated October 23, 2008 38 RAI SAMA 5.a Provide the following information with regard to the selection and screening of Phase I SAMA candidates:
- a. The top two events in the Level 1 importance listing (ER Table F.5-1a) involve failure of operator actions (Events OSLOCAXXCDY and OHRECIRCC2Y, with failure probabilities 1.9E-02 and 5.3E-02, respecti vely). Potential improvement s to operator training are mentioned in the table, but dism issed on the basis that there is a great deal of uncertainty regarding the operator failure probability estimates. Despite the uncertainties, improvement to operator trai ning would appear to be a potentially cost-beneficial SAMA given the high importance of t hese operator actions for both CDF and large early release frequency. In this regard prov ide the following: (1) a descrip tion of the current procedural guidance and training scope and fr equency, (2) the bases for t he human error probability values, including the role that timing, ex perience/training, and procedures play in determining these values, (3) a characterizati on of the uncertainty associated with these actions and discussion of why their uncertain ty may be greater than other events in the PRA, and (4) an evaluation of the costs and benefits of improving the training and/or procedures for these actions.
NSPM Response to RAI SAMA 5.a A summary of the operator actions is listed below:
0SLOCAXXCDY
This operator action involves failure of the operator to perform an RCS cooldown and depressurization after a small LOCA event with successful secondary cooling and safety injection actuation. If this action fails, the operator must perform high head recirculation to be successful. This event was applied to all small LOCA-like (small LOCA and pressurizer PORV LOCA) sequences.
0HRECIRCC2Y
- Operator Fails To Initiate High Head Recirculation Conditional on Failure of RCS Cooldown and Depressurization
This action involves the failure of the operator to initiate high head recirculation following a small LOCA conditional failure of the operator to perform RCS cooldown and depressurization for a small LOCA (operator action 0SLOCAXXCDY), or for a RCP seal LOCA event (0RCPLOCACDY, "Operator Fails to Cooldo wn and Depressurize RCS for an RCP Seal LOCA"). If the operator fails to perform this action, core dam age will occur. This operator action is a conditional operator action based on operator action 0HRE CIRCSMY , "Operator Fails to Initiate High Head Recirculation for a Small LOCA."
Part (1):
The Emergency Operating Procedures (EOPs) will be used by Operations to perform the two operator actions listed above. For 0SLOCAXXCDY, the execution procedure covers post- Responses to NRC Requests for Additional Information Dated October 23, 2008 39 LOCA cooldown and depressurization. For 0HRECIRCC2Y, the execution procedure covers transfer to recirculation.
For initial license training, simulator scenar ios are taught for post-LOCA cooldown and depressurization and transfer to high head recirculat ion. In addition, a classroom presentation is also given.
Continuing license training includes specific training tasks for both operator actions, including simulator and classroom training. Since both actions are standard EOP actions, they are trained on at least once during the 2 year training cycle in accordance with the 6-year training plan.
Part (2):
Operator action 0SLOCAXX CDY (Operator Fails To Perform RCS Cooldown and Depressurization on Small LOCA) involves fa ilure of the operator to perform an RCS cooldown and depressurization after a small LOCA event with successful secondary cooling and safety injection actuation. If this ac tion fails, the operator must perform high head recirculation to be successful.
Operator action 0HRECIRCC2Y (Operator Fails To Initiate High Head Recirculation Conditional on Failure of RCS Co oldown and Depressurization) involves the failure of the operator to initiate high head reci rculation following a small LOCA conditional on failure of the operator to perform RCS cooldown and depre ssurization for a small LOCA event (0SLOCAXXCDY). Since these two operator ac tions appear in the same SLOCA initiating cutset, 0HRECIRCC2Y is a conditional operat or action based on 0HRE CIRCSMY. The EPRI HRA Calculator was used to determine the Hu man Error Probability (HEP) associated with 0SLOCAXXCDY and 0HRECIRCSMY. The methodology used to determine the cognitive part of the HEP is quantified using Cause Based Decisi on Tree Methodology (CBDTM). CBDTM methodology is explained in EPRI TR-100259, "An Approach to the Analysis of Operator Actions in Probabilistic Risk Assessment." The execution part of the HEP was quantified using Technique for Human Error Rate Prediction (THERP). THERP methodology is explained in NUREG/CR-1278, "Handbook of Human Reliability Analysis With Emphasis on Nuclear Power Plant Application." Part (3):
Many factors influence the final Human Erro r Probability (HEP) value including cues and indications, timing analysis, dependencies (related human interactions), cognitive analysis, cognitive recovery and execution performance s haping factors. Various methods are also available to determine the HEP value such as the EPRI methods (HCR/ORE, Cause Based Decision Tree Method (CBDTM)) and the NR C methods (THERP/ASEP and SPAR-H).
Since credit is already taken for training in calculating the above HEPs, any further improvement in training for the HEP events listed above will have no benefit on improving the success of the operator actions.
There is always a degree of uncertainty associated with HEP estimates, but the improv ement in training benefits for this particular case would be within the range of uncertainty for these HEPs. In other words, the resolution of HEP methods is not Responses to NRC Requests for Additional Information Dated October 23, 2008 40precise enough to capture marginal improvement s, such as due to enhanced operator training when operator training is already fully credited.
Part (4):
Both of these operator actions are standard Emergency Operating Procedure (EOP) actions and are trained on at least once during a 2 year training cycle. The CBDTM is applicable to
EOP responses in the control room and the training branches are really only to mitigate unusual circumstances such as inaccurate instru mentation, inaccurate cues, unavailability of information required for diagnosis and complex dec ision logic. Standard operator actions such as these are not subject to these unusual circumstances and are not sensitive to the training mitigating factors in CBDTM. As a resu lt, any additional traini ng will add cost but little benefit in the HEP analysis.
Although additional training wo uld not provide benefit, the im portant PRA information is transmitted to the Training Depar tment to be incorporated into the Prairie Island Training Center procedure which provides instructions and guidance for using PRA information in operator training programs. Spec ifically, PRA insights are used in the classroom training and in the development of simulato r training and evaluation. The procedure identifies the top two operator actions for both units as 0SLOCAXXCDY and 0HRECIRCC2Y.
- b. ER Section F.5.1.5 indicates that two internal flood rela ted enhancements identified in the individual plant examination (Items 2 and 3 on page F.5-5) were implemented through piping modifications, design features, and periodic inspections, as described in Calculation ENG-ME-148, Rev. 1. The thrust of the argument appears to be that this has rendered the probability of cooling water system header rupture negligible. Provide a copy of this calculation/white paper. Justify that the potential enhancements would not be warranted given the dominant contributors to internal flooding CDF, as described in response to RAI 1.h.
NSPM Response to RAI SAMA 5.b A copy of ENG-ME-148, Revision 1, is included as . The objective of this paper is to document the qualifications, design featur es and periodic inspections in place which provide confidence that the probability of occurrence of a pipe rupture (double-ended guillotine break) is negligible. The break pos tulation is reviewed from a deterministic standpoint and is based on current Prairie Island lic ensing basis, plant material condition, and other factors.
The cooling water header piping was completely replaced during the two unit outage in November 1992. The new piping is 33 percent thicker (1/2" compared to the original thickness of 3/8"). The Cooling Water S ystem is a safety related system designed and constructed to Design Class I and QA Type 1 standards. These design and construction standards are much more stringent than are the standards used in industrial and fossil plant design and construction. Also, th e internal surface of the new header piping is coated with an epoxy coating to inhibit microbiol ogically induced corrosion (MIC). Responses to NRC Requests for Additional Information Dated October 23, 2008 41 In addition, it is likely that a substantial piping leak (which could lead to a larger piping failure) would be noticed by operators, e ngineering or maintenance staff, or security personnel who periodically walk through these rooms such that corrective action could be taken well before a break might occur.
As described in the response to RAI SAMA 1.h, the dominant internal flooding sequences for both units involve flooding of the 695' elevation of the Auxiliary Building. The worst case flooding scenario (which is assumed for all fl ooding events associated with this initiating event) is due to a Cooling Water (CL) header rupture in the Component Cooling Water (CC) heat exchanger area, which is assumed to fail one train of CC pumps on both units as they are located below the associated CL header in that room. This is considered a dual-unit initiating event. The other train of CC pumps will continue to f unction if operator action to identify and isolate the ruptur ed CL header prior to submergence of the CC pump electrical connections is successful. Failure of this action will also result in flooding beyond the CC pumps, impacting both trains of Safety Injection (SI) pumps, Residual Heat Removal (RHR) pumps, and Containment Spray (CS) pumps, as well as MCCs supporting the Charging pumps and other safeguards equipment. The core damage sequence involves the occurrence of the flooding initiati ng event followed by failure of the operators to isolate the break prior to loss of the sec ond train of CC pumps. This resu lts in loss of reactor coolant pump (RCP) seal cooling, which eventually leads to an unrecoverable RCP seal LOCA as the ECCS pumps have been impacted by the flooding event.
The operator action to isolate the Auxiliar y Building 695' elevation flooding source (0AB7FLDISLY) was identified in the Level 1 Importance List Revi ew for Unit 1 and Unit 2 (ER Tables F.5-1a and F.5-1b). According to the review for potential SA MAs for this event, several were identified:
Mitigation of this event can be accomplished via an automatic sump pump system to remove water if the operator fails to isolat e Zone 7 of the Auxiliary Bldg. (SAMA 13) Consider installing waterproof (EQ) equi pment (valves / level sensors) capable of automatically isolating the flooding source. (SAMA 6) Consider segregating this zone into 2 comp artments to reduce the impact of a flood on both trains of SI and RHR. (SAMA 6a)
As stated in ER Section F.5.1.
5, the IPE identified two inte rnal flood enhancements (Items 2 and 3 on page F.5-5). These enhancements are related to flooding in the Auxiliary Feedwater (AFW) Pump Room due to the CL header pipe break. However (as reflected in the response to RAI Question 1.h), AFW Pump Room flooding is no longer a significant contributor to the PRA results. Therefore, potential enhancements would not be warranted.
- c. ER Section F.5.1.7.
1 states that a recommendation from the seismic margins analysis was to restrain or remove wall hung ladders and scaffolding. Describe the actions taken in response to this recommendation.
Responses to NRC Requests for Additional Information Dated October 23, 2008 42 NSPM Response to RAI SAMA 5.c Per the PINGP IPEEE one of the recommendati ons from the seismic margins assessment was to "restrain or remove wall hung ladder s and scaffolding that are located near safety related equipment to reduce the impact of seis mically induced relay chatter." As noted in IPEEE Section A.2.2.4, "Findings from the Plant Walkdowns," scaffolding was found to be hung on the wall behind the D2 Diesel Generator Control P anel. Although damage to the panel and its anchorage due to the possible impact of the scaffolding was unlikely, it was thought an impact may cause relay chatter. Similarly, a wall-mounted ladder was found to be located behind 4160 VAC Bus 25. Like the D2 c ontrol panel, it was thought that if the ladder would fall off its wall-hooks due to earthquake motion, rela y chatter may result.
Currently, no scaffolding is stored near safety-re lated equipment. Scaffolding storage is controlled in accordance with a plant procedure, which states that temporary staging of materials, such as scaffolding, shall be consis tent with allowable floor loadings and storage areas shown in plant drawings
. Also, a plant procedure provides guidance on scaffolding construction and use, including requirements for clearances to safety-related equipment and seismic restraints to limit horizontal movement during a seismic event. With the guidance given in these procedures, the impact of scaffolding on safety related equipment is negligible.
For ladder use and storage, current practices ar e defined in a plant pr ocedure, which states that ladders shall be returned to storage racks or other designa ted storage locations, when not in use. In addition, a housekeeping and material condition procedure states that all portable ladders in an area (not in use) are to be secured at the proper ladder storage location and visually checked for safety concerns.
During a recent field walkdown, it was noted that ladders are still located near safety-related equipment such as 4160 VAC Bus 25 and D2. T he ladders are stored on plant storage racks per procedure; however, it was questioned whether additional re straints were warranted to secure the ladders. Investigation determined that there was no clear guidance for the location and construction of ladder storage. The conditi on has been entered into the corrective action program to further investi gate the issue and determine whet her current ladder storage standards are adequate.
- d. ER Section 4.17.1 identif ies five criteria for screening out Phase I SAMA candidates, whereas ER Section F.5.2 identifies two such criteria, one of which involves the use of engineering judgment and expect ed maximum cost and dose benefits. Clarify which criteria were actually used in the SAMA screening process.
NSPM Response to RAI SAMA 5.d Although the screening criteria listed may appear to be different between the two documents, they are meant to be equivalent with similar intent. Also, even though a particular screening criterion was listed, it does not imply that it was necessarily utilized, since it may not have been necessary or applicable. The following table attempts to resolve the apparent discrepancy between the two sections by showing their similarity. Responses to NRC Requests for Additional Information Dated October 23, 2008 43 ER Section F.5.2 ER Section 4.17.1 Applicability to the Plant: If a proposed SAMA does not apply to the Prairi e Island design, it is not retained. (1) Candidates not applicable to the PINGP design Engineering Judgment: Us ing extensive plant knowledge and sound engi neering judgment, potential SAMAs are evaluated based on their
expected maximum cost and dose benefits;
those that are deem ed not beneficial are screened from further analysis. (2) Candidates with no significant benefit in pressurized water reactors such as PINGP
(5) Candidates whose estimated implementation costs exceed the maximum averted cost-risk It was not deemed necessary to list a potential
SAMA candidate if the option has already been, or is planned to be, implemented, e.g., planned
replacement of steam generators on Unit 2.
(3) Candidates that have already been implemented at PINGP Table F.5-3 discusses the various SAMA options, and as applicable, recommends the
use of other SAMAs that could prove more
effective, e.g., SAMA 18 was dispositioned by
recommending the use of SAMA 15.
(4) Candidates with benefits that have been achieved using other
- e. For each screened Phase I SAMA candidate (i.e., SAMAs 1, 6, 6a, 7, 8, 10, 11, 13, 14, 16, 17, 18, 19a, 21, 23, 24) ident ify the criteria used to scr een the SAMA. If engineering judgment was used as the criter ia (as opposed to the criter ia provided in ER Section 4.17.1), provide the estimated cost and dose benefit values used in the screening decision for each SAMA, as well as the basis for the engineering judgment decision.
NSPM Response to RAI SAMA 5.e ER Table F.5-3 provides a description of how each SAMA was dispositioned in Phase I.
Those SAMAs that required a mo re detailed cost-benefit analysi s were evaluated in Section F.6. Also see the response for RAI 5.f below.
- f. ER Section F.7.2.1 identifies five Phase 1 SAMAs that were origin ally screened out but subsequently screened in and further evaluated as a result of an uncertainty assessment (i.e., SAMAs 1, 10, 17, 19a, and 21). Describe the process and criter ia used to identify these five SAMAs. Explain why an uncertain ty evaluation for the remaining 11 screened out SAMAs is not appropriate.
NSPM Response to RAI SAMA 5.f This response addresses both RAIs 5.e and 5.f: Responses to NRC Requests for Additional Information Dated October 23, 2008 44 Four of the five Phase 1 SAMAs (1, 10, 17, and 19a) were originally carried forward into the Phase 2 evaluation based on prel iminary implementatio n costs, but later refined estimates clearly made them not cost beneficial when compared with other Phase 1 SAMAs that were dispositioned as being too costly. Nonetheless, it was decided to retain their analysis by including them as a sensitivity calculation ra ther than delete the earlie r Phase 2 work. SAMA 21, although not seen as cost-beneficial, was retained as a sensitivity calculation only as an exercise to see what possible averted cost benefits might be realized since the SAMA option was viewed to have a large impact on LERF. The other 11 screened out Phase 1 SAMAs
were screened based on the implement ation cost being high and the perceived risk benefit as being low. The following table was developed to help clarify where in the ER each of the identified SAMAs was dispositioned.
SAMA Identifier License Renewal Section / Comments 1 Section F.7.2.1.1 6 Section F.5.2.1 6a Section F.5.2.2 7 Table F.5-3 8 Section F.5.2.3 10 Section F.7.2.1.2 11 Table F.5-3; SAMA 10 viewed as alternative to this SAMA 13 Section F.5.2.4 14 Table F.5-3 16 Table F.5-3 17 Section F.7.2.1.3 18 Table F.5-3; SAMA 15 viewed as alternative 19a Section F.7.2.1.4 21 Section F.7.2.1.5 23 Table F.5-3; SAMAs 5 and 19a viewed as alternatives 24 Table F.5-3; SAMAs 16, 17, 21, and 22 viewed as alternatives
- g. Provide additional description of the SAMA 6a barriers described in Section F.5.2.2 in order to better justify the cost estimate of $2M per unit.
NSPM Response to RAI SAMA 5.g As shown in USAR Figure 1.1-5, the critical equipment in the scope of SAMA 6a is all located on the same floor elevation of the Auxiliary Building. The equi pment involved includes (for each unit) two SI pumps, two CC pumps, severa l motor control centers, three charging pumps, and two RHR pumps located in pits below the floor level. The equipment is not
separated by flood-proof barrier s, and, for the CC pumps, all pumps from both units are located in the same large area.
Therefore, any modification to achieve the benefits of SAMA 6a would have to consist of a series of enc losures that surround in dividual pieces of equipment. Some enclosures may only consist of walls to protect from rising water, but others may need to be full covered enclosures to protec t from spray. At least 22 (11 per unit) Responses to NRC Requests for Additional Information Dated October 23, 2008 45individual, custom-designed enclosures would be required. Additional enclosures may also be required to protect specific instrumentation, MOVs, or other electrical devices.
Because the area of concern is congested and limited in size, and the equipment separation distance tends to be small, permanent barriers are generally not practical. Open access will continue to be needed for each component during periodic disassembly or replacement; permanent barriers that provide room for ma intenance are either not possible or would unreasonably restrict access to other equipm ent. Therefore, each individual equipment enclosure would have to be able to be constructed in relatively small sections that can be moved and assembled in restricted areas, and they would have to be disassembled easily to provide access for equipment operation, ma intenance or replacement. Simply pouring concrete walls around equipment is not an option. The enclosures would also have to be seismically designed and capable of being sealed to the floors. Provisions would also be needed to remove water that may leak from the component inside each enclosure to prevent flooding from even small leaks rendering inoperable the equipment that the enclosure is intended to protect. Floor drains located within proposed enclosures may have to be relocated or modified to provide backflow protection.
For the RHR pump pits, it may be possible to incr ease the heights of the existing curbs or build new higher curbs outside the existing curbs. However, higher curbs would still have to permit easy access to remove an d install the pit covers, and to move personnel, materials and equipment into and out of the pits during main tenance and inspections. The power operators used to remove and reinstall pit covers may have to be redesigned. The RHR pit curb design, therefore, is not necessarily straightforward.
The construction work to erect these enclosures would be difficult. Asse mbly would be labor-intensive. Special precautions would be requ ired during construction to avoid contacting and damaging the safety-related equipment each enclosure is intended to protect, as well as to protect other safety-related equipment in the vicinity.
In view of these considerations, it is reasonable to conclude that the cost of design, fabrication and construction of each enclosure, costs associ ated with future removal and replacement of each enclosure for equipment maintenance, and cost s of maintaining the sealed joints in each enclosure water tight, could easily reach $200,000 each, or more than $2,000,000 per unit.
Responses to NRC Requests for Additional Information Dated October 23, 2008 46 RAI SAMA 6.a Provide the following information with regard to the Phase II cost-b enefit evaluations:
- a. ER Section F.6 states that the PINGP-specific implemen tation cost estimates do not account for replacement power costs that may be incurred due to consequential shutdown time. Clarify whether contingency costs or inflation adjustments are included in the cost estimates. Describe the types of costs that are included within the estimated "life cycle" costs. NSPM Response to RAI SAMA 6.a Cost estimates for potential plant modificati ons identified in the SAMA analysis have been developed as order-of-magnitude cost estimates. Contingency cost or inflation adjustments were not included in these estimates. Each cost estimate is broken down into relevant work activities across the following major project phases: Study, Analysis, Design, Implementation, and Life Cycle.
Work activities associated with the various pr oject phases as descri bed below are considered with respect to the expanded SA MA project descriptions.
The 'Study' phase estimates account for the identification of ph ysical design change alternatives, identification of stakeholders, pre-conceptual desig n, assessment of impact on plant procedures, processes and programs, and a draft safety evaluation or licensing /
permitting assessment.
Estimates for the 'Analysis' phase of each projec t account for evaluations, calculations and analyses required to support the basis for the proj ect such as revisions to the plant heat balance or accident analyses.
The "Engineering and Design' phase estimates account for conceptual design, preliminary design and final design. This involves prep aration, review and approval of drawings, specifications, data sheets, design change packages, as well as various discipline engineering elements and engi neering program elements. Also included are evaluations, calculations and analyses required to support t he implementation of the design change such as piping analysis, pipe support calculations, structural load analyses, electrical circuit analyses and loading, cable tray loading, etc.
The 'Implementation' phase estimates account for procurement, materials management, work planning, installation, testing, return to operations and closeout. This involves maintenance services, construction services, craft labor, design engineering support, program engineering support and procurement services.
Estimates in the 'Life Cycle' phase accounts fo r labor and materials requ ired for maintaining plant equipment in operable condition for 20 years. Life cycle costs do not include any contingency or inflation adjustments. Life cy cle costs are costs related to ensuring the operability of the equipment.
Responses to NRC Requests for Additional Information Dated October 23, 2008 47 RAI SAMA 6.b
- b. For SAMA 2, ER Section F.6.1 indicates a $300K implement ation cost for each unit but provides no basis for this value. It appears t hat this SAMA would involve the upgrade of one site diesel-driven fire pump and the addition of the associated piping connections and starting circuitry. As such, the cost would be shared by each unit.
Provide additional information regarding the basis for the cost estimates for this SAMA.
Identify any other SAMAs that serve both units and whose costs are shared.
NSPM Response to RAI SAMA 6.b The $300k estimate for each unit credited the B.5.
B portable fire pump being connected to the cooling water system. The estimate also credited existing connections with operator actions to open valves, and nominal costs associated with procedure changes. However, additional analysis indicated that the B.
5.B Fire Protection System pum p capacity would be limited, and additional capacity would be needed. To meet the additional pumping capacity, a diesel driven pump could be installed for an estimated
$2.4 million between bot h units. The cost estimate is comparable to the cost of a similar installation at Palisades. This higher cost would screen this SAMA from being cost beneficial.
- c. For SAMA 20, ER Table F.5-3 indicates a
$313K implementation cost for each unit to change normally-open motor-operated valve to normally-closed, including a $100K "life cycle" cost. Describe the physical changes that are included in this cost estimate.
Elaborate on the each of the co st factors that contribute to this implementation cost.
NSPM Response to RAI SAMA 6.c A description of SAMA 20 and a breakdown of the cost factors are provided below:
Title: Close Low Head Injection MOVs to Prevent RCS Backflow to SI System
==
Description:==
Change the safety-related moto r-operated low head reactor vessel injection valves (one valve in each Emergency Core Cooling System train) from normally open to normally closed. Valves would need modifying by drilling a
hole in the upstream disk in order to e liminate any pressure locking concern.
Assumptions: Each valve will be placed in the closed position (or verified closed) by the control room operator prior to entering the appropriate Tech Spec MODE and each valve will receive, as it does pres ently, an "S" (safety injection) signal; therefore, in order to implement th is alternative, procedure and drawing changes are required. Assumptions include: The design requirements for the valve and its motor operator which were in effect at the time the valve was a normally open valve are still valid. Responses to NRC Requests for Additional Information Dated October 23, 2008 48 The current valve design will support the modification to eliminate any pressure locking concern. The valve MEDP (maximum expected differential pressure) and actuator will not be changed by this modification. Minor changes in the wedge friction factor may occur, but will not change the valve actuator or its settings PHASE ITEMRESOURCE FUNCTIONAL AREA ESTIMATE Study/Analyses 1 Contract Labor Engineering Design Studies $40,000 2 PINGP Support Engr / Ops / Lic $12,000 Design 3 Contract Labor Engr Design - Mech /
Civil $60,000 4 Contract Labor Engr Design - Elec /
I&C $60,000 5 PINGP Support Engr / Ops / Maint $40,000 Implement 6 Labor Maintenance / Construction $50,000 7 Contract Labor Engineering $2,000 8 Materials Material & Material Mgmt $1,000 9 PINGP Support Engr / Ops / Lic $3,000 Life Cycle 10 Labor Ops / Maint for 20 years $100,000 GRAND TOTAL $368,000 Note: This estimate is for one unit only. The cost estimate for the second unit would save approximately 30% on the Design Phase. Therefore, the total cost for the second unit is $258,000. The sum of the two costs is $626K, or an average of $313K per unit.
- d. For SAMA 22, it is stated t hat the PRA model does not take fu ll credit for the ability of the power-operated relief valve (PORV) accumulators, because their ability to supply sufficient air to support bleed and feed operation over the full range of reactor coolant system break sizes has not been verified (through testing or through engineering calc ulations). Describe the credit that is taken for the ac cumulators in the current model.
NSPM Response to RAI SAMA 6.d Basic events are included in the PRA to model t he failure probability of the air accumulators for the pressurizer PORV to be able to open t he valves for bleed and feed with the instrument air supply to the valves failed. The current failure probability is 0.1.
Responses to NRC Requests for Additional Information Dated October 23, 2008 49 RAI SAMA 6.e
- e. In ER Sections 4.17 and F.4.6, the modified MACR (MMACR) is indicated to be $1,114,000 and $2,980,000 for Unit 1 and 2, respec tively. In ER Section F.7.1 it is indicated to be $1,048,000 and $2,706,000. Address this discrepancy.
NSPM Response to RAI SAMA 6.e The correct values are $1,114,000 and $2,980,000 for Unit 1 and 2, respectively. The values listed in Section F.7.1 are the result of typographical erro rs. The MMACR values had been modified based on updated information, but the older values within Section F.7.1 were inadvertently not corrected. Th is section dealt with adjusting the Real Discount Rate (RDR) value from 3% to 7%. The end result is that this typographical error does not change any of the results or conclusions for any of the SAMA analyses or sensitivity cases.
Accordingly, the third paragraph in Section F.7.1 is hereby corrected to state the following, with changes shown in boldface:
The Phase II analysis was re-performed using the 7 percent RDR.
Implementation of the 7 percent RDR reduced the MMACR by 28.4 percent compared with the case where a 3 percent RDR was used.
This corresponds to a decr ease in the MMACR from
$1,114,000 to $798,000 for Unit 1 and from
$2,980,000 to $2,134,000 for Unit 2.
Additionally, the values in the tables of Section F.7.1 are hereby updated as follows, with changes shown in boldface: Unit 1 Summary of the Impact of the RDR Value on the Detailed SAMA Analyses SAMA ID Cost of Implementation Averted Cost Risk(3 percentRDR) Net Value(3 percentRDR) Averted Cost Risk(7 percentRDR) Net Value (7 percent RDR) Change inCost Effective-ness? 1 $4,250,000 $268,252 ($3,981,748)$192,168 ($4,057,832) No 2 $1,200,000 1 $123,376 ($1,076,624)$88,388 ($1,111,612) No 3 $250,000 $74,956 ($175,044) $53,700 ($196,300) No 5 $1,500,000 $75,942 ($1,424,058)$54,346 ($1,445,654) No 9 $62,500 $62,746 $246 $44,950 ($17,550)
Yes 10 $2,866,000 $46,870 ($2,819,130)$33,580 ($2,832,420) No 12 $900,000 $186,188 ($713,812) $133,376 ($766,624) No 15 $130,000 $0 ($130,000) $0 ($130,000) No 17 $2,362,000 $88,030 ($2,273,970)$63,004 ($2,298,996) No 19 $700,000 $60,330 ($639,670) $43,178 ($656,822) No 19a $1,935,000 $329,802 ($1,605,198)$236,168 ($1,698,832) No 20 $313,000 $53,910 ($259,090) $38,582 ($274,418) No 21 $3,000,000 $11,286 ($2,988,714)$8,082 ($2,991,918) No 22 $39,000 $15,350 ($23,650) $10,990 ($28,010) No 1Cost of implementation is revised as discussed in NSPM response to RAI SAMA 6.b.
Responses to NRC Requests for Additional Information Dated October 23, 2008 50Unit 2 Summary of the Impact of the RDR Value on the Detailed SAMA Analyses SAMA ID Cost of Implementation Averted Cost Risk(3 percentRDR) Net Value (3 percentRDR) Averted Cost Risk(7 percentRDR) Net Value (7 percent RDR) Change inCost Effective-ness? 1 $4,250,000 $270,474 ($3,979,526)$193,762 ($4,056,238) No 2 $1,200,000 1 $123,092 ($1,076,908)$88,180 ($1,111,820) No 3 $250,000 $76,654 ($173,346) $54,910 ($195,090) No 5 $1,500,000 $222,610 ($1,277,390)$159,310 ($1,340,690) No 9 $62,500 $62,918 $418 $45,070 ($17,430)
Yes 10 $2,866,000 $48,630 ($2,817,370)$34,838 ($2,831,162) No 12 $900,000 $302,132 ($597,868) $216,350 ($683,650) No 15 $130,000 $19,324 ($110,676) $13,842 ($116,158) No 17 $2,362,000 $488,118 ($1,873,882)$349,330 ($2,012,670) No 19 $700,000 $60,514 ($639,486) $43,308 ($656,692) No 19a $1,935,000 $929,586 ($1,005,414)$665,408 ($1,269,592) No 20 $313,000 $54,646 ($258,354) $39,106 ($273,894) No 21 $3,000,000 $12,518 ($2,987,482)$8,958 ($2,991,042) No 22 $39,000 $67,650 $28,650 $48,420 $9,420 No 1Cost of implementation is revised as discussed in NSPM response to RAI SAMA 6.b.
- f. ER Table F.3-7 contains a number of entries that are inconsistent with values reported elsewhere in the ER. Specifically, the Unit 1 CDF is indicated to 9.85E-6 per year, whereas a value of 9.79E-6 per year is r eported elsewhere. The Unit 2 dose-risk is indicated to be 8.37 person-rem per year, wher eas a value of 8.43 is reported elsewhere.
The offsite economic cost risk for Unit 1 and 2, is indicated to be 1.36E4 and 5.44E4, whereas values of 1.59E4 and 6.33E4 are reported elsewhere.
Address these discrepancies.
NSPM Response to RAI SAMA 6.f The Containment Event Tree (CET) seque nce frequencies were determined through quantification of the Boolean l ogic models and included delete-term operations to remove success-branch cutsets from the output at the sequence level. The CET sequences are mapped to release categories; to produce the release categor y frequencies presented in Table F.3-7, a simple summation of the appropr iate sequence frequencies was used. This introduces a small amount of over-prediction in the release category frequencies, as another delete-term operation on the combined sequence cutsets for mutually-exclusive sequences was not performed. Some of the release category frequency values shown on Table F.3-7 are, therefore, slightly higher than their actual values. The Unit 1 and Unit 2 CDF values presented in the table are also simple summations of the release category frequencies. As shown in the CDF for Unit 1, the sum of the release cat egory frequencies produces a CDF metric for Unit 1 that is approximately 6E
-8 (less than 1%) higher than the Boolean-logic quantified CDF value of 9.79E-6.
The difference in the Unit 2 CDF value is not noticeable to 3 Responses to NRC Requests for Additional Information Dated October 23, 2008 51significant digits, but is also less than 1% higher.
The slightly higher CDF values presented in Table F.3-7 were not used in t he SAMA quantification. The slightly higher release category frequencies were used, but as the differences are small, and it is the delta between release category values that is used as the basis fo r the SAMA evaluations, these differences are considered insignificant to the overall results of the evaluation.
Note that the release categories making up the LERF risk metric are more important to the SAMA results, as these categories are more likely to im pact onsite and offsite doses and cleanup costs. The over predi ction of the LERF metric produced by summing these release categories is less than 3/1000 of 1% for both units, which indicates that the actual frequencies for these release categories are very clos e to the approximations used in the analysis.
During performance of the Prairie Island anal ysis, three SECPOP2000 code errors were publicized, specifically:
- 1) incorrect column formatting of the output file, 2) incorrect 1997 economic database file end character resulting in the selection of data from wrong counties, and 3) gaps in the 1997 economic database numbering scheme resulting in the selection of data from wrong counties. All three errors were addressed and new MACCS2 results were generated. It was verified that these new results for MACCS2 served as the basis for all SAMA quantifications. However, the numbers that were presented in Table F.3-7 had not been updated to reflect the latest values from MACCS2.
Accordingly, ER Table F.3-7 is hereby co rrected as presented below, with changes shown in boldface. Coincidentally, the Unit 1 Dose Risk (2.94 p-rem/yr), at least to three significant figures, did not change when using the updated MACCS2 results, which is the reason why it is not shown in boldface.
Table F.3-7 MACCS2 Base Case Mean Results Source Term Release Category Dose (p-sv)(1) Offsite Economic Cost ($) Unit 1 Freq. (/yr) Unit 1 Dose-Risk (p-rem/yr)
(1) Unit 1 OECR ($/yr) Unit 2 Freq. (/yr) Unit 2 Dose-Risk (p-rem/ yr)
(1) Unit 2 OECR ($/yr) 1 H-XX-X 1.64E+01 3.39E+027.28E-061.19E-02 2.47E-03 8.52E-06 1.40E-02 2.89E-032 H-H2-E 2.11E+04 1.20E+102.32E-114.89E-05 2.78E-01 2.32E-11 4.89E-05 2.78E-013 L-H2-E 2.14E+04 1.32E+105.61E-081.20E-01 7.41E+026.52E-08 1.40E-01 8.60E+024 L-CL-E 3.40E+04 2.10E+108.40E-102.86E-03 1.76E+019.17E-10 3.12E-03 1.93E+015 H-OT-L 2.48E+03 5.70E+074.89E-091.21E-03 2.79E-01 5.87E-09 1.46E-03 3.35E-016 L-CC-L 2.23E+04 3.41E+092.82E-076.28E-01 9.61E+023.39E-07 7.56E-01 1.16E+037 H-DH-L 1.95E+02 1.22E+063.09E-086.03E-04 3.77E-02 3.14E-08 6.13E-04 3.83E-028 L-DH-L 6.22E+02 9.60E+061.92E-061.20E-01 1.85E+011.97E-06 1.22E-01 1.89E+01 9 SGTR 5.69E+04 5.03E+102.33E-071.32E+00 1.17E+041.17E-06 6.66E+00 5.89E+0410 ISLOCA 2.28E+05 7.47E+103.22E-087.35E-01 2.41E+033.22E-08 7.35E-01 2.41E+03FREQUENCY WEIGHTED TOTALS 9.85E-062.94E+00 1.59E+041.21E-05 8.43E+00 6.33E+04 (1) MAACS2 provides dose results in Sieverts (sv). The MAACS2 result is converted to rem (1 sv = 100 rem) for the Dose-Risk results to be used in Section F.4.
Responses to NRC Requests for Additional Information Dated October 23, 2008 52 RAI SAMA 6.g
- g. ER Section F.7.2 presents the approach used to address the impact of uncertainty on SAMA results. For PINGP, this approach involves quantifying the Level 1 model uncertainty (and uncertainty multiplier) separ ately for each SAMA evaluation case. (In previous licensee renewal uncertainty analys es, licensees determined and applied a single uncertainty multiplier based on the uncertainty distribution in the baseline risk model.) The ER indicates that for thos e SAMAs whose modeling required the addition of new basic events, no new uncertainty distributions were assigned since the design and implementation of the SAMA wa s defined by the analysis. It appears that this approach may have had the unintended consequences of narrowing the uncertainty for those SAMAs that provide a significant risk reduction (because the added basic events are point estimates, the more they show up in the cu tsets the tighter the distribution becomes.) In addition, the actual uncertainty is associated with the diffe rence between the base model and the model with the improvement. The appr oach used in the ER assigns that uncertainty distribution to the model with the improvement even though two different distributions are being subtract ed. As a result, the actual unc ertainty distribution may be broader than indicated in the ER. Demonstr ate that the approach used to estimate uncertainty is appropriate. Describe the impac t on SAMA results if a single uncertainty multiplier (based on the uncertainty in the baseline model) were used in lieu of the SAMA-specific uncertainty multipliers.
NSPM Response to RAI SAMA 6.g The approach used that accounted for the unce rtainty associated with each specific SAMA option on a case-by-case basis was deemed to be more precise in capturing the specific uncertainty associated with those particular generat ed cutsets. Although t he practice of using a single multiplier has been used for other License Renewal applications, the use of a single multiplier for the 95 th percentile utilizing baseline model CDF cutsets tends to provide a multiplier that may not necessarily represent the individual uncertainty associated with each particular SAMA. That is, in using a single multiplier, some SAMAs could be perceived as not being cost beneficial if the overall multiplier was too low. Likewise, an individual SAMA may be mistakenly perceived as being cost beneficial if t he single multiplier is too high. Therefore, it was deemed more appropria te to evaluate the 95 th percentile estimates using those cutsets that pertain to the actual SAMA of interest to provide for better resolution and a more refined estimate of the 95 th percentile cost benefits for each indivi dual SAMA. Theref ore, the use of individual multipliers based on each SAMA option's 95 th percentile results was considered technically sound.
However, in reviewing the PINGP application of the above process, where it was intended to isolate the uncertainty effects to each individual SAMA, it was found that the 95 th percentile result for each SAMA had been actually divided by the baseline CDF value. To provide a more accurate ratio of the 95 th to the mean estimate, the denominator should have been each SAMA's point estimate for CDF, not the baseli ne CDF. The revised results using each SAMA's CDF point estimate are pr ovided in the following tables.
The tables also reflect the cost correction for SAMA 2 discussed in the response to SAMA 6.b above. The resulting impact from these changes is that Unit 2 now shows SAMA 19a as potentially cost beneficial when using this corrected method. Responses to NRC Requests for Additional Information Dated October 23, 2008 53 Unit 1 95th Percentile Results Using Individual SAMA Uncertainty Multipliers SAMA ID Cost of Implementation Ratio of 95th to SAMA CDF Unit 1 Averted Cost-Risk Net Value SAMA 1 $4,250,000 2.89 $775,079 -$3,474,921 SAMA 2 $1,200,000 1 2.69 $332,481 -$867,519 SAMA 3 $250,000 2.75 $205,793 -$44,207 SAMA 5 $1,500,000 2.86 $216,922 -$1,283,078 SAMA 9 $62,500 2.87 $180,002 $117,502 SAMA 10 $2,866,000 2.84 $132,985 -$2,733,015 SAMA 12 $900,000 2.79 $519,433 -$380,567 SAMA 15 $130,000 2.90 $0 -$130,000 SAMA 17 $2,362,000 2.89 $254,417 -$2,107,583 SAMA 19 $700,000 2.86 $172,754 -$527,246 SAMA 19a $1,935,000 2.77 $914,173 -$1,020,827 SAMA 20 $313,000 2.85 $153,784 -$159,216 SAMA 21 $3,000,000 2.91 $32,882 -$2,967,118 SAMA 22 $39,000 2.89 $44,386 $5,386 1. Results reflect cost correction discussed in the response to RAI SAMA 6.b Unit 2 95th Percentile Results Using Individual SAMA Uncertainty Multipliers SAMA ID Cost of Implementation Ratio of 95th to SAMA CDF Unit 2 Averted Cost-Risk Net Value SAMA 1 $4,250,000 2.82 $763,219 -$3,486,781 SAMA 2 $1,200,000 1 2.79 $343,506 -$856,494 SAMA 3 $250,000 2.71 $207,943 -$42,057 SAMA 5 $1,500,000 2.89 $642,520 -$857,480 SAMA 9 $62,500 2.75 $173,012 $110,512 SAMA 10 $2,866,000 2.86 $138,918 -$2,727,082 SAMA 12 $900,000 2.92 $881,438 -$18,562 SAMA 15 $130,000 2.84 $54,901 -$75,099 SAMA 17 $2,362,000 2.86 $1,397,133 -$964,867 SAMA 19 $700,000 2.87 $173,931 -$526,069 SAMA 19a $1,935,000 2.74 $2,542,917 $607,917 SAMA 20 $313,000 2.85 $155,678 -$157,322 SAMA 21 $3,000,000 2.76 $34,610 -$2,965,390 SAMA 22 $39,000 2.84 $192,028 $153,028 1. Results reflect cost correction discussed in the response to RAI SAMA 6.b In response to the question involving the impact of using a single multiplier, the tables below show that when the baseline 95 th percentile estimate is divi ded by the respective unit's baseline CDF, the results show the same outcome with respect to those SAMAs that are cost Responses to NRC Requests for Additional Information Dated October 23, 2008 54 beneficial at this level of uncertainty. The tabl es also reflect the cost correction for SAMA 2 discussed in the response to RAI SAMA 6.b above.
Therefore, this exercise has shown for this particular SAMA evaluatio n that the two methods, when appropriately applied, produced similar results with regard to determining those SAMAs that are cost beneficial at the 95 th percentile.
Unit 1 95th Percentile Results Using Global Uncertainty Multiplier SAMA ID Cost of Implementation Ratio of 95th to Base CDF Unit 1 Averted Cost-Risk Net Value SAMA 1 $4,250,000 2.95 $791,490 -$3,458,510 SAMA 2 $1,200,000 1 2.95 $364,026 -$835,974 SAMA 3 $250,000 2.95 $221,161 -$28,839 SAMA 5 $1,500,000 2.95 $224,070 -$1,275,930 SAMA 9 $62,500 2.95 $185,135 $122,635 SAMA 10 $2,866,000 2.95 $138,292 -$2,727,708 SAMA 12 $900,000 2.95 $549,356 -$350,644 SAMA 15 $130,000 2.95 $0 -$130,000 SAMA 17 $2,362,000 2.95 $259,736 -$2,102,264 SAMA 19 $700,000 2.95 $178,006 -$521,994 SAMA 19a $1,935,000 2.95 $973,096 -$961,904 SAMA 20 $313,000 2.95 $159,064 -$153,936 SAMA 21 $3,000,000 2.95 $33,300 -$2,966,700 SAMA 22 $39,000 2.95 $45,291 $6,291 1. Results reflect cost correction discussed in the response to RAI SAMA 6.b
Unit 2 95th Percentile Results Using Global Uncertainty Multiplier SAMA ID Cost of Implementation Ratio of 95th to Base CDF Unit 2 Averted Cost-Risk Net Value SAMA 1 $4,250,000 2.78 $751,691 -$3,498,309 SAMA 2 $1,200,000 1 2.78 $342,092 -$857,908 SAMA 3 $250,000 2.78 $213,034 -$36,966 SAMA 5 $1,500,000 2.78 $618,669 -$881,331 SAMA 9 $62,500 2.78 $174,859 $112,359 SAMA 10 $2,866,000 2.78 $135,151 -$2,730,849 SAMA 12 $900,000 2.78 $839,673 -$60,327 SAMA 15 $130,000 2.78 $53,704 -$76,296 SAMA 17 $2,362,000 2.78 $1,356,558 -$1,005,442 SAMA 19 $700,000 2.78 $168,178 -$531,822 SAMA 19a $1,935,000 2.78 $2,583,469 $648,469 SAMA 20 $313,000 2.78 $151,870 -$161,130 SAMA 21 $3,000,000 2.78 $34,790 -$2,965,210 SAMA 22 $39,000 2.78 $188,010 $149,010 1. Results reflect cost correction discussed in the response to RAI SAMA 6.b Responses to NRC Requests for Additional Information Dated October 23, 2008 55 RAI SAMA 8.a For certain SAMAs considered in the ER, there may be lower-cost alternatives that could achieve much of the risk reduction at a lower co st. In this regard, discuss whether any lower-cost alternatives to those Phase II SAMAs considered in the ER would be viable and potentially cost-beneficial. Eval uate the following SAMAs or indicate if the particular SAMA has already been considered. If the latter, indicate whether the SAMA has been implemented or has been determined to not be cost-beneficial at PINGP.
- a. Procedure for manually controlling the degree of SG depr essurization and reclosing the SG PORVs in the event core damage is immi nent, in order to prevent or reduce the challenge to SG tube integrity.
NSPM Response to RAI SAMA 8.a Procedural guidance similar to th at suggested in this SAMA is already in place for events involving extreme damage to the plant (such as may occur during a security-related incident).
The Extreme Damage Mitigation Guideline (EDM G) for injecting wa ter into the steam generators includes the followi ng direction for Technical S upport Center (TSC) personnel:
Monitor conditions and be prepared to re commend closure of the Steam Generator (SG) Power Operated Relief Valves (PORVs) in the event core damage is imminent in order to prevent a challe nge to SG tube integrity.
Also, the Severe Accident Management Guideline (SAMG) procedure for injecting water into the steam generators provi des direction to the plant staff in re-establishing water flow to the SGs following a core damaging event. The proc edure requires that t he negative impacts of injecting water into the SGs be identified and evaluated. The procedure includes a table of negative impacts to consider and a listing of acti ons that can be taken to reduce or mitigate these impacts, if the decision is made to use this strategy. The negative impacts are described in detail, including how depressurizati on of the SGs (to allo w injection with lower pressure systems) can increase the potential for tube failure due to the higher differential pressures across the tubes.
The PINGP emergency response personnel (TSC and Operations staff) t hat respond to plant events requiring use of the Em ergency Operating Procedures ar e the same personnel that respond to events requiring implementation of the SAMGs and EDMGs. These personnel are trained in the use of these procedures in respons e to an event similar to that described above.
Due to the guidance to the operations and emergency response staff already in place, implementation of this proposed SAM A would have no beneficial impact.
- b. Procedure for enhancing manual operation of turbine-driven Auxiliary Feedwater (AFW) pumps including alternate water sources, and operator aids for using local flow indication to maintain SG level.
Responses to NRC Requests for Additional Information Dated October 23, 2008 56NSPM Response to RAI SAMA 8.b The use of alternate water sources is alr eady addressed in the post-accident procedures requiring operation of the AFW pumps, including the TDAFWP (e.g., Caution statements state that if Condensate Storage Tank (CST) level decreases to less than 10,000 gallons, then alternate water sources for AFW pumps will be nec essary). Local manual operation of the TDAFWP may be required during a Station Blackout (SBO) scenario. An abnormal operating procedure provides direction necessary to pe rform these actions. This procedure also contains a step notifying the oper ator to refer to other proc edures for possible sources of makeup to the CST (as CST water le vel is depleted by pump operation).
PINGP also maintains a special document called an "Alternate Source Book" (ASB) that provides information to personnel during off-normal plant operations and during implementation of SAMGs (Decision Maker, Evaluators and Implement ers) when developing strategies to mitigate a severe accident. The ASB provides information on resources for:
Electrical Power Supply Water Makeup Supply Pneumatic (Air) Supply, and Fission Product Scrubbing Supply In addition to the normal and emergency sources of water to the AFW pum ps called for in the EOPs, the ASB identifies a number of alternate on-site and external water sources for providing water to the SGs (see response to RAI SAMA 8.c below).
Also, the EDMG for manual operation of TDAFW pumps also cont ains procedural guidance similar to that suggested in this SAMA (see the response to RAI SAMA 8.a. above for a discussion of the potential for use of the EDMG procedures in response to other events).
Due to the guidance to the operations and emergency response staff already in place, implementation of this proposed SAM A would have no beneficial impact.
- c. Procedure and equipment for us ing a portable pump to provi de feedwater to the SGs with suction from either the external fire ring header or intake canal.
NSPM Response to RAI SAMA 8.c The suggested action is the subject of an EDMG procedure for injecting water into the steam generators. Such an action would be consid ered by the operators and emergency response personnel following an event invo lving loss of heat sink (see the response to RAI SAMA 8.a above for a discussion of the potential for use of the EDMG procedures in response to non-extreme damage scenarios). A portable, di esel-powered pump and instructions for connecting the pump to supply water to the SGs fr om various sources (including the river) is in place, and emergency response personnel hav e been trained on the use of the equipment and on the procedures.
Responses to NRC Requests for Additional Information Dated October 23, 2008 57The ASB also identifies the portable diesel pump as a potential means of delivering water to the SGs, and refers the reader to the EDMGs for guidance in impl ementing this strategy. In addition, the ASB identifies other potential water sources, including 1) connection to the fire main using fire hoses and 2) drawing water fr om the external circul ating water basins or Mississippi River using portable suction hoses and a fire pumper truck (supplied from the local fire station) delivering water to fire hydrant connections. These strategies would provide the water to the SGs via fire hoses connect ed to either the c ondensate system (condensate polisher strainer drains) or to the SG blowdo wn line drains.
Based on the procedures and equipment already avai lable, NSPM considers this strategy to have been already impl emented at PINGP.
- d. Procedure for recovering emergency diesel generators D-1 and D-2 by supplying alternate cooling from well water or fire water throug h a spool piece on the inlet to the emergency diesel generator heat exchangers.
NSPM Response to RAI SAMA 8.d Sections F.5.1.1 and F.5.1.2 of the ER describe the identifica tion of candidate SAMAs through the review of PRA basic event importance measures. In general, events having a Risk Reduction Worth (RRW) importance measure of 1.02 or greater were considered for SAMA identification. Failure of the Cooling Water (CL) system supply to the Unit 1 Emergency Diesel Generators (EDGs) was m odeled explicitly in the Rev.
2.2 SAMA PRA models (failure of active supply valves to open and remain open, common cause failure (CCF) to open, and failure of normally-open manual valves in the supply lines to remain open). The importance measures of all of these events in the Unit 1 and Unit 2 CDF cutsets show that this function is not providing a significant contribution to the overall PRA results (RRW measure is approximately 1.001 or less for all ev ents, including the CCF event).
In addition, an EDMG procedure provides t he procedural guidance recommended in this suggested SAMA (see the response to RAI SAMA 8.a above for a discussion of the potential for use of the EDMG procedures in response to non-extreme damage scenarios). The
strategy is to provide a means to cool ED G D1 or D2 independent of the Cooling Water system. An external cooling supply is pr ovided by removing the spool piece between the existing Cooling Water system supply control valve and t he diesel heat exchangers.
Therefore, as the impor tance of these events was previous ly evaluated to fall below the SAMA candidate screening criterion, and since the procedures are already in place, NSPM considers this strategy to have already been implemented at PINGP.
Responses to NRC Requests for Additional Information Dated October 23, 2008 58 RAI SAMA 8.e
- e. As an alternative to SAM A 15 (Portable DC Power Source), reconfiguring the non-safety main feedwater loads to be powered from DC Bus B rather than the addition of a portable DC power source for 21 AFW pump breaker control as proposed for SAMA 15.
NSPM Response to RAI SAMA 8.e ER Section F.6.6 showed that SAMA 15 had a sma ll positive net value. However, changing the DC power supplies to the Unit 2 Main Feedw ater system loads (instead of the associated motor-driven AFW pump) involves modifications to a larger set of components (pump breaker control power, feedwater regulat ing and bypass valves, etc.).
In addition, the suggested SAMA would extend the DC power asymmetry between the units to the Main Feedwater system (in addition to the AFW system) and additional costs for procedure changes and training would be required. The modification would cost signifi cantly more than the averted cost-risk estimate associated with SAMA 15 ($0 for Unit 1 and $19,324 for Unit 2) and would provide no additional risk benefit.
Therefore, the proposed SAMA would not be cost beneficial.
- f. Modifying the charging pump(s) electrical connections to enable re-powering from alternate 480VAC power supply (e.g., opposite unit) using pre-staged cables.
NSPM Response to RAI SAMA 8.f The important safety function su pported by the charging pumps as modeled in the PRA is to provide water for Reactor Coolant Pump (RCP) seal injection. RCP seal injection, one of the two available means of RCP seal cooling, can be provided by 1 of 3 charging pumps. In the event that seal injection is los t, the seal cooling function is pr ovided automatically by Reactor Coolant System (RCS) water fl owing through the seals after having been cooled by passing through the RCP thermal barrier heat exchanger (TBHX), which is cooled by the Component Cooling (CC) system. The onl y support system shared by t he charging pumps and the CC system pumps is AC power (both sets of pumps are supported by 4KV AC buses 15 and 16 on Unit 1, and 25 and 26 on Unit 2). Therefore, one means of losing RCP seal cooling is to lose safeguards AC power (station blackout).
However, unlike many other PWRs, this is not t he dominant contributor to the seal LOCA core damage frequency at PINGP. Non-SBO induced RCP seal LOCA sequences contribute approximately 26% of the Unit 1 CDF [22% of the Unit 2 CDF], while SBO-induced RCP seal LOCA sequences contribute only approximately 9% [8
%]. This is due to the ability to cross-tie the train-related 4kV buses between units, the availability of dedicated emergency diesel generators for each 4kV safeguards bus, and the differences between the EDG sets between the units (different cooling systems, different manufacturers, etc.).
The dominant sequences involving loss of all RCP seal cooling involve loss of Cooling Water (CL), which fails the CC
system and support for ECCS injection systems, and ultimately failure of the normal supply of water to the charging pumps from the Volume C ontrol Tank (VCT), followed by failure of the Responses to NRC Requests for Additional Information Dated October 23, 2008 59 transfer of the charging pump suction supply to the Refueling Water St orage Tank (RWST).
SAMAs 2, 3, 9, 10, 12, 19a were developed and evaluated to address the CL, CC, and RWST to charging pump suction supplies for these important sequences.
Both the charging pumps and the CC pumps for each unit are already each powered from two independent trains of safeguards 4kV AC power, and each of those trains of AC power can already be transferred to the opposite unit train-related 4kV bus. The charging pumps are powered from safeguards 480V AC power; pum ps 11, 12, and 13 [21, 22, and 23] are powered from 480V buses 121, 111, and 121 [221, 211 and 221] respectively via MCCs 1K2, 1K1, and 1K2 [2K2, 2K1, and 2K2], respectively. The CC pumps are powered from 4kV safeguards buses 15 [25] and 16 [26], respectively. Failures of individual 4kV buses, and failures of electrical equipment between the 4kV buses and the charging pumps (in which the 4kV buses remain available) are low probability events and do not result in loss of more than
two charging pumps. In these cases, at least one charging pump and one CC train remains available to support both means of RCP seal c ooling. For this reason, the basic event importance for all such equipment failures falls below the screening thresholds described in Sections F.5.1.1 and F.5.1.2 of the ER.
Therefore, implementation of the suggested SAMA would not be cost beneficial at PINGP.
- g. Installing a connection flange and valve on safety injection (SI) pump flow test return line to the refueling water storage tank to enable cross-connection of SI pumps to AFW piping via a temporary connection/hose.
NSPM Response to RAI SAMA 8.g As described in the response to RAI SAMA 8.
c above, a number of al ternative means of providing an independent supply of water to the steam generators in the event that all other water sources are unavailable have already been implemented via the ASB, EDMG procedures, and the SAMGs. Connec tion of the Safety Injection (SI) pumps to divert RWST water to the SGs on the same unit experiencing a loss of heat sink via temporary connections may not effectively reduce the risk of core dam age from this event. S upplying water to the SGs from the SI pumps on the opposite unit would involve a great er length of hose, and the hose required would have to able to withstand high pressures.
Given the alternate supplies and strategies already available to the operators, implementation of the suggested strategy would not be cost beneficial at PINGP.
- h. Modifying the charging and volume control system to allow cross-tie of the charging pumps from opposite unit using temporary connections.
Responses to NRC Requests for Additional Information Dated October 23, 2008 60NSPM Response to RAI SAMA 8.h The risk-significant function supported by th e charging pumps is to provide RCP seal injection, preventing an RCP seal leak from occurring. The most probable situation in which all three charging pumps fail is a single unit station blackout (SBO) event. Due to the ability to crosstie the train-related AC buses between units at PINGP, the potent ial for a single unit SBO to occur is lower than at single unit plant s and at multiple unit plants without this capability. Core damage sequences in which the charging pumps on the opposite unit may be available for cross-tie to the affected unit have a frequency of approx imately 2.3E-6/rx-yr on both units, and are dominated by non-SBO-related RCP seal LOCAs. This is considered an upper bound frequency; in some of these sequenc es power may be lost to the opposite unit standby charging pumps, or ot her equipment or operator failu res may prevent them from being used. These factors were not investigated fully for this response.
This RAI suggests that temporary connections coul d be used to make the necessary alternate flow path available to the other unit. However, the charging pumps are positive displacement pumps that develop the very high discharge pressu res necessary for injection into the RCS.
For personnel safety, it is assumed that this connection would involve a modification to install a hard-pipe line (meeting curr ent charging pump discharge piping standards) between the Unit 1 and Unit 2 charging pumps. At least one manual valve on either end would be required for isolation from the normally-o perating high-pressure charging system. Both of these valves would have to be opened to provide flow through the temporary connection pathway. The shortest path for the piping run would be to cross the Auxiliary Building 695' elevation floor in the overhead of the CC heat exchanger room between the units. A ssuming this minimum-distance pathway is available and can be used for the modification, roughly 100'-125' of high pressure piping would need to be installed.
If a (potentially optimistic) 1E-1 probability of operator failure to perform this local recovery action prior to development of an RCP seal LOCA is applied, then the core damage risk savings associated with this SAMA is approximat ely 2E-6/rx-yr on each unit. However, most of these core damage sequences would not bypass containment (AFW is generally available in these sequences, such that induced SGTR is not a factor).
SAMA 3 (Provide Alternate Flow path from RWST to Charging Pu mp Suction) is comparable to this SAMA both in terms of CDF reduction and impact to dominant core damage sequences and release categories. From t he ER Section F.7.2.3, the calculated averted cost-risk values for SAMA 3 were:
Unit Base Averted Cost-Risk (ACR) 95 th Percentile ACR Unit 1 $74,956 $179,894 Unit 2 $76,654 $183,970 Total $151,610 $363,864 SAMA 3 involved installing a bypass around t he motor-operated valve that must open to supply charging pump suction flow from the RWST upo n loss of VCT level. This line would include an air-operated valve, whereas the suggested SAMA investigated here would include two manual isolation valves. The additional, new piping installed un der SAMA 3 would need to be far shorter in length than would this SAMA, and the piping design and installation Responses to NRC Requests for Additional Information Dated October 23, 2008 61 requirements would be less as SAMA 3 involv ed installation on the suction side of the charging pumps. The SAMA 3 cost estimate was $250,000 per unit. If the proposed SAMA could be installed for this amoun t, then the modification would only be cost-beneficial at the 95 th percentile ACR for both units combined. Ho wever, based on the considerations outlined above, the cost to implement this modifica tion would be expected to exceed the SAMA 3 implementation costs. Theref ore, implementation of the suggested SAMA is not considered to be cost beneficial for PINGP.
- i. Purchase or manufacture of a gagging device that could be used to close a stuck-open SG safety value on the ruptured steam generator prior to core damage in SGTR events NSPM Response to RAI SAMA 8.i Two recent license renewal applicants addressed this SAMA as part of their analysis (either on initial submittal or in response to an RAI).
Beaver Valley found it to be cost beneficial at the upper bound of a sensitivity analysi s, whereas Indian Point found it to be cost beneficial in the base case. Both plants used a $50,000 esti mated implementation cost for this SAMA.
The Beaver Valley submittal stated that this SAMA involved procedure changes to require the operators to close the primary loop isolation valve associated with the ruptured SG, and then to gag the stuck open relief valve. This would reduce but not eliminate the radiation exposure to personnel received during the relief valve gagging operation. Like Indian Point, PINGP does not have RCS loop isolation valves. Ther efore, in addition to steam and heat-related risk to personnel, the gagging operation is assum ed to involve some additional amount of radiation exposure risk. The design and implement ation of any gagging device would have to address issues related to personnel safety.
Based on the PRA Rev. 2.2 SAMA results, the CDF associated with SGTR events in which gagging a stuck open relief valve may be of value is about 2E-7/yr for Unit 1 and 1E-6/yr for Unit 2. These sequences involve failure of the operators to cooldown and depressurize the RCS prior to stopping the primary-to-secondary leakage and prior to SG overfill, followed by failure of a SG relief valve to remain closed. The Indian Point RAI response also assumed that implementation of this SAM A would effectively eliminate t he risk of temperature-induced SGTR events. This produced a large positive net value for this SAMA.
As Indian Point is located near New York City, it may be expected t hat the dose savings might be very large there, whereas it might not be expected to be so large at Prairie Island where the local population is far lower. Howe ver, from the PINGP ER, Sect ions F.7.2.1.3 and F.7.2.1.4, SAMA-17 and SAMA-19a were found to work on the same set of core damage sequences as may be expected from this SAMA. SAMA 17 and SAMA 19a showed positive benefit to the SGTR avoided costs for both units (U2 more t han U1), although, overa ll, the numbers were negative based on the high costs of those modifications.
Given the relatively lower implementation cost associated with this SAMA, th is modification may be cost beneficial. This SAMA has been entered into the corrective action pr ogram for a more deta iled examination of viability and implementation cost.
Enclosure 2 PINGP Calculation EN G-ME-148, Revision 1
10 Pages PINGP Calculation EN G-ME-148, Revision 1 1
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