ML032170153
| ML032170153 | |
| Person / Time | |
|---|---|
| Site: | Salem, Oconee, Indian Point, Harris, Prairie Island  |
| Issue date: | 08/01/2003 |
| From: | Newberry S NRC/RES/DRAA |
| To: | Marsh L NRC/NRR/DLPM |
| References | |
| FOIA/PA-2004-0277, IR-00-003, IR-00-004, IR-00-008, IR-00-009, IR-01-003, IR-02-010, IR-99-010, SECY-03-0049 | |
| Download: ML032170153 (13) | |
Text
August 1, 2003 MEMORANDUM TO:
Ledyard B. Marsh, Director Division of Licensing Project Management Office of Nuclear Reactor Regulation FROM:
Scott F. Newberry, Director /RA/
Division of Risk Analysis and Applications Office of Nuclear Regulatory Research
SUBJECT:
TRANSMITTAL OF FINAL ASP ANALYSES (2000-2002 BACKLOG, SET 1)
This memorandum provides a set of eleven final Accident Sequence Precursor (ASP) analyses of operational events which occurred at various plants over the 2000 to early 2002 time frames.
As stated in SECY-03-0049 (dated March 31, 2003), there have been delays in issuing these analyses due to the ASP programs focus on several more complex and potentially risk important events. We have developed, and are currently implementing, a plan for the completion of the backlog of ASP analyses over the next year. Our goal is to return to a schedule of issuing preliminary ASP analyses within several months of the receipt of the Licensee Event Report (LER) and/or the Significance Determination Process (SDP) finding.
The issuance of this package of eleven analyses is part of our catchup effort.
Transmittal to licensees requested. We are requesting NRR/DLPM to send the final ASP analyses to the appropriate licensees for information. The analyses and a transmittal letter will be provided separately by the ASP Program Manager (Marc Harper) to the NRR ASP Program liaison (Margaret Kotzalas).
Final ASP analyses that have previously been peer reviewed. Attachment 1 describes five final ASP analyses for which preliminary ASP analyses have previously been sent out for NRR, Regional and licensee peer review. When applicable, resolutions of the peer review comments are included as part of the final ASP analysis package. The following ASP analyses are discussed in more detail in Attachment 1:
Unavailability of the turbine-driven emergency feedwater pump at Virgil Summer Nuclear Station (September 21, 2000) (LER 395/2000)
Inoperablity of turbine-driven auxiliary feedwater pump at Millstone 2 (August 23, 2000)
(LER No. 336/2001-005)
Loss of offsite power at Diablo Canyon Unit 1 (May 15, 2000) (LER 275/2000-004)
L. Marsh 2
Potential inoperability of a safety injection pump at Shearon Harris Unit 1 (September 2000)(LER 400/2000-007)
Potential inoperability of high pressure injection and auxiliary service water following a tornado at Oconee Units 1, 2 and 3 (April 2000) (Inspection Reports 50-269/270/287/00-04 and 01-09)
Final ASP analyses that do not require peer review. In the past, preliminary versions of ASP analyses were issued to the NRC Staff and the licensee for comment, and comments were resolved as part of the final analysis. In order to reduce the backlog of ASP analyses needing review and comment, we are issuing the non-controversial, lower risk ASP analyses as final documents. In the following events, our calculated change in core damage probability ( CDP) and dominant risk contributors are consistent with those in the SDP for the same events. Since these ASP analyses confirm the results of the SDPs, which have been reviewed by the NRR and Regional staff and the licensee, they are being issued as final products for information only.
Elimination of the comment resolution cycle for non-controversial ASP analyses allows RES to focus resources on the higher risk significant analyses. Attachment 2 describes the following events:
Degraded fire protection carbon dioxide system at Salem Unit 2 (February 14, 2000)
(Inspection Report 50-311/99-010)
Design deficiency of a switchgear room fire barrier at Shearon Harris (December 18, 2001) (Inspection Report 50-400/2000-09)
Degraded cooling water pump at Prairie Island (November 2000)
Non-seismic firewater piping at Oconee Units 1, 2 and 3 (April 30, 2001) (Inspection Reports 50-269/00-08, 50-270/00-08, and 50-287/00-08)
Degraded residual heat removal system at Shearon Harris (October 8, 2001) (LER 400/01-003)
Degraded Control Room fire barrier at Indian Point 2 (July 19, 2002) (Inspection Report 50-247/02-010)
Sensitive information. These ASP analyses are classified as SENSITIVE - NOT FOR PUBLIC DISCLOSURE. This classification is based on the guidance provided by the EDO in the memorandum to the Commission (dated April 4, 2002) concerning the release of information to the public that could provide significant assistance to support an act of terrorism.
In particular, Criteria 1 was determined to apply to ASP analysis reports:
Plant-specific information, generated by NRC, our licensees, or our contractors, that would clearly aid in planning an assault on a facility. An example might be drawings depicting the location of certain safety equipment within plant buildings. Examples may include portions of Final Safety Analysis Reports (FSARs),
Individual Plant Examination (IPE) material, and other risk and facility vulnerability information.
L. Marsh 3
This classification could change in the future based on revised Agency guidance and office (NRR and RES) procedures in response to the Staff Requirements Memorandum, Staff Requirements - COMSECY-02-0015 - Withholding Sensitive Homeland Security Information From the Public, dated April 4, 2002. Future changes in the transmittal of ASP analyses will be coordinated with the NRR ASP Program liaison.
If you have any questions about the individual analyses, please contact the reviewer for that analysis. For questions concerning the transmittal letter or the ASP Program, please call Gary DeMoss (415-6225).
L. Marsh 4
MEMORANDUM DATED: 8/1/03
SUBJECT:
TRANSMITTAL OF FINAL ASP ANALYSES Distribution:
OERAB RF MTschiltz, NRR WLanning, RI DRAA RF SRichards, NRR VMcCree, RIl File Center WBeckner, NRR BClayton, RIll MSnodderly, ACRS PWilson, NRR AHowell, RIV JStrosnider/AThadani, RES PKoltay, NRR ECobey, RI FEltawila, RES DCoe, NRR WRogers, RIl CAder, RES MKotzalas, NRR SBurgess, RIlI MMayfield, RES JClifford, NRR TPruett, RIV MCunningham, RES SMoore, NRR MWidmann, RIl JGiitter, RES WRuland, NRR SSchneider, RI EChelliah, RES HBerkow, NRR RMusser, RIl JHoughton, RES KCotton, NRR DOrr, RI DMarksberry, RES REnnis, NRR MShannon, RIl RBarrett, NRR CPatel, NRR DProuix, RIV SBlack, NRR RFretz, NRR JAdams, RIll DMathew, NRR LOlshan, NRR PHabighorst, RI BBoger, NRR Gshukla, NRR JLamb, NRR PMalano, NRR DOCUMENT NAME: A:\\MEMO-FINAL ASP TO ALL (MIKE).WPD To receive a copy of this document, indicate in the box: C = Copy wo/encl E = Copy w/encl N = No copy OFFICE OERAB E
OERAB E
OERAB E
OERAB E
DRAA E
NAME GDeMoss MHarper MCheok PBaranowsky SNewberry DATE 7/29/03 7/29/03 7/29/03 7/29/03 8/1/03 OFFICIAL RECORD COPY OAR in ADAMS? (Y or N)
Y Publicly Available? (Y or N)
Y Template Number: RES-006 Accession Number: ML032170153 RES File Code: 2C-3 ALL ASP ANALYSES ARE SENSITIVE AND MUST NOT BE MADE PUBLICALLY AVAILABLE IN ADAMS.
Attachment 1 FINAL ASP ANALYSES THAT HAVE RECEIVED PEER REVIEWS This attachment describes five final ASP analyses for which NRR, Regional, and licensee peer review has previously been performed. Where applicable, resolutions of peer review comments are included as part of the final ASP packages which are made available through ADAMS.
Turbine-driven Emergency Feedwater Pump discharge valve found isolated, Virgil Summer Nuclear Station (September 2000)
The condition was reported by LER No. 395/2000-06, dated October 18, 2000, and documented in NRC Inspection Report No. 50-395/00-05, dated October 20, 2000. The licensee provided comments to the preliminary Accident Sequence Precursor (ASP) Program analysis. We prepared the final analysis based on our review and evaluation of comments from the licensee and NRC staff on the preliminary analysis of this condition. No changes to the preliminary analysis were necessary.
Condition summary. The condition involved the unavailability of the turbine-driven emergency feedwater pump for more than 48 days due to isolation of the pump discharge valve. The results of the final analysis indicate that this condition was a precursor with an increase in core damage probability of 4.2 x 10-6.
SDP/ASP comparison. The risk significance associated with this condition was a WHITE finding under the SDP (Document EA-00-238 dated December 28, 2000). The quantitative results and the dominant contributors of the ASP analysis are similar to those in the SDP analysis.
The ASP analysis and the responses to comments can be found at ML031950525. If you have any questions about this analysis, please contact Erul Chelliah (415-6186).
Failure of the turbine-driven auxiliary feedwater pump during a routine surveillance test, Millstone 2 (August 2000)
The condition was reported by LER No. 336/2001-005, dated July 13, 2001, and documented in NRC Inspection Report No. 50-336/2000-011, dated October 30, 2000. We prepared the final analysis based on our review and evaluation of comments from the licensee on the preliminary analysis of this condition. The licensees comments led to minor changes in the exposure time estimates for the turbine-driven auxiliary feedwater (TDAFW) pump.
Condition Summary. This condition involved the unavailability of the TDAFW pump for 29 days. The results of the final analysis indicate that this condition is a precursor. This condition resulted in a CDP of 1.8 x 10-6.
2 SDP/ASP Comparison. Both the SDP and the ASP programs concluded that the importance of the issue was between 10-6 and 10-5 (a WHITE finding in the SDP). The SDP estimate was 3 x 10-6 and the ASP estimate was 1.8 x 10-6. The dominant contributors of the ASP analysis are similar to those in the SDP analysis.
The ASP analysis and the responses to comments can be found at ML031950218. If you have any questions about the analysis, please contact Marc Harper (415-6344).
Extended loss of offsite power to safety-related buses due to a 12kV bus fault, Diablo Canyon Unit 1 (May 2000)
This event was documented in licensee event report (LER) 275/2000-004-01, event date May 5, 2000. The licensee provided detailed comments to the preliminary ASP analysis. The final analysis is based on our review and evaluation of comments from the licensee and NRC staff.
Most of the comments were addressed by use of the Revision 3 SPAR model for Diablo Canyon and by use of sensitivity analyses.
Event summary. In this event, Unit 1 tripped because of an electrical phase-to-phase fault on the 12kV non-segregated phase bus between the Unit Auxiliary Transformer (UAT) 1-1 and 12kV Bus D and Bus E. Due to close proximity, the 12 kV fault created electrical arcing which damaged the nearby 4 kV start-up Bus E, which resulted in a loss of both offsite sources of 4 kV power. The reactor trip coupled with the loss of both power supplies to safety-related buses caused the emergency diesel generators (EDGs) to start. All three EDGs started and loaded successfully. Offsite power was restored to the vital and non-vital loads approximately 33 hours3.819444e-4 days <br />0.00917 hours <br />5.456349e-5 weeks <br />1.25565e-5 months <br /> after the unit trip. The conditional core damage frequency (CCDP) value in the final ASP report (4.2 x 10-4) using the Revision 3 SPAR model is similar to the preliminary analysis (3.1 x 10-4) that used the earlier Revision 2QA SPAR model. The results are very sensitive to the common cause failure parameters for the emergency diesel generators, which were calculated using standard ASP procedures.
SDP/ASP comparison. There is no SDP evaluation for this event since initiating events (with no performance deficiency identified) are not analyzed as part of the SDP process.
The ASP analysis and the responses to peer review comments can be found at ML031920094.
If you have any questions about the analysis, please contact Jim Houghton (415-6353).
Unavailability of the C train High Pressure Injection pump for a period of 59 days, Shearon Harris Unit 1 (September 2000)
This condition was documented in licensee event report (LER) 400/2000-007-02, event date September 4, 2000. The licensee did not provide comments to the preliminary ASP analysis.
However, in an April 2003 telephone conversation, the licensee informed the NRC that further analysis by the pump vendor determined that the pump was operable during the period in question.
3 Event Summary. During scheduled maintenance of the C charging safety injection pump, plant staff discovered that the pump outboard thrust bearing shoes were damaged. The licensee declared the pump inoperable. The preliminary ASP analysis was based on the licensee-submitted premise that the safety injection pump was inoperable for 59 days. A CDP of 4.2 x 10-6 was estimated for this condition. With the new information provided by the licensee on the pump operability, the final ASP program position is to reject the operating condition as a potential precursor because the CDP is less than 10-6.
SDP/ASP comparison. As in the case of the preliminary ASP analysis, the SDP was also based on the licensee-submitted premise that the safety injection pump was inoperable for 59 days. Both the SDP and the preliminary ASP analysis concluded that the event was in the WHITE range (10-6) and no significant differences between the ASP results and the SDP results were found.
The record of the NRC staff phone conversation with the licensee can be found at ML032040241. If you have any questions about the analysis, please contact Erul Chelliah (415-6186).
Potential Inoperability of High Pressure Injection and Station Auxiliary Service Water following a Tornado, Oconee Units 1, 2 and 3 (April 2000)
This condition was documented in NRC Inspection Reports 50-269/270/287/00-04 dated May 4, 2000 and 50-269/270/287/01-08, dated April 20, 2001.
Condition Summary. Two potential conditions occurred during an overlapping time period: the potential failure of the high-pressure injection (HPI) system following a tornado event; and the inability to align the station auxiliary service water (ASW) pump to supply lake water to the steam generators within 40 minutes following a design basis tornado. Both conditions have existed for a number of years. Changes in core damage probabilities ( CDP) of 5 x 10-6 for Unit 1 and 4 x 10-6 for Units 2 and 3 were calculated. The difference in CDP is caused by different reactor coolant pump seals in service at the time of the conditions.
SDP/ASP comparison. The risk significance associated with these conditions as analyzed under the SDP was a WHITE finding for all three units. A direct comparison with SDP results was not possible because both conditions were combined in the ASP analysis, whereas the SDP analyzed each condition individually (consistent with SDP procedures). The combined results of the two SDP evaluations and the dominant contributors do not differ from the ASP results.
The ASP analysis and responses to comments can be found at ML032100335. If you have any questions about the analysis, please contact Gary DeMoss (415-6225).
Attachment 2 FINAL ASP ANALYSES THAT DO NOT REQUIRE PEER REVIEW In the ASP analysis of the following events, the calculated risk and dominant risk contributors are consistent with those in the SDP. Since these ASP analyses confirm the results of the SDPs which have been reviewed by the NRR and Regional staff and the licensee, they are being issued as final products for information only. This attachment discusses ASP analyses of six of these events.
4160 Vac switchgear room carbon dioxide fire suppression system did not achieve a 50% concentration during testing, Salem Unit 2 (February 2000)
This condition was documented in NRC Inspection Report 50-311/99-010, dated February 14, 2000.
Condition summary. An NRC inspection identified that the carbon dioxide (CO2) concentration for the Salem Unit 2 4160 Vac switchgear room fire protection system did not reach or maintain the required concentration of 50 percent during testing. The CO2 system also did not meet its design requirement which requires the CO2 tanks to contain a sufficient supply of CO2 for two full discharges into the largest protected areas. This CO2 system was thus in a degraded condition such that the system may not have been fully effective in extinguishing fires. Based on the room and equipment geometry and location of intervening combustibles, this event was modeled as a fire-induced failure of all electrical equipment in 4160Vac division B and propagation of the fire through overhead cables to 4160Vac division C resulting in loss of equipment powered by the Division 1C 4160Vac bus. This condition resulted in a mean CDP of 1.0 x 10-6 with a 5% and 95% uncertainty bounds of 9.4 x 10-9 and 4.1 x 10-6 respectively.
SDP/ASP comparison. The result of the SDP analysis was a WHITE finding. The quantitative results and the dominant contributors of the SDP analysis are similar to those in the ASP analysis The ASP analysis of this event can be found at ML031920503. If you have any questions about the analysis, please contact Jim Houghton (415-6353).
Degraded fire barrier between the train B Switchgear Room and the Auxiliary Control Panel Room, Shearon Harris (December 2001)
This condition was documented in NRC Inspection Report 50-400/2000-09, dated December 18, 2001.
Condition summary. This event involves a degraded thermo-lag fire barrier that had existed for more than a one year period. A postulated fire in switchgear room B could propagate across the degraded fire barrier to the adjacent auxiliary control panel (ACP) room. In the ASP model, equipment assumed to be failed by the fire include all train B equipment in switchgear room B and some train A equipment in the ACP Room, including the auxiliary feedwater pump A and valve controls that
2 effect the operation of the auxiliary feedwater turbine-driven pump. This condition resulted in a CDP of 5.6 x 10-6.
SDP/ASP comparison. The quantitative results and the dominant contributors of the ASP analysis are similar to those in the SDP analysis (a WHITE finding).
The ASP analysis can be found at ML031920515. If you have any questions about the analysis, please contact Jim Houghton (415-6353).
Inoperability of Essential Service Water pumps caused by unqualified lubricating water supply to the pump shaft bearings, Prairie Island Units 1 and 2 (November 2000)
This condition was reported Condition summary. An inspection found that the support system that provides lubrication and cooling for the Cooling Water system was non-safety-related and was non-seismically qualified. During a postulated loss of offsite power event, power to the backwash system would be lost, and filter clogging would eventually result in a loss of the bearing lubrication for the Cooling Water system pumps. This condition could be risk significant for two scenarios: (1) during river conditions that would cause rapid plugging of the system filters; and (2) following seismic events. The ASP analysis therefore considered an initiating event involving a loss of offsite power concurrent with periods of adverse water turbidity in the Mississippi River, and a seismic initiating event. In addition, an analysis of an overlapping condition (potential for failure of safety-related Cooling Water system pumps from flooding due to failure of the Cooling Water pump air/vacuum valves) for the same year was conducted. These two conditions collectively resulted in a CDP of 1.3E-6.
SDP/ASP comparison. The SDP analysis for this operational condition resulted in a WHITE finding. The quantitative results and the dominant contributors of the SDP analysis are similar to those in the ASP analysis.
The ASP analysis can be found at ML031950389. If you have any questions about the analysis, please contact Erul Chelliah (415-6186).
Loss of High Pressure Injection and Component Cooling System pumps due postulated flooding in the Auxiliary Buildings, Oconee Nuclear Station Units 1, 2 and 3 (April 2001)
This condition was documented in NRC Inspection Reports 50-269/00-08, 50-270/00-08, and 50-287/00-08, dated April 30, 2001.
3 Condition summary. A non-seismic 16-inch fire system piping header transits through the auxiliary building and posed a potential flooding problem should the pipe break during a seismic event. The postulated flood could disable the high pressure injection (HPI) pumps and the component cooling system (CCS) pumps. This condition has existed since the 1970s and was analyzed using a duration of one year. The ASP results show a mean CDP of 4.3 x 10-6 for Unit 1 and 1.2 x 10-6 for Units 2 and 3. The 5% and 95% uncertainty bounds for the CDP for Unit 1 are 5.1 x 10-7 and 1.3 x 10-5 respectively; and for Units 2 and 3 are 1.4 x 10-7 and 3.6 x 10-6 respectively. The difference in results between the Units is due to the different reactor coolant pump seals installed at the units.
SDP/ASP comparison. The risk significance associated with this condition as analyzed by the SDP was a WHITE finding for Unit 1 and GREEN findings for Units 2 and 3. Although the ASP evaluation resulted in CDPs of greater than 10-6 for all three units, the CDP for Units 2 and 3 are essentially at the SDP GREEN-WHITE threshold. The small differences in the ASP and SDP approaches were reviewed, and we conclude that the quantitative results and the dominant contributors of the ASP analysis are similar to those in the SDP analysis. (Note: The basic difference between the methodologies was that the SDP used a random pipe rupture probability, while the ASP analysis used a seismic-induced flooding probability.)
The ASP analysis can be found at ML031920520. If you have any questions about the analysis, please contact Jim Houghton (415-6353).
Inoperability of Residual Heat Removal Train A for greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> due to foreign material in the sump, Shearon Harris (October 2001)
This condition was documented in Licensee Event Report (LER) 400/01-03, event date October 8, 2001 and in NRC Inspection Report 50-400/02-02 dated April 25, 2002.
Condition Summary. This analysis involves the potential failure of pump A of the residual heat removal (RHR) during safety injection or recirculation due to debris in the pumps suction lines.
A concurrent condition is the failure of an isolation valve in the RHR pump B suction (due to a cable lug not being properly installed). The ASP program analyzed these conditions over a duration of one year. The resultant mean CDP is 5.7 x 10-6, with a lower bound (5th percentile) of 2.8 x 10-6 and an upper bound (95th percentile) of 9.3 x 10-6.
SDP/ASP comparison. A comparison of ASP and SDP results shows that results are essentially the same, with both analysis in the WHITE or 10-6 range. As expected, the ASP analysis of the combined events resulted in a higher mean CDP (5.7 x 10-6) than the SDP Phase 3 analysis ( CDP of 2.9 x 10-6) which included only the debris clogging condition. In addition, the SDP analysis included an external events analysis with a CDP of 2.7 x 10-6, while the ASP analysis did not include contributions from external events. The small differences in the ASP and SDP approaches were reviewed, and we conclude that the quantitative results and the dominant contributors of the ASP analysis are similar to those in the SDP analysis.
The ASP analysis can be found at ML031920531. If you have any questions about the analysis, please contact Jim Houghton (415-6353).
4 Control Room west wall was not a fully qualified 3-hour fire barrier, Indian Point Unit 2 (July 2002)
The condition was documented in Inspection Report 50-247/02-010, dated July 19, 2002 and in final Significance Determination for this inspection report, dated November 8, 2002.
Condition summary. The inspection report identified a degradation of the control room fire barrier that could allow smoke and gases to infiltrate into the control room in the event of a turbine building fire. This would require evacuation of the control room and use of alternative safe shutdown systems. Appendix R requirements were not met for a 3-hour fire barrier.
This condition resulted in a mean CDP of 7.1 x 10-6. The uncertainty bounds are 1.3 x 10-7 (5th percentile) and 2.8 x 10-5 (95th percentile). The relative large range in uncertainty, especially in the lower bound 5th percentile estimate, is caused by the uncertainty in the fire initiating event frequency.
SDP/ASP comparison. The results of the ASP analysis are similar to those for the SDP (a WHITE finding). The Phase 2 SDP analysis does not result in a mean CDP or a list of dominant contributors that can be directly compared to the ASP analysis.
The ASP analysis can be found at ML031920545. If you have any questions about the analysis, please contact Jim Houghton (415-6353).
ROUTING AND TRANSMITTAL SLIP Date 8/6/03 TO: (Name, office symbol, room #, building, agency/post)
Initials Date
- 2. Marc Harper - Concur MCC for MH 7/29
- 3. Mike Cheok - Concur MCC 7/29
- 4. Pat Baranowsky - Concur PWB 7/29
- 5. Scott Newberry - Signature SFN 8/1
- 6. Nancy - Distribute - Fill in Template No., Accession No., and RES File Code NLL 8/1 7.
8.
9.
10.
Action File Note and Return Approval For Clearance Per Conversation As Requested For Correction Prepare Reply Circulate For Your Information See Me Comment Investigate X
Concurrence/Signature Coordination Justify REMARKS TRANSMITTAL OF FINAL ASP ANALYSES (2000-2002 BACKLOG, SET 1)
FROM: (Name, org. symbol, Agency/Post)
Room # - Bldg.
Phone #
Distribution WorksheetASP Preliminary Analysis
Title Name
- 1. OERAB Reading File OERAB RF
- 2. DRAA RF Reading File DRAA RF
- 3. File Center File Center
- 4. ACRS Coordinator (15 copies)
, ACRS
- 6. RES/DRAA Director SNewberry, RES
- 7. RES/DSARE FEltawila, RES
- 10. NRR/ADPT Associate Director BSheron, NRR
- 11. NRR/DE Director RBarrett, NRR
- 12. NRR/DSSA Director GHolahan, NRR
- 13. NRR/SPSB Chief MJohnson, NRR
- 15. NRR/ADIP Associate Director RBorchardt, NRR
- 16. NRR/RORP Chief WBeckner, NRR
- 17. NRR/DIPM Director BBoger, NRR
- 18. NRR/IIPB Chief CCarpenter, NRR
- 19. NRR/IIPB inspection program section chief DCoe, NRR
- 21. NRR Project Directorate (chief)
- 23. Regional Administrator
, RX
- 24. Region DRS Director
, RX (DRS)
- 25. Region SRA
, RX (SRA)
- 26. Region DRP Director
, RX (DRP)
- 27. Region DRP appropriate tech branch chief
, RX (DRP)
- 28. Senior Resident Inspection
, RX (SRI)