NL-08-057, Official Exhibit - ENT000380-00-BD01 - NL-08-057, Letter from F. Dacimo, Entergy, to NRC, Amendment 3 to License Renewal Application (LRA) (Mar. 24, 2008)
| ML12339A465 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 03/24/2008 |
| From: | Dacimo F Entergy Nuclear Northeast |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| SECY RAS | |
| References | |
| RAS 22150, 50-247-LR, 50-286-LR, ASLBP 07-858-03-LR-BD01, NL-08-057 | |
| Download: ML12339A465 (121) | |
Text
United States Nuclear Regulatory Commission Official Hearing Exhibit Entergy Nuclear Operations, Inc.
In the Matter of:
(Indian Point Nuclear Generating Units 2 and 3) c.\.~p..p. REGU<.,.;, ASLBP #: 07-858-03-LR-BD01 E~~:"
Docket #: 05000247 l 05000286
~ 0 Exhibit #: ENT000380-00-BD01 Identified: 10/15/2012
~ ~
~ , ~
Admitted: 10/15/2012 Withdrawn:
~ ~
" ****'" ,-d' Rejected:
'1'/1- Stricken:
ENT000380
.'
Other:
Submitted: March 30, 2012 Entergy Nuclear Northeast Indian Point Energy Center
~Entergy:
450 Broadway, GSB P.O. Box 249 Buchanan, NY 10511-0249 Tel (914) 788-2055 Fred Dacimo' Vice President License Renewal March 24, 2008 Re: Indian Point Units 2 & 3 Docket Nos. 50-247 & 50-286 NL-08-057 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001
SUBJECT:
Entergy Nuclear Operations Inc.
Indian Point Nuclear Generating Unit Nos. 2 & 3 Docket N'os. 50-247 and 50-286 '
Amendment 3to License Renewal Application (LRA)
REFERENCES:
- 1. Entergy ,Letter dated April 23, 2007, F. R. Dacimo to Document Control Desk, "License Renewal Application" (NL-07-039)
- 2. Entergy Letter dated April 23, 2007, F. R. Dacimo to Document Control Desk, "License Renewal Application Boundary Drawings (NL-07-040)
'3. Entergy Letter dated April 23, 2007, F. R. Dacimo to Document Control Desk, "License Renewal Application Environmental Report References (NL-07-041)
- 4. Entergy Letter dated October 11,2007, F. R, Dacimo to Document Control Desk, "License Renewal Application (LRA)" (NL-07-124)
- 5. Entergy Letter November 14, 2007, F. R, Dacimo to Document' Control Desk, "Supplement to License Renewal Application (LRA)
Environmental Report References" (NL-07-133)
Dear Sir o~ Madam:
In the referenced letters, Entergy Nuclear Operations, Inc. applied for renewal of the Indian Point Energy Center operating license.
This letter contains Amendment 3 of the License Renewal Application (LRA), which consists of five attachments. Attachment 1 consists of an amendment to the LRA to address Regional Inspection items. Attachment 2 consists of an amendment to address Audit Time Limited Aging
NL-08-057 NL-08-057 Docket Nos. 50-247 & & 50-286 ofý 2.
Page 2 of1t Analyses (TLAA) and other LRA amendment amendment items. Attachment Attachment 3 consists of a revision to the the commitments associated list of regulatory commitments associated with the LRA. Attachment Attachment 4 provides provides the responses responses to the questions questions raised by the NRC NRC team during the TLAATLAA portion of the LRA. Attachment Attachment 5 provides the responses responses to the questions questions raised by the NRC NRC team during the Aging Management Management Programs (AMP) portion of the LRA.
If you have any questions, or require additional If Robert Walpole additional information, please contact Mr. Robert Walpole at 914-734-6710.
at 914-734-6710.
II declare under und.5r penalty of perjury that the foregoing is true and correct. Executed on 3)d4\O 0 . .
Sin FreFr R.R. Dacimo Dacimo Vice President License Renewal Attachments: .
1.
- 1. Regional Inspection LRA Amendment Regional Amendment
)
- 4. TLAA Audit Database Database Report
- 5. AMP Audit Database Database Report cc: Mr. Samuel J. Collins, Regional Administrator, NRC NRC Region I Mr. Sherwin E. Turk, NRC Office of General General Counsel, Special Counsel Mr. Kenneth Engineering Review Kenneth Chang, NRC Branch Chief, Engineering Review Branch I Mr. Bo M.
M. Pham, NRC Environmental Environmental Project Manager Manager Mr. John Boska, NRR Senior Project Manager Manager Mr. Paul Eddy, NewNew York State Department of Public Service Service NRC Resident Resident Inspector's Office Office Mr. Paul D. Tonko, President, President, New York State Energy, Research, & Development Authority
& Development
ATTACHMENT 1 TO NL-OB-:057 ATTACHMENT NL-08-057 Inspection LRA Amendment Regional Inspection Amendment ENTERGY NUCLEAR OPERATIONS, ENTERGY NUCLEAR OPERATIONS, INC.
INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 &
NUCLEAR GENERATING &3 DOCKET NOS. 50-247 AND 50-286 50-286
NL-08-057 NL-08-057 Attachment Attachment II Docket Nos.
Docket Nos. 50-247 50-247 & & 50-286 50-286 Page Page 11 of of 99 Regional Inspection NRC Regional NRC Inspection License Renewal License Renewal Application Application Amendment Amendment Based on Based on discussions discussions with the the staff staff during during thethe NRC NRC inspection, inspection, the the LRA LRA is revised as is revised as described below.
described below. (underline (underline - added, added, strikethrough strikethrough - deleted) deleted)
Components installed Components installed to improve the flow of of water to the service water pump suction are added to the scope of license renewal and require require the following LRA LRA changes.
changes.
LRA Section 2.4.2, Water Control LRA Control Structures, Description, Structure,sixth Description, Intake Structure, sixth paragraph, paragraph, is revised revised as follows.
follows.
For both Unit 2 and both Unit and Unit structure is a massive intake structure Unit 3, the intake massive reinforced concrete structure, reinforced concrete structure, consisting of separate consisting separate concrete concrete cells. The base of the structure founded on rock and the structure is founded the exterior walls of the structure are reinforced exterior reinforced concrete. The service water strainer pit is aa reinforced concrete structure reinforced structure with the west wall being common to the intake intake structure. The The pit pit is covered with steel decking decking supported I-beams. The service supported on I-beams. service water bay enclosure enclosure consists of structural consists structural steel framing and grating. The Unit 3 service water stee! framing water pumppump bays are are supplied with fiberglass fiberglass baffling/grating bafflinq/qratinq partitions installed to improve the flow of water to thethe pump oumo suction and reduce hydraulic interaction hydraulic interaction between between the pumps.
CopoetsSbjc toAigMngmn eiw LR Tal .- ,WtrCnrlSrcue LRA Table 2.4-2, Water Control Structures Components Components SubjectSubject to Aging Management Management Review, Other Metals, Steel and Other Metals, is revisedrevised to add the following following line item.
Component Intended Function Intended Function Steel and Other Metals Baffling/qrating partition and support Baffling/grating Support for Criterion (a)(2) eguipment eguipment platform (steel portion)
Component Intended Function
' ',,'C:,
", C' "
, " ,i " ,
' , "
Other Materials OtherMaterials' , , ": ,,'
" , . ,
"
- , ' ,
e
- ,: "
, '
'"
Baffling/grating partition and support
'Baffling/grating support Support for Criterion (a)(2} (a)(2) eguipment equipment platform platform (fiberglass (fiberglass portion}
portion)
Section 3.5.2.1.2, Water LRA Section LRA Water Control Materials, is revised as follows.
Structures, Materials, Control Structures) follows.
NL-08-057 NL-08-057 Attachment Attachment II Docket Nos. 50-247 & & 50-286 Page 2 of 9 Water control components subject control structures components subject to aging management management review review are constructed of the following materials.
- carbon steel
- concrete concrete
- concrete brick concrete
- fiberglass fiberglass
- galvanized galvanized steel
- stainless steel LRA Section 3.5.2.1.4, Water Control Structures, Bulk Commodities, Materials, is revised as as
. follows.
commodities subject to aging Bulk commodities management review are constructed of the following aging management following materials.
- aluminum
- carbon steel
- cera blanket blanket
- cerafiber
- concrete concrete
- copper alloy
- elastomer elastomer
- fiberglass/calcium silicate fiberglass/calcium silicate
- galvanized steel galvanized
- mineral wool
- pyrocrete pyrocrete
- stainless steel LRA Table 3.5.2-2, Water Control Structural Structural Components Components and Commodities Commodities (IP2 and IP3), IP3), is revised revised to add the following line items.
3.5.2-2: Water Control Structures 3.5.2-2: Structural Components Structures Structural Components and Commodities Commodities (IP2 and IP3)
Structure and/or Structure Intended Aging Effect Aging Effect Aging NUREG-NUREG- Table 1 amnent/or and/or Intended unteondd Material Environment Requiring Management 1801 Vol.
Vol. Table Tem 1 Notes Material Environment Requiring Management 1801 Notes Component Component or Function Management Programs 2 Item Item Item Commodity Management Programs 2 Item Commodity Baffling/gqratin SNS Baffling/gratin Stainless Exposed to Loss of Structures Structures III.A6-11 III.A6-11 3.5.1-3.5.1- E
~
qg partition and steel fluid material material monitoring monitoring (T-21))
(T-21 47 supoort support environment environment platform (steel (steel portion) (IP3}
portion} (IP3)
NL-08-057 NL-08-057 Attachment I Docket Docket Nos. 50-247 & 50-286 Page 3 of 9 3.5.2-2: Water 3.5.2-2: Water Control Structures Structures Structural Components and Commodities Structural Components (IP2 and 1P3)
Commodities (1P2 IP3)
Structure Aging Effect Aging NUREG-and/or and/or Intended Intended Aging Effect Aging NUREG- Table 1 Function Material Material Environment Environment Requiring Requiring Management 1801 Management 1801 Vol. Item Notes Notes Component or Component Function Item Management Management Programs Item 2 Item Commodity Commodity Baffling/.ratin Baffling/gratin SNS Fiberglas Exposed Fiberglas Ex~osed to Loss of Structures Structures J
~
~artition and qg partition s§. fluid material material monitoring support su~~ort environment environment
~Iatform platform (fiberglass (fiberglass
~ortion) (I portion) (IP3)
P3)
LRA Table 3.5.2-4, Summary of Bulk Commodities, SummarySummary of Aging Management Management Review, is revised to add the following line items.
Table 3.5.2-4: Bulk Commodities Commodities Structure Aging Effect Aging NUREG-and/or and/or Intended Intended Aging Effect Aging NUREG- Table Table Function Material Material Environment Environment Requiring Requiring Management Management 1801 Vol. 1 Item Notes Notes Component or 1 Item Management Programs 2 Item Commodity Commodity Management Programs 2 Item 1 Anchor Anchor bolts SNS Stainless Stainless Exposed to Ex~osedto Loss of Structures Structures II1.A6-11 III.A6-11 3.5.1-3.5.1- gE steel fluid material monitoring monitoring ('-21)
(T-21 ) 47 47 environment environment Structural SNS Copper alloy CO~Qer allo~ Exposed Ex~osedtoto Loss of Structures II.A6-11 III.A6-11 3.5.1- . g 3.5.1- E bolting fluid material material monitoring monitoring T-J )
(T-21 47 47 environment environment
NL-08-057 NL-08-057 Attachment II Docket Nos. 50-247 Docket 50-247 & & 50-286 Page 4 of 9 LRA Section B.1.36, Structures Monitoring, Enhancements, Structures Monitoring, Enhancements, is revised following revised to include the following enhancement for elements 1 and 4.
enhancement Scope of Program
- 1. Scope Guidance will be added to the Structures Guidance Structures
- 4. Detection of Aging Effects Monitoring Program to inspect inaccessible Monitoring Program inaccessible concrete concrete areas that are exposed by excavation excavation for any reason. IPEG IPEC will also inaccessible concrete inspect inaccessible concrete areas in in environments where observed environments observed conditions in in accessible areas exposed to the same accessible same significant concrete environment indicate that significant concrete degradation is occurring.
degradation Enhance Monitoring Program Enhance the Structures Monitoring Program for IP2 and IP3 to perform perform inspection inspection of submerged concrete normally submerged concrete portions of the the intake structures intake structures at least once every 5 years.
baffling/grating partition and Also, inspect the baffling/grating support platform of the IP3 intake structure at least once every 5 years.
least Structures Monitoring LRA Section A.3.1.35, Structures Program, second paragraph, sixth bullet, is revised Monitoring Program, as follows.
- applicable structures Revise applicable structures monitoring procedures to inspect monitoring procedures inspect normally submerged submerged concrete portions portions of the intake structures structures at least least once every 5 years. Also, inspect the the baffling/grating partition baffling/grating platform of the intake structure at least once every 5 partition and support platform years.
The definition of a "selectedset"of components inspected by the Selective Leaching Programis The definition of a "selected set" of components inspected by the Selective Leaching Program is added to the LRA.
added LRA.
Program Description, is revised as follows.
LRA Section B.1.33, Program The Selective Leaching Program is aa new program that will ensure Leaching Program ensure the integrity of components components made of gray cast iron, bronze, brass, and other alloys exposed to raw water, treated water, made groundwater that may lead to selective leaching.
or groundwater leaching. The program one-time program will include a one-time visual inspection, inspection, hardness measurement measurement (where feasible feasible based on form and configuration) or mechanical inspection techniques of selected industry-accepted mechanical other industry-accepted components that may selected components be susceptible to selective selective leaching determine whether loss of material leaching to determine material due to selective selective leaching leaching is occurring, whether the process will affect the ability of the components to occurring, and whether to perform intended function through the period of extended operation.
perform their intended
NL-08-057 NL-08-057 Attachment II Docket Docket Nos. 50-247 & & 50-286 Page 5 of 9 The selected selected set or representative representative sample size will be based on Chapter 4 of EPRI document document 107514, 107514, Age Related Degradation Inspection Inspection Method and Demonstration, Demonstration, which outlines a method to determine determine the number of inspections required for 90% confidence confidence that 90%
90% of the the population does not experience population experience degradation degradation (90/90). Each Each group of components components with the the same material-environment material-environment combination is considered considered a separate separate population.
population.
The program program will be implemented implemented prior to the period extended operation.
period of extended The Diesel Diesel Fuel Fuel Monitoring Monitoring Program Program is is enhanced enhanced to include include sampling sampling activities activities when transferring transferringfuel oil with the onsite portable portable fuel oil tanker.
tanker.
LRA Section A.2.1.8, Diesel Fuel Monitoring Program, fourth paragraph, paragraph, is revised revised to add thethe following enhancement.
- Revise applicable applicable procedures procedures to direct sampling sampling of the onsite portable fuel oil tanker contents prior to transferring contents transferring the contents to the storage storage tanks.
LRA Section A.3.1.8, Diesel Fuel Monitoring Program, fourth paragraph, paragraph, is revised revised to add thethe following enhancement.
enhancement.
- Revise applicable procedures to direct sampling of the onsite portable applicable procedures portable fuel oil tanker tanker contents contents prior to transferring transferring the contents to the storage storage tanks.
LRA Section B.1.9, Diesel Fuel Monitoring, Enhancements, is revised to add the following.
Monitoring, Enhancements,
- 2. Preventive Preventive Actions procedures to direct Revise applicable procedures sampling sampling of the onsite portable fuel oil tanker contents prior to transferring the transferring the contents to the storage storage tanks.
The Diesel Diesel Fuel Fuel Monitoring Monitoring Program Programis is enhanced enhanced to add the security diesel diesel fuel oil storage storage tank to the list of tanks sampled quarterly quarterlyfor particulates, particulates,water, water, and and sediment.
sediment.
LRA Section A.2.1.8, Diesel Fuel Monitoring Program, fourth paragraph, Monitoring Program, paragraph, second bullet is revised as follows.
- Revise applicable applicable procedures to include quarterly quarterly sampling and analysis the analysis of the SBO/Appendix SBO/Appendix R diesel generator generator fuel oil day tank, security security diesel fuel oil storage storage tank, and security diesel fuel oil day tank. Particulates Particulates (filterable solids), water and sediment checks checks will be performed Filterable solids acceptance performed on the samples. Filterable acceptance criterion will be .::;,
<
10mg/l. Water 10mg/1. Water and sediment acceptance be < 0.05%.
acceptance criterion will be.::;,
"
NL-08-057 NL-08-0S7 Attachment Attachment I 50-247 &
Docket Nos. 50-247 Docket & 50-286 50-286 Page Page 6 of of 9 LRA LRA Section Section B.1.9, S.1.9, Diesel Diesel Fuel Fuel Monitoring, Enhancements, is revised as follows.
Monitoring, Enhancements, Preventive Actions
- 2. Preventive Actions IP2: Revise Revise applicable procedures to applicable procedures to include quarterly include quarterly sampling analysis of sampling and analysis Detection of Aging
- 4. Detection Aging Effects Effects the the SBO/Appendix SSO/Appendix R R diesel diesel generator generator fuel fuel
- 5. Monitoring Monitoring and Trending Trending oil day tank, security security diesel diesel fuel fuel oil storage storage tank, and security diesel fuel oil day tank.
and security Particulates (filterable Particulates (filterable solids),
solids), water andand checks will be performed sediment checks sediment performed on the the samples. Filterable Filterable solids acceptance acceptance criterion will be criterion be.$. < 10mg/1. Water and 10mg/l. Water and sediment acceptance criterion will be .$.
sediment acceptance <
0.05%
IP3: Revise Revise applicable procedures to applicable procedures to include quarterly include quarterly sampling and and analysis of the Appendix Appendix R R fuel oil storage tank.
oilstorage Particulates (filterable solids), water Particulates water andand sediment checks will be performed sediment performed on the the samples. Filterable solids acceptance acceptance criterion will be.$.
be < 10mg/1.
10mg/l. Water and sediment acceptance criterion will be .$.
sediment acceptance <
0.05%
0.05%
Water Chemistry The Water Control - Closed Chemistry Control Cooling Water Program Closed Cooling enhanced to monitor security Program is enhanced security generator and generator protection diesel and fire protection diesel cooling cooling water water for pH and glycol within specified by within limits specified EPRI guidelines.
EPRI guidelines.
LRA Section A.2.1.39, Water Chemistry Control - Closed Cooling Water Program, third paragraph, second bullet, is revised as follows.
paragraph,
- appropriate procedures Revise appropriate generator and fire protection procedures to maintain the security generator diesel cooling water system pH and glycol within limits specified by EPRI guidelines.
Section A.3.1.39, Water Chemistry Control - Closed Cooling Water Program, third LRA Section paragraph, first bullet, is revised as follows.
- Revise appropriate procedures to maintain security generator generator and fire protection diesel cooling water
, pH and glycol within limits specified by EPRI guidelines.
by EPRI
NL-08-057 NL-08-057 Attachment II Attachment Docket Docket Nos. 50-247 & & 50-286 Page 7 of 9 LRA Section B.1.40, Water Chemistry Control - Closed Cooling Water Water Program, Enhancements, Enhancements, is revised as follows.
- 2. Preventive Actions Actions appropriate procedures IP2: Revise appropriate procedures to
- 3. Parameters Monitored or maintain water chemistry of the the Inspected SBO/Appendix SBO/Appendix R diesel generator generator cooling cooling
- 5. Monitoring and Trending Trending system per EPRI guidelines.
- 6. Acceptance Criteria Acceptance Criteria appropriate procedures IP2: Revise appropriate procedures to generator and fire maintain the security generator fire*
protection diesel cooling water system pH and glycol within limits specified specified by EPRI guidelines.
appropriate procedures IP3: Revise appropriate procedures to maintain security generator and fire security generator fire protection diesel cooling water pH and and
~ within limits specified g!ycol specified by EPRI guidelines...
guidelines The Diesel Fuel Monitoring Diesel Fuel Monitoring Program Program is enhanced enhanced to perform perform thickness thickness measurements measurements on the IP3 EDG IP3 EDG fuel oil storage storage tanks.
tanks.
LRA Section A.3.1.8, Diesel Fuel Monitoring Program, Program, fourth paragraph, paragraph, third bullet, is revised revised as follows. .
- Revise Revise applicable applicable procedures procedures to include thickness measurement of the bottom surface thickness measurement surface of the EDG fuel oil day tanks, EDG fuel oil storage storage tanks, Appendix storage Appendix R fuel oil storage tank, and diesel diesel fire pump fuel oil storage storage tank once every ten years.
LRA Section B.1.9, Diesel Fuel Monitoring, Monitoring, Enhancements, Enhancements, is revised as follows.
NL-08-057 NL-08-0S7 Attachment Attachment I Docket Nos. 50-247& 50-286 50-247 & 50-286 Page 8 of 9
- 4. Detection Detection of Aging Effects Effects IP2: Revise applicable procedures to applicable procedures measurement of the include thickness measurement the bottom surface of the EDG fuel oil storage storage tanks, EDG fuel oil day tanks, SBOI Appendix R SBO/Appendix R diesel generator generator fuel day tank, GT1 gas turbine fuel oil storage storage tanks, and diesel fire pump fuel oil storage storage tank once every ten years.
IP3: Revise applicable applicable procedures to to include include thickness measurement measurement of the the bottom surface of the EDG fuel oil day tanks, EDG fuel oil storage tanks, Appendix Appendix R fuel oil storage tank, and diesel fire pump fuel oil storage tank once every ten years.
The Metal-Enclosed Metal-Enclosed Bus Inspection Inspection Program Program isis enhanced enhanced to clarify clarify the acceptance acceptance criteria criteria for enclosed bus internal metal enclosed inspections.
internal inspections.
LRA Section A.2.1.19, Metal-Enclosed Metal-Enclosed Bus Inspection Inspection Program, paragraph, is revised to Program, third parag'raph, to add the following enhancement.
0* Revise acceDtance criteria of appropriate Revise acceptance appropriate procedures forfor MEB internal internal visual inspections inspections indications of dust accumulation to include the absence of indications accumulation on the bus bar, on the the insulators, insulators, and in the the- duct, in addition to the absence absence of indications of moisture moisture intrusion into the duct.
LRA Section A.3.1.19, Metal-Enclosed Metal-Enclosed Bus Inspection Inspection Program, third paragraph, is revised to to add the following enhancement.
enhancement.
- Revise acceptance acceptance criteria of appropriate appropriate procedures procedures for MEB internal internal visual inspections inspections to include the absence absence of indications indications of dust accumulation accumulation on the bus bar, on the the insulators, and in the duct. in addition to the absence indications of moisture intrusion absence of indications intrusion into the duct.
NL-08-057 NL-08-057 Attachment II Docket Nos. 50-247 & & 50-286 50-286 Page 9 of 9 Metal-Enclosed Bus Inspection LRA Section B.1.20, Metal-Enclosed Inspection Program, Program, Enhancements, Enhancements, is revised as as follows.
- 6. Acceptance Acceptance Criteria Revise the acceptance acceptance criteria for MEB MEB inspections to include internal visual inspections the include the absence absence of indications of dust accumulation on the bus bar, on the accumulation the duct, in addition insulators, and in the duct. addition to the absence of indications indications of moisture moisture intrusion into the duct.
ATTACHMENT 2 TO NL-08-057 ATTACHMENT NL-08-057 Audit TLAA TLAA and other LRA Amendment Amendment ENTERGY NUCLEAR OPERATIONS, ENTERGY NUCLEAR OPERATIONS, INC.
INDIAN POINT NUCLEAR NUCLEAR GENERATING GENERATING UNIT UNIT NOS. 2 &
&3 DOCKET NOS. 50-247 AND 50-286
NL-08-057 NL-08-057 Attachment 2 Attachment Docket Nos. 50-247 Docket 50-247 & & 50-286 Page 11 of 28 28 INDIAN INDIAN POINT NUCLEAR NUCLEAR GENERATING GENERATING UNIT UNIT NOS.
NOS. 2 AND AND 33 LICENSE RENEWAL APPLICATION (LRA)
RENEWAL APPLICATION AMENDMENT AMENDMENT Audit Item 3 4.3-1, IP2 Analyzed LRA Table 4.3-1, Analyzed and Projected Number of Thermal Projected Number Thermal Cycles, Abnormal Conditions, is revised as follows.
Abnormal Conditions -
Numbers ofof Cycles Cycles GO-year 60-year Analyzed Numbers Analyzed as of of Projection Transient Condition Cycles 5/24/2005 as 9/28/20331 Projection Cycles
. 5/24/2005 9/28/2033 1 Reactor trip Reactor 400 239 3013 4-24 cooldown
- No excessive cooldown 230 230 88 88 1313 69 Excessive cooldown
- Excessive cooldown 160 160 148 148 1603
- Excessive Excessive cooldown cool down with safety 9 injection 10 10 33 103 LRA Table Table 4.3-1, 4.3-1, footnote 3, is revised as follows.
- 3. Total reactor trips were projected projected by summing summing the three sub-categories sub-categories of trips below this entry, not by projecting the totals. This gives a conservative conservative result due to the round up up on each of the three parts. The three sub-categories sub-categories of reactor trips were projected proiected based Deriod from 1999 on the six year period 1999 to 2005. The 336 daysdays that the unit was shutdown in 2000-2001 were not used in the Droiection.
projection.
Audit Item 7 LRA Section 4.3.1, 4.3.1, Class 1 Fatigue, Unit 2, third paragraph, paragraph, is revised as follows.
The 60-year projections projections for IP2 show the following.
following.
The only normal normal condition projecting above the analyzed analyzed number of cycles cycles is steady state fluctuations. The projection 106 while the analyzed projection is 1.5 x 106 analyzed number number is 1 x 10 1066 .. However, the the value shown in Table 4.3-1 is not based on actual cycles. The value shown shown in Table 4.3-1 4.3-1 for cYclc, for cyoles as of 10i31/1999 10/31/1999 is a calculated calculated value based on the th~ assumption assumption that the the transients transients occur occur at a constant constant rate that results in a number number of transients occurring occurring over 40 40
NL-08-057 NL-08-057 Attachment 2 Docket Nos. 50-247 & & 50-286 Page 2 of 28 28 years years based on this calculated calculated value is 1.5 1.5 times the analyzed analyzed number number of transients. In accordance Monitoring Program, accordance with the Fatigue Monitoring Program, prior to the period 'of of extended operation, corrective corrective actions will be taken to confirm that monitoring is not required or to establish appropriate appropriate monitoring.
monitoring.
Audit Item 8 LRA Table 4.3-5, CUFs CUrs for the IP2 ReactorReactor Vessel Internals, location location upper support plate plate assembly, is revised to replace replace the existing CUE CUF of 0.173 with 0.81.0.81.
Audit Items 9. 12. 12, 141 LRA Section 4.3.1.3, Pressurizer, second paragraph,paragraph, is revised as follows.
Section Section 4.3.1 projected projected the numbers numbers of cycles of tAe the all transients transients used in the pressurizer pressurizer determination, except steady fatigue determination, steady state oscillations, would remain below the numbers numbers analyzed analyzed by the stress report through the period extended operation.
period of extended operation. The stress report analyzed the 10J;.6 10E6 steady steady state oscillations only for condition N-415.1N-415.1 (b), where these oscillations determined to be "'Not oscillations were determined Not Significant." The projection projection of steady state oscillations oscillations therefore does not affectaffect the results of the stress report evaluation evaluation of N-415.1.
N-415.1.
Therefore Therefore the number of significant cycles will remain below that analyzed analyzed by the stress stress Thus the TLAA report. Thus TLA^A for determining determining that detailed fatigue analyses are not required required remnains valid for the remains the period of extended operation) operation in accorFdance assordanse with 10CFR64 0F=R64.21 .21(c)(1)(i).
(s)(1 )(i).
Audit Item 10 LRA Section 4.3.1, 4.3.1, Class 1 Fatigue, Unit 2, third paragraph, paragraph, second sub-paragraph, is revised second sub-paragraph, as follows.
Feedwator cycling Feed'Nater sysling ,, a replacement replasement steam generator generator design transient limitedlimited to to 18,30-0 18,300 cycles, sysles, does not appear on on Table 4.3 1.
- 1. The value of of 18,300 isthe projected is the projested value for for 10 40 years of steam years of steam generator operation. Since generator operation. the 1122 Sinse the IP2 replacement replasement steamtamgnerators generators Will 'Nill no~t not be ir er*FVce for 40 years at the end of the pe*rid in servise period of of extended operatioR, feedwate'r cyclin operation, feedwater sysling isnot expected is expested to to excGeed exseed the analyzed analyzed number number Ofof cycles.
sysles.
Feedwater Feedwater cycling is a transient transient that affects replacement steam generators. The steam affects the replacement generators are analyzed for 18,300 18,300 cycles. However, However, the 18,300 18,300 cycles cycles do not appear on Table 4.3-1 since these cycles have have no significant impact significant impact on the RCS. Instead, Table Table 4.3-1 includes includes 2000 feedwater feedwater cycles. These are cycles that are significant enough significant enough to affect affect the the RCS.
, Audit Item 11 Refer to Item 12 below below for revisions revisions to Tables 4.1-1 4.1-1 and 4.1-2 related to this item. item.
LRA Section 4.3.1.1, 4.3.1.1, Reactor Vessel, second paragraph, is revised as follows.
NL-08-057 NL-08-057 Attachment 2 Attachment Docket Nos. 50-247 & & 50-286 Page 3 of 28 28 Design cyclic loadings and thermal conditions conditions for the reactor reactor pressure pressLire vessel were originally originally defined in the design specifications defined specifications and analyzed in the original vessel stress reports.
These analyses have been occasionally revised, been occasionally revised, most recently for the extended power extended power uprate. These latest analyses are reflected in the current UFSAR UFSAR tables. As described described in in Section 4.3.1, projected numbers of transient cycles used for reactor vessel fatigue 4.3.1, the projected fatigue analyses remain remain nnI~~hi'edo ton analyzed within analyzed values. CRon...Uo.tly, rn*.t~wl~l Consequently, "rom vlidVl~y
.in thc TLAA the TLAA for tho ocio *
(^actF,,
(reactor ol fatiguc
....vessel fatigue of cx.tV.n.. d ooor,'* tion in.
analyses) based en those transients will remain valid for the period of extended operation in .. o codance..
accordanoe it~h 10 CFR
'Nith CPR 514.21 (.)(1)(i) 54.21 (c)(1 )(i) for both IP2,P2 and,P3.IPd. The effects of fatique fatigue on the the reactor vessel will be managed managed by the Fatigue MonitoringMonitoring Program in accordance accordance with 10 CFR 54.21 (c)(1)(iii) for both IP2 and IP3.
54.21(c)(1)(iii)
LRA Table 4.3-1 is revisedrevised to add footnote 4 to the "Loss of power" power" transient condition.
- 4. Loss of power transients involve the loss of the turbine qenerator generator bus followed by reactor and turbine trips. The reactor reactor vessel fatigue analyses do not identify loss of power as as unique unique transients.
Audit Items 12. 144 12,144 LRA tables 4.1-1 and 4.1-2 4.1-2 revised as follows.
'Table 4.1-1
'Table 4.1-1 1P2 TLAA List of IP2 TLAA and Resolution TLAA Description TLAA Description Resolution Option Resolution Section Reactor Vessel Vessel Neutron Embrittlement Embrittlement Analyses Analyses upper-shelf energy Charpy upper-shelf Analyses projected 4.2.2 4.2.2 10 CFR 54.21 (c)(1 )(ii)
(c)(1)(ii)
Pressure/temperature Pressure/temperature limits P-T limit curves managed 4.2.3 10 10 CFR 54.21 (c)(1 (c)(1)(iii)
)(iii)
Low temperature temperature overpressure LTOP LTOP limits managed managed 4.2.4 4.2.4 protection protection (L (LTOP)
TOP) 10CFR54.21 OCFR54.21 (c)(1 (c)(1)(iii)
)(iii)
Pressurized thermal shock Analysis projected projected 4.2.5 10 CFR 54.21 (c)(1 (c)(1)(ii)
)(ii)
NL-08-057 NL-08-057 Attachment 2 Docket Nos. 50-247 & 50-286 Page Page 4 of 28 Table 4.1-1 List of IP2 1P2 TLAA TLAA and Resolution Resolution TLAA Description TLAA Resolution Option Section Metal Fatigue Fatigue Analyses Analyses Reactor vessel Analy^,, romain ARalyses FeFRaiR valisvalid 4.3.1.1 4.3.1.1 10 CFR 10 ' 54.21 CpR 4.21 (G)(')()*
(0)(1 )(i)
Aging effects managed Aging 10 CFR 54.21 (c)(1)(iii)
(c}{1 Hiii}
Reactor vessel internals internals AnalyE.cs ARalyses r.main FeFRaiR valid"lalis 4.3.1.2 4.3.1.2 10 CFR 10 CpR 54.214-.I (4)(1)(")
(0)(1 )(i)
Aging effects Aging managed effects managed 10 CFR 54.21 10 54.21(c)(1)(iii)
(c}{1 Hiii}
Pressurizer Analyses remain ARalyses FeFRaiR valisvalid 4.3.1.3 4.3.1.3 10 10 CE=R 64.21 (G)(1)(4)
CpR 54.21(0)(1)(i)
Aging effects managed 10 54.21(c)(1)(iii) 10 CFR 54.21 (c}(1 Hiii}
Pressurizer insurge/outsurge insurge/outsurge Aalye. FeFRaiA
,A.Aalyses c*,na. IJaiis valid 4.3.1.3 4.3.1.3 transients transients 10 CFR 54.24 (0)(1 CpR 54.21 (*)(1)(*iHi)
Aging effects managed effects managed 10 CFR 54.21 10 54.21(c)(1)(iii)
(c}{1 }(iii}
Steam generator generator AnalyGeS
..
ARalyses main valid FeFRaiR valis 4.3.1.4 4.3.1.4 10 CFR CpR 54.21 (c)(1)(i)
(0)(1 )(i)
Aging effects managed effects managed 10 CFR 54.21 (c}(1(c)(1)(iii)
Hiii}
Reactor coolant Reactor coolant pump A nAly... FeFRaiR ARalyses I .alid valis 4.3.1.5 4.3.1.5 10 10 CFR 1 4.21 (*)(1)(i)
CpR 54.21 (0)(1 Hi)
Aging Aging effects effects managed managed 10 CFR 54.21 (c}(1 (c)(1)(iii)
}(iii}
Control rod drive mechanisms mechanisms Analyses ARalyses r.main valid FeFRaiR IJaiis 4.3.1.6 4.3.1.6
- 10 C;FR CpR 54.21 (c)(1)(i)
(0)(1 )(i)
Aginq Aging effects effects managed 10 CFR 54.21 (c}{1 (c)(1)(iii)
}{iii}
NL-08-057 NL-08-057 Attachment 2 Nos. 50-247 &
Docket Nos. & 50-286 Page 5 of 28 Page 28 4.1-1 Table 4.1-1 IP2 TLAA and Resolution List of IP2 Resolution TLAA Description Resolution Option Section Regenerative letdown Regenerative letdown heatheat Analycs FeFRaiR ARalyses remain llalia 4valid 4.3.1.7 4.3.1.7 exchanger CFR 64.21 10 GrR 51.21(c)(1)(,
(0)(1 )(i))
Aging effects effects managed 10 CFR 54.21 (c}(1 (c)(1)(iii)
)(iii)
Class 1 piping and in-line Analys.
.,,-,,. FeFRaiR ARalyses ,alid valia 4.3.1.8 4.3.1.8 components-ANSI 831.1 components-ANSI B31.1 piping 10 C FR 64.21 0Q GrR R54.21c) (0)(1 )(i).'i Aging effects Aging managed effects managed 10 CFR 54.21 (c)(1)(iii)
Class 1 piping and in-line Ana^Ysc ARalyses rc....
FeFRaiR valid valia 4.3.1.8 4.3.1.8 components-pressurizer surge components-pressurizer 10 CFR 64.21((0)(1 GrR 64.21 ,)(1)(i)
)(i) line Aging Aging effects managed managed 10 CFR 54.21 (c}(1 (c)(1)(iii)
)(iii}
Class 1 piping and in-line Analyes ARalyses remain FeFRaiR valid
'Ialia 4.3.1.8 4.3.1.8 components-thermowells components-thermowells 10 CFR GrR 54.21 (c)(1 )(*
64.21 (0)(1 )(i))
Aging effects managed Aging effects managed 10 CFR 10 CFR 54.21 54.21(c)(1)(iii)
(c}(1 )(iii}
Class 1 piping and in-line in-line Analysis will be updated updated as 4.3.1.8 4.3.1.8 components -charging components -charging system environmental fatigue part of environmental fatigue evaluation.
evaluation. See Section Section 4.3.3.
Class 1 piping and and in-line in-line Analys,.
ARalyses r.main FeFRaiR valid "alia 4.3.1.8 4.3.1.8 components-loop 3 accumulator components-loop accumulator 10 10 CF-R GrR 54.21c)1)i 64.21 (0)(1 )(i) nozzle nozzle Aging Aging effects managed managed 10 10 CFR 54.21(c)(1)(iii) 54.21 (c}(1 )(iii}
Non-Class Non-Class 1 piping and and in-line Analyses Analyses remain remain valid valid 4.3.2 components components 10 10 CFR 54.21 54.21(c)(1)(i)
(c)(1 )(i)
NOR-Class NeR Glass 1, ReR pipn 1, non !3i!3iRj Analyse ARalyses r4min3ali FeFRaiR "alia ~
cOmpOnent-oeFfl!3eReRts residual,.eat Fesiaual heat 10 10 CFR GrR 51.21 (G)(1),(1 64.21 (0)(1 )(i) removal heat FeFReval heat exchanger e*ohaRjeF Effects Effects of reactor water water Aging Aging effect effect managed managed 4.3.3 4.3.3 environment environment on fatigue life 10 10 CFR 54.21 (c)(1)(iii)
(c)(1 )(iii)
NL-08-057 NL-08-057 Attachment Attachment 2 Docket Nos. 50-247 && 50-286 Page 6 of 28 28
"
Table 4.1-1 List of IP2 TLAA TLAA and Resolution TLAA Description TLAA Description Resolution Option Section Section Environmental Qualification Environmental Qualification managed Aging effect managed 4.4 4.4 Analyses Of Electrical Electrical 10 CFR 54.21 (c)(1)(iii)
(c)(1 )(iii)
Equipment Equipment IIPEC PEC does not have pre- 4.5 4.5 Concrete Concrete Containment Tendon stressed tendons in the stressed tendons in the Prestress Analyses containment structures.
containment structures.
Containment Liner Liner Plate and Penetrations Analyses Penetrations Fatigue Analyses Containment penetration Containment penetration Analyses remain valid 4.6 (feedwater line #22) fatigue 10 (c)(1)(i) 10 CFR 54.21 (c)(1 )(i) analysis analysis Other TLAA Other Leak before break Analysis remains remains valid 4.7.2 10 CFR 54.21 (c)(1 (c)(1)(i)
)(i)
Steam generator generator flow-induced Analyses remain valid 4.7.3 vibration vibration (tube wear) 10 CFR 54.21 (c)(1 (c)(1)(i)
)(i)
Table 4.1-2 4.1-2 List of IP3 TLAA TLAA and Resolution Resolution TLAA Description
. TLAA Description Resolution Option Resolution Option Section Section Reactor Vessel Neutron Embrittlement Embrittlement Analyses Analyses upper-shelf energy Charpy upper-shelf Analyses projected 4.2.2 10 CFR 54.21 (c)(1 (c)(1)(ii)
)(ii)
NL-08-057 NL-08-057 Attachment 2 Attachment Docket Nos. 50-247 &
Docket & 50-286 Page 77 of 28 28 Table 4.1-2 4.1-2 1P3 TLAA List of IP3 TLAA and Resolution Resolution Description TLAA Description Resolution Option Option Section Section Pressure/temperature limits Pressure/temperature P-T limit curves managed managed 4.2.3 4.2.3 10 10 CFR 54.21 (c)(1(c)(1)(iii)
)(iii)
Low temperature temperature overpressure overpressure LTOP L managed TOP limits managed 4.2.4 4.2.4 protection (LTOP)
(LTOP) 10CFR54.21(c)(1)(iii) 10CFR54.21 (c)(1 )(iii)
Pressurized thermal shock Pressurized Aging effects managed effects managed 4.2.5 4.2.5 10 CFR 54.21 (c)(1(c)(1)(iii)
)(iii)
Metal Fatigue Fatigue Analyses Analyses Reactor vessel AAalyses FeffiaiA valid AnalYcoc r.main valiEl 4.3.1.1 4.3.1.1 10 CER CpR 51q.21(c)(1)(i) 54 .21 (0)(1 )(i)
Aging effects Aging managed effects managed 10 CFR 54.21 (c}(1(c)(1)(iii)
Hiii)
Reactor Reactor vessel internals internals Analysoc AAalyses r...ain FeFAaiA valid valiEl 4.3.1.2 4.3.1.2 CFR 54.21 10 CpR (c)(1)(i) 64.21 (0)(1 )(i)
Aging effects managed mananed 10 CFR 54.21 (c}(1(c)(1)(iii)
Hiii}
Pressurizer Pressurizer Aal*sec AAalyses rcmai.
FeffiaiA valid lolaliEl 4.3.1.3 4.3.1.3 CpR 64.21 (c)(1)(i) 10 CFR (0)(1 )(i)
Aging managed Aging effects managed 10 CFR 54.21 (c}(1(c)(1)(iii)
Hiii}
Pressurizer Pressurizer insurge/outsurge insurge/outsurge Analyses
..
AAalyses main valid FeffiaiA valiEl 4.3.1.3 4.3.1.3 transients 10 CFR CpR 64.214'.21 (0)(1 )(i)
(G)(1)(6)
Aging Aging effects managed managed 10 CFR 10 CFR 54.21 (c)(1)(iii) 54.21 (c}(1 Hiii}
Steam generator Steam generator Analyscs AAalyses rFcmn*.
FeFAaiA valid valiEl 4.3.1.4 4.3.1.4 10 CFR CpR 51.21 64.21 (G)(1 (0)(1 )(0)
)(i) \
Aging Aging effects managed managed 10 10 CFR 54.21 (c)(1)(iii)
(c}(1 Hiii}
NL-08-057 NL-08-057 Attachment Attachment 2 Docket Nos. 50-247 Docket 50-247 & & 50-286 50-286 Page 8 of 28 Table 4.1-2 4.1-2 TLAA and Resolution List of IP3 TLAA TLAA Description TLAA Description Resolution Option Resolution Section Reactor coolant pump Reactor ARalyses rcm.ain valid Analysos FemaiR yaliEl 4.3.1.5 4.3.1.5 10 CFR erR 514.21 (c)(1)(i) 54.21 (0)(1 )(i)
Acing Aging effects manacled managed 10 CFR 54.21 (c}(1 (c)(1)(iii)
)(iii) mechanisms Control rod drive mechanisms ARalyses r.
Analys^, ain FemaiR.. valid yaliEl 4.3.1.6 4.3.1.6 CFR 54.21 (c)(1)(i) 10 erR (0)(1 )(i)
Aging effects managed managed 10 CFR 54.21 (c}(1 (c)(1)(iii)
)(iii)
Regenerative letdown heat Regenerative Analycco r...n*,
,l\Ralyses valid FeFRaiA yaliEl 4.3.1.7 4.3.1.7 exchangers exchangers 10 CFR
,-, 54.21 10 erR .21(.)(1)(i)
(0)(1 )(i)
Aging Aging effects managed 10 CFR 54.21 (c)(1)(iii) 10 (c}(1 )(iii)
Class 1 piping and in-line ARalyses remain IJaliEl Analyses FemaiR valid 4.3.1.8 4.3.1.8 components--B31.1 components-B31.1 piping CFR 54.21 10 erR 51.21 (0)(1 G,)(1\)(m)
)(i) effects managed Aging effects 10 CFR 54.21 (c}(1 (c)(1)(iii)
)(iii)
Class 1 piping and in-line Aalys6 FemaiR AAalyses valid Fremain yaliEl 4.3.1.8 4.3.1.8 components -pressurizer components -pressurizer surge surge C..- ,*2(G)(1)(i) 10 erR R 54.21 (0)(1 )(i) line Aging effects managed effects managed 10 CFR 54.2154.21(c)(1)(iii)
(c}(1 )(iii)
Class 1 piping and in-line ARalyses rem.ain valid Ana,*y*.e FeFRaiA yaliEl 4.3.1.8
. 4.~.1.8 components -thermowells components -thermowells CER 10 erR " 54.21 21(c)(1)(i)
.. (0)(1 )(i)
Aging Aging effects managed effects managed 10 CFR 54.21 (c}(1)(iii)
(c)(1)(iii)
Class 1 piping and in-line in-line Analysis will be updated as 4.3.1.8 4.3.1.8
-charging system components -charging components part of environmental environmental fatigue fatigue evaluation.
evaluation. See SectionSection 4.3.3.
Aging effects managed Aging effects managed 10 CFR 54.21 (c}(1 (c)(1)(iii)
)(iii)
Non-Class 1 piping and in-line Analyses remain valid Analyses remain 4.3.2 components components 10 CFR 54.21 (c)(1)(i)
(c)(1 )(i)
NL-08-057 NL-08-057 Attachment Attachment 2 Docket Nos. 50-247 & 50-286 Page 9 of.
Page of 28 Table 4.1-2 4.1-2 List of IP3 TLAA and Resolution Resolution TLAA Description Description Resolution Option Option Section Section Non Class N9A Glass 1 ~,, non R9R piping l3il3iR§ Analysos romnain ARalyses valid4.2 FeFRaiA '-Ialia ~
com;pononts S9FR139ReRts rosidual Fesiaual hot10 heat GFR 544.21
~ 0 CF=R .2~ (E)(1)(i)
(c)(~ )(i) rcmoval heat oXchangcr Feffi9IJai heat e*chaR§eF Effects of reactor water Aging effect managed managed 4.3.3 environment environment on fatigue life 10 10 CFR 54.21 (c)(1 )(iii) )(iii)
Environmental Qualification Environmental Qualification Aging effect managed managed 4.4 4.4 Equipment Electrical Equipment Analyses of Electrical 10 CFR 54.21 (c)(1 10 )(iii)
(c)(1)(iii)
IPEC does not have have pre- 4.5 Concrete Concrete Containment Containment Tendon stressed tendons stressed tendons in the in the Prestress Analyses Analyses containment structures.
containment structures.
Containment Containment Liner Plate and No TLAA for these 4.6 Penetrations Fatigue Analyses Penetrations Analyses components.
Other TLAA TLAA Leak Leak before break Analysis remains valid 4.7.2 4.7.2 10 CFR 54.21 (c)(1 (c)(1)(i)
)(i)
Steam generator generator flow-induced flow-induced Analyses projected Analyses projected 4.7.3 vibration vibration (tube wear) 10 CFR 54.21 (c)(1)(ii) 10 (c)(1 )(ii)
LRA Section 4.3.1.2, Reactor Vessel Internals, Internals, is revised as follows.
The IPEC reactor reactor vessel internals were designed to meet the intent of Subsection NG of the the ASME ASME Boiler and Pressure Vessel Code, Section II1.
III. A plant-specific plant-specific stress report on the the reactor internals was not required. The structural structural integrity integrity of the reactor internals internals design design has been has been ensured by analyses performed on both generic analyses performed generic and plant-specific plant-specific bases. These These analyses analyses were used as the basis for evaluating evaluating critical reactor internal components with with
NL-08-057 NL-08-057 Attachment 2 Docket Nos. 50-247 & & 50-286 50-286 Page 10 of 28 28 CUFs provided in Tables 4.3-5 and 4.3-6. The effects of fatigue on the reactor reactor vessel internals will be managed managed by the Fatigue Monitoring Monitoring Program in accordance accordance with 10 CFR 54.21(c)(1)(iii) 54.21 (c)(1)(iii) for both IP2 and IP3.
LRA' Section 4.3.1.3, Pressurizer, fifth paragraph LRA paragraph and Insurge/Outsurge Insurge/Outsurge Transients (second paragraph), are revised as follows.
None of the design design transients used in the analysis of the pressurizer pressurizer will be exceeded exceeded as discussed in Section 4.3.1. pressurizer fatigue analyses will thus 4.3.1. The Pr,.U.iZc- thus rcmai, remain valid or-the'
.. ld ffor thc poriod of ,*x4ndcd operation acc.rdanco With 10CFR"4.21 (G)(1)(i.
period of extended operation in in accordance '.'\lith 10CFR54 .21 (c)(1 )(i). The effects of fatigue fatigue on the pressurizer will be managed managed by the Fatigue Program in accordance Monitoring Proqram Fatigue Monitoring accordance with with 10 CFR 54.21(c)(1 54.21 (c)(1)(iii)
)(iii) for both IP2 and IP3.
,
Insurae/Outsurae Transients Insurae/Outsurge Transients The effects of fatigue on the pressurizer pressurizer will be managed by the Fatigue Fatigue Monitoring Monitoring Program in accordance in accordance with 10 CFR 54.21 (c)(1)(iii)
(c)(1 )(iii) for both IP2 and IP3. As4The As-tIhe cycles on which analyses are based will not be exceeded these analyses exceeded through the period of extended extended operation.:.,
operation._
thocc- TLAA these TLA\A remain remnain valid through the poriod period of extended cxtcndod opcration pcr, 10CFR54 operation per OCFR64.21 .21 (c)(1)I).
(c)(1 )(i).
Nonetheless, Nonetheless, as identified above. above, the surge nozzles require environmental fatigue environmE1ntal fatigue considerations~
considerations,-they and will be reanalyzed reanalyzed for license license renewal as disdussed disCussed in in Section 4.3.3.
LRA Section 4.3.1.4, LRA Section Steam Generators, 4.3.1.4, Steam Generators, Evaluation, Evaluation, is is revised revised as follows.
as follows.
Section Section 4.3.1 projects that none of the deSign design transients used for steam generator generator fatigue fatigue analysis will exceed their analyzed analyzed numbers during the period of extended operation. operation. These These usage factor calculations calculations are based on the design design transients transients discussed in in Section 4.3.1-a-pA 4.3.1-aoo rcmain valid for the period will remain pcriod of cxtondod epcratien in accordanco extended operation accordance with 11OCFR54 OCFR54.21.21 (-)(1 (c)(1 )(i). The effects of fatigue on the steam steam generators generators will be managed managed by the* the Monitoring Fatigue Monitoring Program in accordance in accordance with 10 CFR 54.21 (c)(1)(iii) 54.21(c)(1 )(iii) for both IP2 and and IP3.
LRA Section LRA 4.3.1.5, Reactor Section 4.3.1.5, Reactor Coolant Coolant Pump Fatigue Analysis, Pump Fatigue Analysis, second second paragraph, paragraph, is is revised revised as as follows.
Detailed fatigue analyses of RCP casings were not required because because the conditions conditions specified inin the 1965 1965 edition of the ASME code Sections N-415.1 (a) through (f), "Vessels Not Requiring Analysis for Cyclic Operation," were met. These fatigue waiver evaluations evaluations may be considered considered TLAA ifif they used the numbers of design design cycles in in the evaluation evaluation of items N-415.1 (a) through (f). IPEC has chosen to conservatively conservatively call the evaluations TLAA.
determinations were based on the numbers These determinations numbers of design cycles. The projections in in Tables 4.3-1 and 4.3-2 show that the numbers numbers of significant significant cycles cycles inin 60 years will remain remain below below the numbers of cycles used in in these determinations.
determinations. The effects of fatigue on the the reactor coolant pumps will be managed by the Fatigue Monitoring Program in Fatigue Monitoring Program in accordance accordance with 10 10 CFR 54.21(c)(1 54.21 (c)(1)(iii) IP3.Thus the TLAAs
)(ii;) for both IP2 and IP3.Thus T-.,AAc for determining determining that
NL-08-0S7 NL-08-057 Attachment 2 Docket Nos. 50-247 & 50-286 Docket Page 11 of 28 28 detailed fatigue aRalyses arc Rno required emain Val-i r tho pe-riod of oxto*,Rd operaton detailed fatigue analyses are not required remain valid for the period of extended operation '
in accordance iR accor.daR 'Nith ,11 OCFR54 e with OCGER-I.21 .21 (c)(1 )(i).
(")(1\)(i). '
lJ.D.i1.g From stretch stretch power uprate uprate analyses, the CUF for the RCP main main flange bolts is 0.44. As As tIhis CUF is based on the design tThis design transients and the design design transients will not be exceeded. exceeded.
The effects of fatigue on the main flanae flange bolts will be managed managed by the Fatigue Fatilue Monitoring Monitoring Program Program in accordance accordance with 10 (c)(1 WiD., the calcul1ation 10 CFR 54.21 (c)(1)(iii)., calculation of of CUF for the main main flange bolts romaine flange remains valid valid for the the period poriod of extended extended operation operationR in in accordance With \Nith 11OCFR641.21 OCFR54 .21 (1 (1 )(c)(i).
unit3 From stretch power power uprate analyses, the CUF for the RCP main flange bolts is 0.32. As tThis CUF is based on the design transients, and the design transients will not be exceeded.
tIhis exceed ed.
The effects fatique on the main flange bolts will be managed effects of fatigue managed by the Fatigue Monitoring Monitoring Prooram in accordance with 10 CFR 54.21 (c'*(l '(iiiY.. tho calculation, of C'JF for thc main Program in accordance with 10 CFR 54.21 (c)(1 )(iii)., the calculation of CUF for the main 1 - *ccr.21(1e fl.-*
flange g.- belts,in Fe ) aRSr bolts c)....c .valid remains . . f.-F va-l;id .. .the for the .period p . re *,ie
. ..of 1 ")
ef evxten1 " . operation extended . . .. r-÷;
............ .. . .. ...With in*.*~r*~.*r**,
accordance .... .......
"10-"GFR'r5 4.4 2 1t(1 )\(G) 10CFR54 .21 (1 )(c)(i).
LRA Section Section 4.3.1.6, Control Rod Drive Mechanisms, last paragraph, paragraph, is revised as follows.
As discussed discussed in Section Section 4.3.1,4.3.1, the numbers numbers of analyzedanalyzed design transients used in this this fatigue analysis will not be exceeded exceeded in 60 years of operation. operation. The effects effects of fatigue on the the control control rod drive mechanisms mechanisms will be managed managed by the Fatigue Monitoring Monitoring Pro-gram Program in accordance with 10 CFR 54.21 accordance 54.21 (c)(1)(iii).and (c)(1 WiD.and thus this TLAA will ','ViII remain remain valid through the the periodpeid of extended o~peration operation in in accorFdance accordance with 10CFR54 OGFR64.21 .21 (G)(1)(4).
(c)(1 )(i).
LRA Section Section 4.3.1.7, Class-1 Heat Exchangers, Exchangers, second paragraph, paragraph, is revised revised as follows.
Westinghouse determined that the regenerative regenerative heat exchanger exchanger was the controlling controlling heat exchanger exchanger with regards regards to fatigue, and therefore therefore only that heat exchanger exchanger was analyzed.
associated report concludes that by 10/31/1999, Unit 2 had accumulated The associated accumulated 466 of the the analyzed 2000 cycles (23.3%) on the regenerative regenerative heat exchanger. Further, since the the analyzed analyzed CUF was only 0.235, the CUF as of 10/31/1999 was equal to 0.235 x 23.3% 23.3% = =
0.05. For license license renewal, the thermal thermal cycles cycles seen by the regenerative regenerative heat exchanger can exchanger be projected through through the period of extended operation to show that only only 1072 1072 cycles (54%)
are expected expected in 60 years, corresponding corresponding to a projected CUF of 0.235 x 54% =
a projected = 0.13. The IP3 IP3 auxiliary heat exchangersexchangers have no plant-specific evaluation. However, the similarity in plant-specific evaluation.
design and operation operation betweenbetween the two units units indicates the results would be similar. As the the projected projected IP2 CUF is 0.13, it follows that the IP3 CUF would also be well below below the limit of 1.0, such that aa plant-specific plant-specific analysis is not required. Thus the aging aginq effects due to fatique fatigue on Class 1 heat exchangers exchangers will be managed for the period of extended extended operation in accordance accordance with 10CFR54.21 OCFR54.21 (c)(1 )(iiD. Thus the TLAA (c)(1)(iii). TI.AA for the heat heat exchanger exchanger fatigue remains valid forF for the period period of extended operation operation inin accorFdanco accordance With with 1OGF=R5.21 OCFR54 .21 (G)(1)4)
(c)(1 )(i).
NL-08-057 NL-08-0S7 Attachment 2 Attachment Docket Docket Nos. 50-247 & & 50-286 Page 1212 of 28 t
LRA Section Section 4.3.1.8, Class 1 Piping and Components, Components, Pressurizer Pressurizer Surge Line Piping, second paragraph, is revised as follows.
site-specific evaluations The site-specific evaluations of the pressurizer pressurizer surge line are considered consider:ed TLAA since the the evaluations use time-limited evaluations time-limited assumptions assumptions such as thermal and pressure pressure transients, and and operating cycles. The dominant cycles in the surge line analysis operating analysis are the 200 heatups heatups and cooldowns, including including the stratification stratification and striping associated associated with those transients.
transients. As As discussed in Section 4.3.1, 4.3.1, the number of analyzed heatups/cooldowns, as well as the other analyzed heatups/cooldowns, design transients transients presented in Tables 4.3-1 and 4.3-2, will not be exceeded exceeded in 60 years of operation. Thus this TLA/\
operation. TLAA' remains valid through the end end of the period peried of extended eXt,,end operation in aooordanoe accordanc. 10CFR54 4.e.....'1.'ithIt*h CR.21 .21 ()(1 )(i).*The effects (0)(1 )(i). effects of fatigue on the pressurizer pressurizer surge line piping surge piping will be managed by the Fatigue Monitoring Monitoring Program in accordanceaccordance with 10 CFR 54.21 (c)(1 CFR 54.21 (c)(1)(iii).
)(iii).
LRA Section 4.3.1.8, Class 1 Piping and Components, Components, Thermowells, is revised as follows.
Westinghouse Westinghouse identified identified cumulative cumulative usage factors for various thermowells associated associated with with the IPEC pressurizers pressurizers based on 200 heatups and cooldowns with a maximum CUF of 0.021. 0.021.
Si4Gee-Table 4.3-1 Sinoe Table 4.3-1 and Table 4.3-2 project that 200 heatups heatups and cooldowns will not be be exceeded, exceeded, this TL'AATL/\A remains valid for the pe.rid period of extvd, extended d operation operation ;R in ac.ordance aooordanoe With with 1,O,-FR.,
1 OCFR54 .2*
.21 (*)(1)(i).
(0)(1 )(i). The effects effects of fatigue on thermowells will be managed by the Fatigue Fatigue Monitoring Program Monitoring Program in accordance accordance with 10 CFR 54.21 (c)(1)(iii). (c)(1 )(iii).
Section 4.3.1.8, Class 1 Piping and Components, IP2 Loop 3 Accumulator LRA Section Accumulator Nozzle, Nozzle, is* is revised as follows.
The IP2 loop 3 accumulator accumulator nozzle does not have a thermal sleeve. Although this piping piping was built to B31 831.1 .1 and no fatigue analysis of the piping was originally performed, performed, a fatigue fatigue analysis was performed performed to justify justify continued operation without continued operation without the thermal sleeve. An An analysis of the nozzle determined determined the CUF to be 0.95. This analysis was based based on the the same design cycles cycles as the reactor vessel, and those analyzed analyzed numbersnumbers of cycles will not be be exceeded for 60 years of operation.
exceeded operation. Therefore, this TLA TLA/\ for the 1122 IP2 lop loop 3 accumulator aooumulator nozzle remains valid for the period of extended operation operation per per 10CFR64.21 OCFR54 .21 (c)(1)(i).
(0)(1 )(i). The effects of fatigue on the IP2 loop 3 accumulator accumulator nozzle will be managed by the Fatigue Fatigue Monitoring Program in accordance Monitoring accordance with 10 CFR 54.21 (c)(1 (c)(1)(iii).
)(iii).
LRA Section A.2.2.2.1, Class 1 Metal Fatigue, second A.2.2.2.1, Class.1 second paragraph, is revised as follows.
The Fatigue Monitoring Program will assure that the analyzed analyzed number of transient cycles is exceeded. The program requires corrective action ifif the analyzed not exceeded. analyzed number number of transient transient cycles is approached.
cycles approached. Consequently, Consequently, the effects effects of aging related to these TLAA (fatigue (fatigue analyses) based on those transients will be managed by the Fatigue Monitoring Monitoring Program Program in accordance accordance with 10 10 CFR 54.21 (c)(1)(iii). f"r 54.21(c)(1)(iii). for both 1P2 _P3re.nOn valid for the peFi*d IP2 and IP3remain period ef of extended operation operation in in accordance aooordanoe with 10 10 CFR 54.21 (G)(4)(4)-.
(0)(1 )(i).
NL-08-057 NL-08-0S7 Attachment Attachment 22 Docket Docket Nos. 50-247 50-247 & & 50-286 50-286 Page 1313 of 28 28 LRA Section A.3.2.2.1, Class 1 Metal Section A.3.2.2.1, Metal Fatigue, paragraph, is revised as follows.
Fatigue; second paragraph, The Fatigue The Fatigue Monitoring Monitoring Program assure that Program will assure that the analyzed analyzed number transient cycles number of transient cycles is not exceeded.
exceeded. The programprogram requires corrective corrective action if if the the analyzed number of transient analyzed number transient cycles is approached. Consequently, the effects approached. Consequently, effects of aging aging related related to these TLAA (fatigue TLAA (fatigue transients will be managed based on those transients analyses) based managed by the Fatigue Monitoring Program Fatigue Monitoring Program in accordance with accordance with 10 10 CFR 54.21 (c)(1)(iii).
(c)(1 WiD. for for both both 1122 IP2 and and IP3remain P3romain validvalid for tho the poriod period ofof extended oxtd*,Rd operation por,-at-;on in aooordanoe accordanc- with 10 10 CFR CFR 64.21 51.21 (0)(1 (G)(1 )(i).
)@1.
Item 13 Audit Item 13 LRA Section 4.3.1.3, Pressurizer, Insurge/Outsurge, LRA paragraph, is revised as follows.
Insurge/Outsurge, first paragraph, The impact impact of pressurizer insurge/outsurge transients was not considered pressurizer insurge/outsurge considered in original original design basis calculations calculations for the pressurizer.
pressurizer. TheThe IP2 CUF of record record for the pressurizer surge pressurizer surge nozzle remains nozzle remains the original design design stress report number number of 0.264. IP3 re-evaluated the CUF IP3. re-evaluated CUF of the pressurizer pressurizer surge line nozzle considering surge line insurge/outsurge during the 200 design considering insurge/outsurge design heatups cooldowns. The revised CUF for IP3 is 0.9612. The CUFs are heatups and cooldowns. are reflected in Tables Tables 4.3-7 4.3-7 and 4.3-8. If reanalyzed for insurge/outsurge If the IP2 surge nozzle was to be reanalyzed insurge/outsurge itit is expected expected the resulting similar to the increase for IP3. Since increase would be similar resulting increase Since both plants plants approximately 0.26 (0.2589 and 0.264) without consideration had CUFs of approximately consideration of insurge/outsurge, then both would be expected insurge/outsurge, expected to have CUFs of approximately approximately 0.96 for 200 200 heatups with consideration insurge/outsurge. However, no TLAA to address consideration of insurge/outsurge. address insurge/outsurge exists for IP2. Both the IP2 and IP3 surge nozzles will be re-evaluated for insurge/outsurge environmentally assisted fatigue prior to the period of extended environmentally operation. That re-analysis extended operation. re-analysis will consider not only environmental factors, but also the effects of insurge/outsurge insurge/outsurge for both units. '
Audit Item 14 4.3-1, IP2 Analyzed and Projected Number of Thermal LRA Table 4.3-1, Thermal Cycles, Footnote 2, is revised as follows.
Hydro tests are no longer required or performed as a result of changes to ASME Section
- 2. Hydro
& Therefore hydro tests are projected to remain at the current value for the remainder of XI. Therefore plant life. Section 3.0 of WCAP-16169 states the vessel is ourrently GUF-e*tly analyzed for 200 hydrotests.
NL-08-057 NL-08-057 Attachment 2 Docket Docket Nos. 50-247 & & 50-286 50-286 Page 1414 of 28 LRA Table Table 4.3-2, IP3 Analyzed Analyzed and Projected Number of Thermal Cycles, is revised as follows.
Table 4.3-2 IP3 Analyzed Analyzed and Projected Number of Thermal Cycles Cycles Analyzed Cycles 60-year 60-year Transient Condition Numbers Numbers of as of Projection11 Projection Cycles Cycles 3/31/2006 3/31/2006 1211212035 12/12/2035 2
Nete4 Note 2 4O2
+2G 11 Plant heatup at 100°F per hr 200 55 1092 Plant heatup at 100°F per hr 200 55 1092 Nete-2 Note 2 -I 2
+2G 2 Plant cooldown at 100OF per hr 200 55 1092 Plant cooldown at 100°F per hr 200 55 1092
- 2. Cyclo
- 2. Cyole projeotion based on rate of pro~jcction based of occGurrence ooourrenoe of oyoles betweon Of cycles between 1975 1976 and 1995-.
1996.
Projection, is the number Projeotion number of oyoles as of 12/31/1 of cycle.. 995 plu, 12/31/1996 rate per day times thO plus the rate the number 12431/A 995 to the end of the per*ld number of days from 12/31/1996 period Of extended operatin.
of extenRded operation.
- 3. Hydro tests are no longer required or performed performed as a result of changes changes to ASME section
~ Current values are zero and projections XI. Current projections are zero.
Audit Items Items 17 and 142 142 LRA Section Exchangers, is revised as follows.
Section 4.3.1.7, Class-1 Heat Exchangers, manufacturing equipment The original manufacturing specification for the regenerative equipment specification regenerative letdown heat exchangers exchangers and the excess letdown heat letdown heat exchangers says these heat exchangers exchangers are to be be qualified for various transients. The E-spec qualified E-spec suggests that the manufacturer manufacturer should verify in in writing that all conditions conditions of Paragraph Paragraph N-415.1 N-415.1 of Section Section III are satisfied for the transient conditions; otherwise, a fatigue analysis is required. The IPEC UFSARs UFSARs say thethe regenerative letdown heat exchangers exchangers and the excess letdown heat exchangers exchangers are qualified temperature cycles from 100 deg F to 560 deg F associated qualified to 2000 temperature associated with charging charging and letdown stops and starts.
Westinghouse Westinghouse determined determined that the regenerative regenerative heat exchanger exchanger was the controlling heat exchanger exchangerwith with regards to fatigue, and therefore only that heat exchanger exchanger was analyzed.
analyzed.
The associated report concludes concludes that by 10/31/1999, Unit 2 had accumulated accumulated 466 of thethe analyzed 2000 cycles (23.3%) on the regenerative regenerative heat exchanger. Further, since the the analyzed CUF was only 0.235, the CUF as of 10/31/1999 was equal to 0.235 x 23.3% =
analyzed 0.05. For license renewal, the thermal cycles seen by the regenerative regenerative heat exchanger exchanger can be projected projected through the period of extended operation extended operation to show that only 1072 1072 cycles cycles (54%)
corresponding to a projected CUF of 0.235 x 54% == 0.13. The IP3 are expected in 60 years, corresponding IP3 auxiliary heat exchangers exchangers have no plant-specific evaluation, and therefore.
plant-specific evaluation. therefore, there is no no TLAA. However, the similarity in design and operation between the two units indicates the TLAA. the results would be similar. As the projected projected IP2 CUF is 0.13, itit follows that the IP3 CUF wouldwould
NL-08-057 NL-08-057 Attachment Attachment 22 Docket Docket Nos. 50-247 50-247 & & 50-286 50-286 Page Page 1515 of 28 28 also be be well well below the limit of of 1.0, such such that a plant-specific plant-specific analysis, if performed, would if performed, would code CUF limitl-is satisfy the code required.:.. The Fatigue limit is not Feui Fatigue Monitoring Monitoring Pro-gram Program will count count the the transients transients experienced experienced by by the the units and and require reguire action action if if any analyzed analyzed number number of transients transients is approached is approached during during the period of of extended operation. Thus the aging extended operation. aging effects effects due toto fatigue fatigue on on Class 1 heat exchangers exchangers will be be managed managed for the period of extended extended operation operation in accordance accordance with 1 10CFR54.21 OCFR54.21 (c)(1(c)(1)(iii).
)(iii). Thus Thus this TLAA TLAA roFmans remains valid through the end valid through end efof thc the period of period of extended operation in extended operation in acc'rdanco accordance with with 11OCR5-*.21 OCF~64 .21 (G)(1)(4i.
(c)(1 Hi).
IPEC IPEC design design documents documents indicate indicate that that the auxiliary auxiliary heat heat exchangers exchangers are not the limiting limiting components components in the CVCS system. system. The charging nozzles at the RCS cold charging nozzles cold leg piping piping are more limiting. Therefore, monitoring limiting. Therefore, monitoring of the chargingcharging nozzles nozzles will assure assure acceptability the acceptability of the auxiliary auxiliary heat exchangers. Because Because the charging nozzle is nozzle one one of the locations identified identified byby NUREG-6260 NUREG-6260 as requiring environmental adjustments environmental adjustments to the fatigue analysis, this nozzle nozzle will be evaluated evaluated with with the other NUREG-6260 NUREG-6260 locations locations as discussed discussed in Section 4.3.3.
Audit Audit Item 112112 Add Add LRA Section 4.3.4, References, References, as follows.
4.3.4 Rfc.en...
ReferenGes 4.3-1 NL-04-005, Entergy to NRC, Indian Point 2, "Indian Point Nuclear Generating NL-04-005, Generating Unit No.
2, Stretch Stretch Power Uprate, NSS and BOP Licensing Report", Report", January, 2004 4.3-2 NRC Letter, Patrick D. MilanoMilano to Mike Kansler, Entergy,Enter-qy, "Indian Point NuClear Nuclear Generating Generating Unit No. 22- - Issuance Amendment Re: 3.26 Percent Issuance of Amendment Percent Power Uprate",
October 27,2004.
October 27, 2004.
4.3.3 NL-04-069, NL-04-069, Entergy to NRC, Indian Point 3, "Proposed Changes to Technical Specifications: Stretch Power Uprate Specifications: Uprate (4.85%) and Adoption of TSTF-339", June, 2004.
4.3-4 NRC Letter, Patrick D. Milano to Mike Kansler, Entergy, "Indian Point Nuclear Generating Generating Unit No. 33 - Issuance of Amendment Re: 4.85 Percent Stretch Stretch Power Cycle-specific Parameters", March 24,2005.
Uprate and Relocation of Cycle-specific 24, 2005.
4.3-5 NRC Letter, Herbert Herbert N.N. Berkow to Robert H. Bryan, Chairman, Chairman, Westinghouse Owner's Owner's Evaluation of Topical Report Group, "Safety Evaluation Report WCAP-15666, Extension of Reactor WCAP-15666, Extension Flywheel Examination", May, 2003 Coolant Pump Motor Flywheel
NL-08-057 NL-08-057 Attachment 2 Attachment Docket Nos. 50-247 &
Docket & 50-286 Page 16 28 16 of 28 Audit Item 118118 LRA Section 4.3, Metal Fatigue, third paragraph, paragraph, is revised as follows.
Fracture mechanics mechanics analyses of flaws discovered discovered during in-service in-service inspection may be TLAA analyses based on time-limited assumptions for those analyses assumptions defined by the current operating operating term.
When a flaw is detected during in-service inspections, eitheF in-service inspections, eitRef the component may be be replaced. flaw replaced, must be-repaired.l.
flavv must the oGe)peF be-repaired, or the componente that contains
-,"tains the flaW
- ca..... can be-evaluated fla be-evaluated for continued continued service accordance with ASME Section service in accordance Section Xl.
XI. These evaluations evaluations may show that the component acceptable to the end of the license term based on projected component is acceptable projected in-service service flaw growth. Flaw growth is typically typically predicted based on the design thermal and mechanical loading mechanical loading cycles.
Audit Item 134134 LRA Table 4.3-2, IP3 1P3 Analyzed Analyzed and Projected Number Number of Thermal Cycles, is revised as follows.
Table 4.3-2 IP3 Analyzed and Projected Number Number of Thermal Thermal Cycles Cycles Analyzed Analyzed Cycles 60-year 60-year Transient Transient Condition Condition Numbers of as of Projection11 Projection Cycles 3/31/2006 3/31/2006 1211212035 12/12/2035 Operating basis 14 Operating basis 5 0 0 earthquake earthquake (OBE)2 (OBE)-!
Design Design basis basis earthquake earthquake 15 1 0 0 0 (DBE)2 (DBE)-5
- 5. The upset conditions include the effect of the specified specified earthquake earthquake for which the system must remain operational operational status. The faulted conditions operational or must reqain its operational conditions earthquake for which safe shutdown is required.
include the earthquake reguired. For fatique fatigue studies, Class II components were components were analyzed for five OBEs and one DBE in addition'to addition'to other fatigue fatique producinq events. Each earthquake is considered to produce producinq produce ten peak stress magnitudes.
maqnitudes.
Audit Item 135135 LRA Tables 4.3-13 and 4.3-14, IP2 (IP3) Cumulative Usage Factors for NUREG/CR-6260 NUREG/CR-6260 Limiting Locations Locations is revised revised to replace footnote 1 with the following and move the footnote footnote reference reference from NUREG-6260 NUREG-6260 location "Pressurizer surge surge line nozzle" to "Surge line piping".
NL-08-057 NL-08-057 Attachment Attachment 2 Docket Nos. 50-247 & & 50-286 50-286 Page 17 of 28 28
- 1. The maximum maximum usage factor factor on IPEC surge surge lines occurred at the pipe side of the the pressurizer nozzle pressurizer nozzle safe end with a maximum maximum value of 0.60.
Audit Item 141 LRA Section Section 4.3.1.3, Pressurizer, fourth and fifth paragraphs, are revised as follows.
Tthe original stress report did not analyze While +!he analyze the pressurizer shell, itit did analyze the the surge nozzle and spray nozzle. The resulting CUFs are not the CUFs of record as both the the nozzles were subsequently surge and spray nozzles subsequently re-evaluated re-evaluated for the stretch stretch power uprates.
The IPECG
+he prcsrr IPEC pressurizers evaluated for the stretch wore evaluated were powcr uprates Estrctch povJer cumulative ucagc upratcs and cum~ulativo usage facGt"rE wc-r factors were updated. The Y-usageUusage factors of record record are given in Tables 4.3-7 and 4.3-8.
Audit Item 143 The LRA is revised to remove the prefix to "831.1""B31.1" from the following sections and tables.
- Table 4.1-1, 4.1-1, List of IIP2 P2 TLAA and Resolution Resolution
- Table 4.1-2, List of IIP3 P3 TLAA and Resolution Resolution
- Section 4.3.3, Effects Effects of Reactor Reactor Water Environment Environment on Fatigue Life Life
- Table 4.3-13, IP2 Cumulative Usage Usage Factors for NUREG/CR-6260 NUREG/CR-6260 Limiting Locations, footnote 2
- " Table Table 4.3-14, IP3 Cumulative Usage Factors for NUREG/CR-6260 Cumulative Usage NUREG/CR-6260 Limiting Locations,Locations, footnote footnote 2 LRA Section 4.3.1.8, Class 1 Piping and Components, is revised as follows.
, AN&!
AN&4 B31.1 Pipina 831.1 Piping The IPEC Class 1 boundary corresponds to all reactor coolant coolant system (RCS) pressure pressure components within the ASME Section XI, boundary components boundary XI, IWB inspection boundary.
IW8 inspection The 831.1 B31.1 power power piping piping code originated originated in 1955 as ASA 831.1.
B31.1. In 1967 1967 itit became USAS USAS B31.1. ItIt later became 831.1. became ANSI 831.1B31.1 and is currently ASME B31.1.
831.1. The code of record for most of IP2 and some of IP3 is ASA 831.1 B31.1 (1955) while the code of record for some of IP2 IP2 and most of IP3 is USAS 831.1 B31.1 (1967). Use of the designation B31.1 in the application is designation 831.1 meant to differentiate differentiate piping designed B31.1 from piping designed to 831.1 piping designed designed to ASME Section III Section III standards.
NL-08-057 NL-08-057 Attachment 2 Attachment Docket Docket Nos. 50-247 & & 50-286 Page 18 Page 18 of of 28 28 USAS 831.1 YSAS B31.1 was used in the design of the primary primary coolant piping. A thermal expansion flexibility flexibility stress analysis was performed performed on the main primary primary coolant piping in accordance accordance with the criteria set forth in YSAS USAS 831.1 B31.1 to ensure ensure that the stress range is within the the prescribed limits. As per the requirements prescribed USAS 831.1, requirements of YSAS B31.1, no fatigue analysis analysis is required and no fatigue analysis of the reactor coolant coolant loop piping is performed. Rather stress range performed. Rather range reduction reduction factors are used to account account for anticipated transients (normally, a stress range range reduction reduction factor of 1.0 is acceptable in the stress analyses analyses for up to 7000 cycles).
Audit Item 144 144 LRA Section 4.3.2 is revised revised as follows.
4.3.2 Non Class 1 Piping and Compent Component Fatigue fatigue Pipinq and in-line components: The design of ASME Piping ASME III Code Class 2 and 3 piping systems systems incorporates incorporates the Code Code stress reduction factor for determining acceptability acceptability of piping design design with respect to thermal stresses. In general, 7000 thermal cycles cycles are assumed, allowing a stress reduction reduction factor of 1.0 in the stress evaluated the validity of this stress analyses. IPEC evaluated this assumption for 60 years of plant operation. operation. The results of this evaluation evaluation indicate indicate that the the 7000 thermal cycle assumption is valid and bounding bounding for 60 years of operation. Therefore, calculations are valid for the period of extended the pipe stress calculations accordance with extended operation in accordance 10 CFR 54.21 (c)(1 )(i). )(i).
Non-piping components: Review Non-piping Review of potential potential TLAAs for IPEC non-Class 1 components components fatyuie-TLAA identified no fatigue TLAA rolated related toto nnon Cl..
Gass 1I1c..mponcnts Class components cXceptexcept the the residual heat heat removal (RHR)(RHR) heat exchanger.
eXchanger.
Residual Heat Remoyal Heat Exchanger The original mauatrngeupot manufacturing equipment spccification specification states the RHR RHR heat exchanger is to be qualified for 200 cycles cycles that wouild would occur during plant shutdowns.
shutdowns. The 1122 IP2 1UFSA UfSAR, R, Ta-blc Table 6.2-88 and the IP3 6.2 1123 UFSAR, UfSAR, Table 6.2 6 statc state the RHR heat eXchangers exchangers are qualmfiod qualified to 200n 200 byclcs froem cycles from 85 OF to 350 360 -2F-.
Of.
No No fatigue analyses for these heat exchangers;exchangers have been been identified. itIt is believed that the manufacturers showed mnanufacturers showed the requirements of Paragraph the requiremnents Paragraph N 415.1 Of of ASME ASME Section III 111Wer were met; met; but but nono wrfitten statement froM written statement from the the manufacturer manufacturer has been been found. Non~etheless, Nonetheless, IPECiIPEC is conservatively cons~idering considering that determination determination a TLAA.
TLAA. This TLAA is is considered considered based on on the specified 200 design cycles;, cycles, corresponding corresponding to to the 200 design heatuipS/coldownS heatups/cooldo'A'ns for the reactE)r coolant reactor coolant system.
system. The system system will not Rot exceed 200 heatups and GGGldGwnscooldowns in 60 years prOjected in Tables 1.3 as projected 4.3 11 and 1.3 4.3 2. Thus this TLATLAA remains remains valid for for the the period Of of extended operation operation in acrdane accordance withvVith 1OCfR54 .21 (G)(1)(i)'.
- ' 'IR*.21 (c)(1 )(i).
NL-08-057 NL-08-057 Attachment 22 Attachment Docket Nos. 50-247 & & 50-286 Page 19 of 28 28 LRA Section Section A.2.2.2.2, Non-Class 1 Metal Metal Fatigue, second paragraph paragraph is revised as follows.
The only ORIY non Class!,
Glass1, non piping comnponent with a fatigue time limited idcntifiod with component identified limited aging analysis was the rcsidual residual heat rcmoval removal heat exchanger. That That heat exchanger is projected projoctod to incur less numnber Of than the analyzed number of cycles and therefore therefore the analysis will remain valid for the period poriod of of oxtonded extended operation.
LRA Section A.3.2.2.2, Non-Class Non-Class 1 Metal Fatigue, second paragraph is revised as follows.
The only non Glass1, Glass, no non piin piping componcnt component identified identified with a fatigue time limited aging analysianalysis was the residual heat reemoval;;;
removal heat exchanger.
exchanger. That heat exchanger exchanger is is projected to incur less loss than the analyzed number number of cycles and therefore Of cGycEl therefore the analysis will remain
- alidvalid for the period of Will remaiR extended operation.
operation.
Audit Item 147 147 ,
LRA Section 4.3.3, Effects of Reactor Water Environment Environment on Fatigue Life, third paragraph, paragraph, is revised as follows.
NUREG/CR-6260 identified locations of interest for consideration NUREG/CR-6260 consideration of applied the fatigue design curves that incorporated curves incorporated environmental designsto several plants and environmental effects in several plant desiqnsto identified locations ofof interest for en;idoration of environ.mental
.. consideration environmental effect". Section 5.5 effects. Section 5.5 of NUREG/CR-6260 identified the following component locations to be evaluated NUREG/CR-6260 M9et evaluated for the mast se~itP sensitive 0 e-e to environmental effects on fatigue for IPEC vintage Westinghouse Westinghouse plants. These locations and the subsequent calculations are directly directly relevant relevant to IPEC.
Audit Item 164 LRA Section 8.1.12, B.1.12, Fatigue Monitoring, Monitoring, Enhancements, is revised as follows.
Attributes Affected Affected Enhancements Enhancements
- 3. Parameters Monitored or Parameters Monitored IP2: Perform Perform an evaluation evaluation to confirm that Inspected Inspected monitoring steady monitoring steady state cycles and feedwater cycles is not required revise required or revise appropriate procedures appropriate procedures to monitor steady state cycles. Review the numbernumber of allowed events discrepancies events and resolve discrepancies between reference between reference documents documents and monitoring monitoring procedures.
IP3: Revise Revise appropriate procedures procedures to to
NL-08-0S7 NL-08-057 Attachment 2 Docket Nos. 50-247 & 50-286 Page 20 of 28 Attributes Affected Affected Enhancements Enhancements include all the transients identified.
include identified. Assure all fatigue analysis transients are included included with the lowest limiting limiting numbers. Update numbers. Update the number of design transients transients accumulated to date.
accumulated A.2.1.11, Fatigue LRA Section A.2.1.11, Fatigue Monitoring Monitoring Program, Program, second second paragraph, first bullet, is revised as as follows.
- Perform Perform an evaluation evaluation to confirm that monitoring steady state cycles cycles and feedwater cycles is not required appropriate procedures required or revise appropriate procedures to monitor steady steady state cycles.
Review the number of allowed discrepancies between allowed events and resolve discrepancies between reference reference documents and monitoring procedures.
documents Audit Item 562 Note: The LRA tables and sections described described below below were revised by letter NL-07-153 NL-07-153 to thethe NRC dated December December 18, 2007. . )
LRA Table Table 3.3.2-19-12-1P2, 3.3.2-19-12-IP2, Feedwater Feedwater System, is revised as follows.
Sight Pressure Carbon Pressure Treated Cracking GRe~entiFRe tome VIII.D1- 3.4.1-VIII.D1- 3.4.1- E glass boundary steel water (int) - fatigue e iRspectioR 7 1 Periodic (S-*11 (S-11))
surveillance surveillance and greventive preventive maintenance maintenance 3.3.2-19-2-1P3, Auxiliary LRA Table 3.3.2-19-2-IP3, Auxiliary Steam and Condensate Condensate Return System, is revised as as follows.
Sight Pressure Carbon Treated Treated Cracking Cracking GRe iMe G*e tiFRe VIII.B1- 3.4.1-VIII.B1- 3.4.1- E glass boundary boundary steel water (int) - fatigue i*epeetion iRspectioR 10 1 Periodic (S-08) surveillance surveillance and preventive greventive maintenance maintenance
NL-08-057 NL-08-057 Attachment 2 Docket Nos. 50-247 & & 50-286 50-286 Page 21 of 2828 LRA Table Table 3.3.2-19-14-1P3, Condensate Transfer System, is revised as follows.
3.3.2-19-14-IP3, Condensate Sight Pressure Pressure Carbon Treated Cracking ORetAime GAe time VIII.D1- 3.4.1-VIII.D1- 3.4.1- E glass boundary boundary steel water (int) - fatigue i~ispccticn iAspestioA 7 1 Periodic (S-11 (S-11))
surveillance surveillance and preventive greventive maintenance maintenance LRA Table 3.3.2-19-27-1P3, 3.3.2-19-27-IP3, Heater Separator Drains / Vents, is revised Heater Drains / Moisture Separator revised as follows.
Sight Pressure Carbon Carbon Steam Steam (int) Cracking Cracking Rettime GAe time VIII.B1- 3.4.1-VIII.B1- 3.4.1- E glass boundary boundary steel steel - fatigue p iAspestioA 10 1 Periodic (S-08) surveillance surveillance and preventive greventive maintenance maintenance LRA Table 3.4.1 is revised as follows.
3.4.1-1 Steel piping, piping, Cumulative TLAA, Yes, TLAA For most piping fatigue evaluated in evaluated components, the the components, damage damage accordance accordance evaluation of fatigue evaluation fatigue and piping with 10 CFR is a TLAA. For some some elements elements 54.21 (c) components, where exposed to no fatigue analyses analyses steam or exist, the GAe One Time Time treated treated water '..SPe.t.E)i IAspestioA Periodic Periodic Surveillance and Surveillance Preventive Preventive Maintenance Maintenance Program will manage will manage sOAfirm GGRfiRA the ab;-scnco tAe aeseAse oefof s;gif*a"'*t cracking sigAifisaAt cracking due to fatigue. See See Section 3.4.2.2.1.
Section 3.4.2.2.1.
NL-08-057 NL-08-0S7 Attachment 22 Attachment Docket Nos. 50-247 & & 50-286 50-286 Page 22 of 28 LRA Section 3.4.2.2.1, 3.4.2.2.1, Cumulative Fatigue Damage, is revised as follows.
Where identified as an aging effect requiring management, the analysis analysis of fatigue is a TLAA as defined defined inin 10 10 CFR 54.3. TLAAs are evaluated in in accordance accordance with 10 CFR 54.21(c).
54.21 (c).
Evaluation of this TLAA is addressed Evaluation addressed in in Section 4.3. For some components, where no analyses exist, the Ono fatigue analyses Timc Inspection One Time Inpecti,*, Periodic Surveillance and Preventive Preventive Maintenance Maintenance Program will manage confirm thc abcn, confirm the absence e of cignifiaRnt significant cracking due to fatigue fatigue enhanced visual or other NDE techniques.
using enhanced LRA Section A.2.1.28, Periodic Surveillance Preventive Maintenance Surveillance and Preventive Maintenance Program, second paragraph, add the following bullet item.
- auxiliary steam auxiliary steam and condensate return system sight glass housings housings
- condensate transfer condensate transfer system sight glass housings housings
- " heater drain/moisture heater drain/moisture separator separator drains/vents systems sight glass -glasshousings housings LRA Section B.1.29, Nonsafety-related Nonsafety-related systems affecting IP2 safety-related safety-related systems, add the the following activity.
Use visual or other NDE techniques techniques to inspect a representative representative sample sample of feedwater system sigqht glass housings sight glass housings to manage cracking due to fatique.
fatigue.
LRA Section B.1.29, Periodic Surveillance and Preventive Maintenance, Nonsafety-related Preventive Maintenance, Nonsafety-related systems affecting IP3safety-related IP3 safety-related systems, add the following activities.
Use visual or other NDE techniques techniques to inspect inspect a representative representative sample of auxiliary steam auxiliary steam and condensate return system sight glass glass housings housings to manage crackinq due manage cracking due to fatigue.
Use visual or other NDE techniques techniques to inspect inspect a representative representative sample of condensate condensate glass housings transfer system sight glass manage cracking housings to manage cracking due to fatigue.
Use visual Use visual or other NDE techniques techniques to inspect a representative representative sample of heater drain/moisture separator drains/vents drain/moisture separator drains/vents systems sight glass housings to manaqe manage cracking cracking due due to fatigue.
NL-08-057 NL-08-057 Attachment Attachment 2 Docket Nos. 50-247 &
Docket & 50-286 50-286 Page Page 23 of 28 Items 63 and 563 Item 63 is being revised to reflect discussion with the NRC Staff associated Item associated with draft LR-ISG-addresses the plant specific 2007-02. LRA B.1.22 addresses non-EQ bolted cable specific AMP for non-EO cable connections.
Based on discussion with the NRC Staff, the AMP discussion being discussion for using visual inspection is being clarified to further explain explain the types of connections connections and personnel safety issues of opening energized equipment.
An example of where visual inspection acceptable is motor inspection is acceptable connections where the motor motor connections' motor lead connected to the field cable in is connected in a local junction box. Because personnel safety practices Because of personnel the practices the junction box cover would not be removed when the cable is energized, junction thermography could energized, so thermography could only be performed with the junction box cover in in place, which may not provide provide accurate accurate results.
Another example of using visual inspection would be in switchgear panels where the in remote switchgear the covered with tape or an insulating boot. For both of these entire connection to the bus is covered these examples, contact contact resistance measurements examination of the measurements would require the destructive examination the connection. The Entergy Entergy policies for personnel energized components at a potential personnel safety for energized greater than 600V, are to observe a restricted approach greater approach boundary, which would preclude preclude the the removal of a bolted cover from energized components at a potential removal potential of greater than 600V. The The number connections that are greater than 600V are limited to large motor, transformer, number of bolted connections connections (less than 30 connections, which is 3 connections per phase for 10 generator connections or generator motors) for both units, and 5 remote MCC for both units.
previously revised with Amendment B. 1.22 was previously LRA Section B.1.22 Amendment 1, Entergy Letter NL-07-153 1, Entergy NL-07-153 dated 12/18/2007, and is not being changed by this clarification.
clarification.
NL-08-057 NL-08-0S7 Attachment 2 Docket Nos. 50-247 & 50-286
& 50-286 Page 24 of 28 28 INDIAN INDIAN POINT NUCLEAR GENERATING UNIT NUCLEAR GENERATING UNIT NOS.
NOS. 2 ANDAND 3 RENEWAL APPLICATION (LRA)
LICENSE RENEWAL REQUESTS FOR REQUESTS ADDITIONAL INFORMATION FOR ADDITIONAL INFORMATION (RAls) (RAIs)
CLARIFICATION Structures Structures RAI 2.4.3-1 RAI2.4.3-1 Section Section 2.4.3 of the LRA states that the fuel storage storage buildings have the following intended intended functions for 10 54.4(a)(1) and (a)(2): '~Maintain 10 CFR 54.4(a)(1) "Maintain integrity non-safety related integrity of non-safety components related components such that that safety safety functions are not affected by maintaining maintaining pool water water inventory (Units 2 and 3)."
LRA Section Section 2.1.2.2, "Screening of Structures," states states that the screening of structural components components and commodities commodities was based primarily primarily on whether they perform an intended function.
function .
. LRA Table 3.5.2-3, "Turbine Building, Auxiliary Building, and Other Structures Structures Structural
. Components Components and Commodities (IP2 and IP3)," identifies identifies structural structural components components subject to aging aging management management based on materials of construction and intended functions functions for components components of structures structures including the fuel storage buildings. The intended functions listed in Table 3.5.2-3 (e.g., pressure pressure boundary, missile missile barrier, and shelter shelter or protection) protection) agree with the intended intended functions listed in LRA Table 2.0-1, functions 2.0-1, "Intended Functions: Abbreviations Abbreviations and Definitions."
However, the intended intended functions for the fuel storage building listed in LRA Section 2.4.3 does does not agree with the listed intended functions in LRA Tables 2.0-1 and 3.5.2-3.
Pursuant to 10 CFR 54.21, 54.21, the LRA must identify identify and list those structures and components components subject to an AMR.
AMR. Clarify the LRA Section 2.4.3 2.4.3 description of the intended intended function(s) of the the fuel storage building components components using the list of intended functions from Table Table 2.0-1.
2.0-1. To To satisfy the requirements requirements of 10 54.21, the clarification must be adequate 10 CFR 54.21, adequate to reasonably reasonably identify identify the fuel storage storage building structural structural components subject to aging managementmanagement by the the component/commodity, construction, and intended component/commodity, material of construction, intended functions listed in LRA Table Table 3.5.2-3.
Response for RAI 2.4.3-1 2.4.3-1 The intended intended functions listed in Tables 2.0-1 and 3.5.2-3 3.5.2-3 are component intendedintended functions, which which are determined during determined during the screening screening process. The intended intended functions in Section 2.4.3, in contrast, are the intended functions of the structure in its entirety entirety and are determined determined during during thethe scoping process. The scoping process determines determines whether whether or not the structure structure has an intended intended function function (such as providing containment or isolation to mitigate post-accident providing containment post-accident offsite doses or providing support or protection protection to safety-related safety-related equipment), whereas the screening screening process process identifies those components components that support the structure intended structure intended function(s) via specific specific component intended functions (such as providing component providing shelter and protection protection (EN)
(EN) or providing providing support for safety-related safety-related equipment (SSR)). The structure and system level functions that are are assessed assessed against the scoping criteria of 10 CFR 54.4 are intended to match the component are not intended component level functions defined defined in LRA Table 2.0-1.2.0-1. While similarities exist between between the terminology terminology
NL-08-057 NL-08-057 Attachment 22 Attachment Docket Nos. 50-247 & & 50-286 50-286 Page 25 of 28 28 used for component intended functions versus structure intended functions, a direct correlation between the structure intended functions in Section 2.4 and the component structure intended component intended functions intended functions in the tables in Section Section 3.5 does does not exist.
Consistent with the function stated in Section 2.4.3, components components of the fuel storage building building perform a component-level license renewal intended function if component-level license if they are required to maintain maintain pool water inventory.
Clarification Clarification for RAI 2.4.3-1 March 7, 2008, the NRC staff questioned conversation on March In a telephone' conversation whether the intended questioned whether intended function of maintaining maintaining pool water inventory was the only intended function function applicable applicable to items items included in the structural included management review for the fuel storage buildings. In structural aging management In response response to the request paragraph of the response to RAI 2.4.3-1 request for clarification, the last paragraph 2.4.3-1 provided in in letter NL-08-005 letter NL-08-005 dated January 4, 2008 is replaced 4,2008 replaced with the following.
In addition addition to the function stated in Section 2.4.3, the fuel storage buildings perform perform the license license intended function of provide support and protection for safety-related renewal intended safety-related equipment and nonsafety-related equipment within the scope of license renewal. Using Table 3.5.2-3, nonsafety-related component intended functions supporting each structure level intended component level intended intended function are indicated as follows.
non-safety related components Maintain integrity of non-safety
- 1) Maintain such that safety functions are not components such inventory (Units 2 and 3).
affected by maintaining pool water inventory affected Structure and/or Component Structure and/or Component or Intended Intended Function Commodity Spent fuel pool p_ool liner plate and gate (IP2) andgate EN, SSR EN,SSR Spent fuel pool liner plate and gate (I(IP3) P3) EN, SSR EN,SSR Exterior walls Exterior EN, FB, MB, PB, SNS, SSR EN,FB,MB,PB,SNS,SSR Exterior walls - below grade Exterior EN, MB, MB, PB, SNS, SSR Floor slabs, interior interior walls, and ceilings EN, EB, MB, PB, SNS, SSR EN,FB,MB,PB,SNS,SSR
- 2) Provide support protection for safety-related support and protection equipment and nonsafety-related safety-related equipment nonsafety-related equipment within the scope of licenselicense renewal.
Structure and/or Component Structure Component or Intended Function Function Commodity Crane rails and girders SNS SNS Metal siding EN, FB EN,FB New fuel storage New storage racks EN, SSR EN,SSR Roof decking FB FB Spent fuel pit bridge crane, rails and SNS SNS girders girders Spent fuel pool storage racks racks SSR Structural steel: beams, columns, plates MB, SNS, SSR Exterior walls EN, FB, MB, PB, SNS, SSR EN,FB,MB,PB,SNS,SSR
NL-08-057 NL-08-0S7 Attachment Attachment 2 Docket Docket Nos. 50-247 &
Nos. 50-247 & 50-286 50-286 Page Page 26 of 28 28 Exterior Exterior walls walls - below below grade Qrade EN, MB, PB, SNS, SSR EN, MB, SSR Floor interior walls, and ceilings Floor slabs, interior ceilinQs EN, EN, FB, MB, PB, SNS, SSR FB,MB,PB,SNS,SSR Masonry walls Masonry walls EN, FB, SNS, SSR EN,FB,SNS,SSR Roof slab FB, MB, PB, SNS, SSR EN,FB,MB,PB,SNS,SSR EN, 2.3.4.2 2.3.4.2 Main Feedwater Feedwater System RAI2.3A.4.2-1 RAI 2.3A.4.2-1 License renewal License renewal drawing drawing LRA-9321-2019-0 identifies that valves FCV-417-L, LRA-9321-2019-0 identifies FCV-417-L, FCV-417, FCV-417, FCV-427, FCV-437-L, FCV-437, FCV-447-L, FCV-447, BF2-21, FCV-427-L, FCV-427, FCV-427-L, BF2-21, and and BF2-22, for the the Unit 2 main feedwater feedwater system, are within the system system evaluation evaluation boundary.
Although Although the aforementioned aforementioned valves are long-lived, they are not highlighted are passive and long-lived, highlighted indicating that they indicating they are not subject subject to aging management accordance with 10 CFR 54.21 (a).
management in accordance Explain Explain the valves' valves' exclusion exclusion from agingaging management.
Clarification Clarification for RAI 2.3A.4.2-1 In a telephone conversation on March telephone conversation March 7, 2008, the NRC questioned the statement that the NRC staff questioned the subject valves havehave no intended function no passive intended function for 54.4(a)(1) 54.4(a)(1) or (a)(3) since their failure would would accomplish the safety function of preventing feedwater flow to the steam generators. To clarify, preventing feedwater the response to RAI 2.3A.4.2-1 2.3A.4.2-1 provided in letter NL-08-005 January 4, NL-08-005 dated January 2008 is replaced 4,2008 with the following.
The LRA drawings indicate components that are included in the scope of license renewal for 10 indicate components management review. The subject FW system 54.4(a)(1) or (a)(3) and subject to aging management CFR 54.4(a)(1) valves, which are located located upstream of the containment isolation check valves in nbnsafety-containment nonsafety-related piping, safety-related because of their function to provide piping, are classified as safety-related provide feedwater feedwater isolation. highlighted, these valves and the remainder of the FW system isolation. Though not highlighted, components on LRA drawing LRA-9321-2019-0 are in scope and subject to aging management drawing LRA-9321-2019-0 management performing the intended function defined by 10 CFR 54.4(a)(2) with the review based on performing the component types component types evaluated evaluated in in Table Table 3.3.2-19-12-IP2.
3.3.2-19-12-1P2.
RAI 2.3B.4.2-1 RAI2:3B.4.2-1 License renewal drawing identifies that valves FCV-417-L, FCV-417, LRA-9321-20193-0 identifies drawing LRA-9321-20193-0 FCV-427-L, FCV-427, FCV-437-L, FCV-437, FCV-447-L, FCV-447, BF2-31, BF2-31, and BF2-32, for the the Unit 3 main feedwater system are within the system evaluation evaluation boundary.
Although the aforementioned valves are passive and long-lived, they are not not highlighted highlighted accordance with 10 CFR 54.21 (a).
management in accordance indicating that they are not subject to aging management Explain the valves' exclusion from aging management.
Explain
NL-08-057 NL-08-057 Attachment 2 Docket Nos. 50-247 & & 50-286 50-286 Page 27 of 28 28 Clarification for RAI 2.38.4.2-1 Clarification 2.3B.4.2-1 In a telephone conversation conversation on March 7, 2008, the NRC staff questionedquestioned the statement statement that the the subject valves have subject have no passive passive intended intended function for 54.4(a)(1) 54.4(a)(1) or (a)(3) since their failure would would accomplish the safety function function of preventing feedwater flow to the steam generators.
generators. To clarify, the response response to RAI 2.3A.4.2-1 2.3A.4.2-1 provided provided in letter letter NL-08-005 January 4,2008 NL-08-005 dated January 4, 2008 is replaced replaced with the following:
following.
The LRA drawings indicate indicate components that are included in the scope of license renewal renewal for 10 54.4(a)(1) or (a)(3) and subject to aging CFR 54.4(a)(1) management review. The subject aging management subject MFW system valves, which are located upstream upstream of the containment containment isolation isolation check valves in nonsafety-related piping, are classified safety-related because classified as safety-related because of their function to provide feedwater feedwater isolation. Though not highlighted, highlighted, these valves and the remainder remainder of the FW system components on LRA drawing drawing LRA-9321-20193-0 LRA-9321-20193-0 are in scope and subject to aging management management review based performing the intended based on performing intended function defined by 10 CFR 54.4(a)(2) with the component component types evaluated evaluated in Table 3.3.2-19-34-1P3.
3.3.2-19-34-IP3.
RAI 2.5-1 2.5-1 (Rev. 1)
Based Based on discussion discussion with the NRC Staff on 12/4/0712/4/07 and industry discussion discussion with the NRC StaffStaff 12/12/2007 and 113012008, on 12/12/2007 1/30/2008, the response response to this RAI provided provided in Entergy Entergy Letter NL-07-138, NL-07-138, Dated Dated 11/16/2007 is beingbeing revised. The only section that requires revision revision is LRA Figure 2.5-2 and associated discussion.
discussion.
Clarification Clarification for RAI 2.5-12.5-1 (Rev. 1)
As shown in the revised LRA Figure 2.5-2, the 6.9 kV buses receive receive offsite power from either the 138 kV 1 / 6.9 kV station auxiliary 13.8 kV 1 auxiliary transformer or the 13.8 / 6.9 kV GT autotransformer.
autotransformer. TheThe station auxiliary auxiliary transformer transformer is connected connected to the 138138 kV Buchanan Buchanan substation, the primary offsiteoffsite switchyard bus, overhead power source, via switchyard overhead transmission transmission conductors, and underground underground transmission transmission conductors conductors through mo.to.
motor.p.rat.d disconnectt F3A operated diOnn*RRe, FaA switchyard switchyard breakers breakers F2 and BT 3-4, which is are located Buchanan substation.
located at the Buchanan substation. The GT autotransformer autotransformer is connected connected to the 13.8 kV Buchanan Buchanan substation, the secondary secondary offsite power source, via underground underground medium voltage cable through breaker F2-3, which is located located at the Buchanan Buchanan substation.
substation.
NL-08-057 NL-08-0S7 Attachment 22 Attachment Docket Nos. 50-247 Docket 50-247 & 50-286 50-286 Page 28 Page 28 of of 28 28 IP20ffsite Underground Medium Underground MediumVolt Volt Path Cable Cable BT3-4 breaker) 138kV Traosmissiqn Lines 138kV Transmission Lines Buchanan Substation 138kV Switchyard 138kV Switchyard Bus Bus 138kV I(bre:a~ker).
III Underground Cable.
138kV UndergroundCabre.
138kV Buchanan Buchamin I,
t Substation Substation I j13.8kIV 13.8kV
...
Medium Volt Cab.le Volt Cable
.... ...
Non Segregated Noli Segregatoo Ptlase Phase Stationl Swtiori Bus Bus Switchyard 138kV 138kV *
- l I
I. PI.
'2 138akV Bus:.I
~
IP213.8kV Bus:
!
sr"UOfl Transffmer Station Aux Tmllsfo.rmer 13,81J 6,9kVGTAuto 13,8 6.VVGT Au to Tlans!orm~ .
Ifansfornaet I ...
lJJJJ J
1 Transformer Yard Transformer
,... "-"-' .-.,_.,"-. .. .-., : -", '.- . -
," : , -- . -
, , , - ., ""'- ,, - ._1
6.9kVBus 5 ~ 6.9kV8us2 o.9kVBus3 6.9kV Bus6 Non Safety t Non Safety NOn Safety I Non Safety I Turbine Building
(
WJJ* SST5 lillJ
[YTI)SST2 ~SST3 ~SST6 fj1 480V805 SA I
4&OVBusZA 480V8osJA I 400VBus 6A I
Safety Safety Safety Safety Switchgear Room Figure 2.5-2 Figure Offsite Power Scoping Diagram IP2 Offsite
ATTACHMENT ATTACHMENT 3 TO NL-08-057 NL-08-057 IPEC LRA List of Regulatory Revision 4 Regulatory Commitments, Revision ENTERGY ENTERGY NUCLEAR NUCLEAR OPERATIONS, OPERATIONS, INC.
INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 &
NUCLEAR GENERATING &3 50-247 AND 50-286 DOCKET NOS. 50-247
NL-08-057 NL-08-0S7 Attachment Attachment 3 Docket Nos. 50-247 Docket 50-247 && 50-286
, Page 1 of 13 List of Regulatory Commitments Regulatory Commitments Revision Revision 4 The following table identifies those actions committed to by Entergy in this document.
Any other statements in this submittal are provided for information information purposes purposes and are not regulatory commitments.
commitments.
- COMMITMENT IMPLEMENTATION IMPLEMENT ATION SOURCE RELATED SCHEDULE SCHEDULE LRA LRA SECTION /I AUDIT ITEM AUDIT IP2: NL-07-039 A.2.1.1 Aboveground Steel Tanks Tanks Program for IP2:
Sptb 28, NL-07-039 A.2.1.1 A.2.1.1 1 Enhance the Aboveground Program for perform thickness measurements of September September 28, A.3.1.1 A.3.1.1 IIP2 P3 to perform P2 and IIP3 measurements of tanks, storage tanks, condensate storage the condensate ~013 B.1.1 surfaces of the bottom surfaces of the city water tank, and fire water tanks once during the lP3:
IP3:
first ten years of the period period of extended extended operation.
operation. December 12, December 12, Enhance the Aboveground Aboveground Steel Tanks Program for ~015 2015 IP2 and IP3 to require trending trending of thickness thickness measurements measurements when material material loss is detected.
Program for Integrity Program Enhance the Bolting Integrity IP2 and IP3 IP2:
IP2: NL-07-039 NL-07-039 A.2.1.2 A.2.1.2 2 for IP2 and IP3 that actual yield strength is used in selecting September 28, September A.3.1.2 A.3.1.2 to clarify strength is used in selecting susceptibility to SCC andand clarify the ~013 013 B.1.2 B.1.2 materials for low susceptibility to SCC clarify the prohibition on use of lubricants lubricants containing containing MoS MoS 22 for IP3: NL-07-153 Audit Items IP3: NL-07-153 Audit Items bolting. December 12, 201,241, December 12, 201,241, The Bolting Integrity Program Program manages manages loss of 2015 270 1 preload and loss of material material for all external external bolting.
Implement the Buried Piping and Inspection Tanks Inspection IP2:
IP2: NL-07-039 NL-07-039 A.2.1.5 A.2.1.5 3 Implement and Tanks September September 28, A.3.1.5 A.3.1.5 Program for IP2 Program IP2 and IP3 IP3 as described in LRA described in LRA Section Section 2013 2013 B.1.6 B.1.6 B.1.6. NL-07-153 Audit Item NL-07-153 Item This new program will be implemented implemented consistent with IP3: 173 173 the corresponding corresponding program program described described in NUREG-NUREG- December 12, December 1801 Section XI.M34, XI,M34, Buried Piping and Tanks 2015 2015 Inspection.
NL-08-057 NL-08-057 Attachment Attachment 3 Docket Nos.
Docket Nos. 50-247 50-247 & 50-286 50-286 Page Page 22 of of 13 P2:
IP2: NL-07-039 NL-07-039 A.2.1.8 A.2.1.8 4 Enhance Enhance the Diesel Diesel Fuel Fuel Monitoring Monitoring Program Program to to September 28, September A.3.1.8 A.3.1.8 include include cleaning and and inspection inspection of of the IP2 IP2 GT-1 GT-1 gasgas 2013 12013 B.1.9 8.1.9 oil storage turbine fuel oil storage tanks, IP2 IP2 and and IP3 IP3 EDG fuel oil NL-07-153 NL-07-153 Audit items Audit items SS~/Appendix R day tanks, IP2 SBO/Appendix R diesel diesel generator generator fuel IP3:
IP3: 128,129, oil day day tank, and IP3 IP3 Appendix Appendix R R fuel oil storage tank /
December 12, December 12, 132, 132, and day day tank once once every every ten years.
years.
2015 12015 NL-08-057 491,492, NL-08-057 Enhance the Diesel Enhance Diesel Fuel Monitoring Program Fuel Monitoring Program to to 510 510 include include quarterly quarterly sampling sampling and and analysis of of the the IP2 IP2 SBO/Appendix SSO/Appendix R R diesel generator generator fuel oil day day tank, IP2 security security diesel fuel fuel oil oil storage tank, IP2 security diesel fuel oil day tank, and IP3 Appendix R diesel R fuel oil storage tank. Particulates, storage Particulates, water and sediment sediment checks will be performed checks performed on the samples. Filterable Filterable solids acceptance acceptance criterion will be less than or equal to 10mg/l.
10mg/1. Water Water and sediment acceptanceacceptance criterion will be less than or equal equal to 0.05%.
Enhance the Diesel Fuel Enhance Monitoring Program Fuel Monitoring Program to to include thickness measurement of the bottom of the thickness measurement the following tanks once every ten years. IIP2: P2: EDG fuel oil storage tanks, EDG EDG fuel oil day tanks, SBO/Appendix R diesel generator SSO/Appendix generator fuel oil day tank, GT-1 gas turbine fuel oil storage tanks, and diesel fire fire pump fuel oil storage tank; IP3: EDG fuel oil day tanks, EDG fuel oil storage tanks, Appendix R R fuel oil storage tank, and diesel fire pump fuel oil storage storage tank.
Enhance Enhance the Diesel Fuel Monitoring Monitoring Program to I
change the analysis analysis for water and particulates particulates to a quarterly frequency quarterly frequency for the following tanks. IP2: GT-1 gas turbine fuel oil storage storage tanks and diesel fire pump pump tank; IP3: Appendix R fuel oil day tank fuel oil storage tank; and diesel fire pump fuel oil storagestorage tank.
Enhance the Diesel Fuel Monitoring Program to specify acceptance acceptance criteria for thickness thickness measurements measurements of the fuel oil storage storage tanks within the the scope of the program.
program.
Enhance the Diesel Fuel Monitoring Program Program to direct samples be taken and include include direction to remove remove water when detected.
Revise applicable procedures to direct sampling of the the onsite portable fuel oil contents prior to transferring transferring the contents to the storage tanks.
Enhance the Diesel Fuel Monitoring Program to direct Enhance the addition of chemicals including biocide when the the presence of biological activity is confirmed.
NL-08-057 NL-08-057 Attachment Attachment 3 Docket Nos.
Docket Nos. 50-247 50-247 & 50-286 50-286 Page Page 3 of 13 5 Enhance Enhance the External External Surfaces Surfaces Monitoring Monitoring Program IIP2:
P2: NL-07-039 NL-07-039 A.2.1.10 A.2.1.10 September September 28, A.3.1.10 A.3.1.10 for for IP2 IP2 and and IP3 in~lude periodic IP3 to include periodic inspections inspections of systems 2013 2013 B.1.11 B.1.11 systems in scope and and subject to aging aging management management review review for license license renewal renewal in accordance accordance with 10 10 CFR IIP3:
P3:
54.4(a)(1) and 54.4(a)(1) and (a)(3). Inspections Inspections shall include areasareas surrounding December 12, December 12, surrounding the subject systems systems to to identify identify hazards hazards to those systems. Inspections Inspections ofof nearby nearby systems systems that ~015 2015 could could impact the subject systems subject systems will include include SSCs SSCs that are in scope scope and subject subject to aging aging management management review for license license renewal in accordance accordance withwith 10 CFR 54.4(a)(2).
54.4(a)(2).
t I. 1*
IP2: NL-07-039 NL-07-039 A.2.1.11 A.2.1.11 6 Enhance the Fatigue Monitoring Monitoring Program for IP2 to to September September 28, A.3.1.11 A.3.1.11 monitor steady statestate cycles cycles and feedwater feedwater cycles or perform 2013 12013 B.1.12, perform an evaluation evaluation to determine determine monitoring monitoring is not not NL-07-153 NL-07-153 Audit Item Item required. Review the number of allowed allowed events events and resolve discrepancies discrepancies between reference 164 164 reference documents documents and and monitoring procedures.
monitoring procedures.
Enhance the Fatigue Monitoring Enhance Monitoring Program Program for IP3 to IP3:
IP3:
include include all the transients identified. Assure transients identified. Assure all fatigue fatigue December December 12, 12, analysis analysis transients are included included with the lowest lowest 2015 12015 limiting numbers. Update Update the number of design transients accumulated accumulated to date.
7 IP2:
IP2: NL-07-039 NL-07-039 A.2.1.12 A.2.1.12 Enhance the Fire Protection Protection Program to inspect September 28, A.3.1.12 A.3.1.12 external surfaces of the IP3 RCP oil collection 2013 12013 B.1.13 B.1.13 systems for loss of material material each refueling refueling cycle.
Enhance the Fire Protection Enhance Protection Program to explicitly explicitly IP3:
IP3:
state that the IP2 and IP3 diesel fire pump engine engine December 12, December sub-systems (including sUb-systems (including the fuel supply line) shall be be 2015 12015 observed while the pump is running. AcceptanceAcceptance criteria will be revised to verify that the diesel engine engine does not exhibit signs of degradation degradation while running; such as fuel oil, lube oil, coolant, or exhaust gas leakage.
leakage.
Enhance the Fire Protection Program Program to specify specify. that the IP2 and IP3 diesel fire pump engine carbon steel steel exhaust components are inspected for evidence of corrosion and cracking at least once each operating operating cycle.
Enhance the Fire Protection Program for IP3 to to visually inspect the cable spreading spreading room, 480V switchgear room, and EDG room CO C022 fire suppression system for signs of degradation, such as corrosion and mechanical damage at least once every six months.
NL-08-057 NL-08-057 Attachment 3 Attachment Docket Nos. 50-247 Docket 50-247 &
& 50-286 50-286 Page 4 of 13 P2:
IP2: NL-07-039 NL-07-039 A.2.1.13 A.2.1.13 8 Enhance the Fire Water Program Enhance Program to include inspection September September 28, A.3.1.13 A.3.1.13 of IP2 and IP3 hose reels for evidence evidence of corrosion.
2013 2013 B.1.14 8.1.14 Acceptance criteria will be revised to'verify no no NL-07-153 Audit Items NL-07-153 Items unacceptable signs of degradation.-
unacceptable degradation'"
1P3:
IP3: 105, 106 105, 106 Enhance Enhance the Fire Water Program to replace all or test December December 12, NL-08-014 I NL-08-014 a sample of IP2 and IP3 sprinkler sprinkler heads required for 2015 2015 10 CFR 50.48 using guidance guidance of NFPA 25 (2002 edition), Section Section 5.3.1.1.1 before before the end of the 50-year sprinkler sprinkler head 10-year head service life and at 10-year intervals intervals thereafter during during the extended period of operation to ensure that signs of degradation, degradation, such as corrosion, are are detected detected in a timely manner.
Enhance the Fire Water Program to performperform wall thickness evaluations evaluations of IP2 and IP3 fire protection piping on system components components using using non-intrusive non-intrusive techniques (e.g., volumetric testing) to identify evidence evidence of loss of material material due due to corrosion. These inspections inspections will be performed performed before the end of the the current operating term and at intervals thereafter thereafter during the period of extended operation. Results of the initial evaluations evaluations will be used to determine determine thethe appropriate appropriate inspection inspection interval interval to ensure aging aging effects effects are identified prior to loss of intended intended function.
function.
Enhance the Fire Water Program Enhance Program to inspect the the internal surface surface of foam based fire suppression suppression tanks.
Acceptance Acceptance criteria will be enhanced enhanced to verify no no sianificant corrosion.
significant corrosion.
NL-08-057 NL-08-057 Attachment 3 Attachment Docket Docket Nos. 50-247 & 50-286 Nos. 50-247 50-286 Page Page 55 of of 13 13 IIP2:
P2: NL-07-039 NL-07-039 A.2.1.15 A.2.1.15 9 Enhance Enhance the Flux Flux Thimble Thimble Tube Inspection Program Tube Inspection A.3.1.15 September September 28, A.3.1.15 IP2 and for IP2 for IP3 to implement and IP3 comparisons to wear implement comparisons wear B.1.16 2013 12013 B.1.16 rates identified in WCAP-12866. Include rates identified provisions to Include provisions compare data to the previous compare performances and previous performances and IIP3:
P3:
evaluations regarding perform evaluations perform change to test regarding change December 12, December 12, frequency and scope.
frequency 2015 12015 Enhance the Enhance Inspection Program the Flux Thimble Tube Inspection Program I P2 and IIP3 for IP2 P3 to to specify acceptance criteria specify the acceptance criteria as as outlined in WCAP-12866 outlined plant-specific values WCAP-12866 or other plant-specific values based on evaluation based previous test results.
evaluation of previous Enhance Inspection Program Enhance the Flux Thimble Tube Inspection Program evaluation and direct evaluation for IP2 and IP3 to direct and performance performance corrective actions of corrective tubes that actions based on tubes that exceed exceed or are projected to exceed are exceed the the acceptance Also acceptance criteria. Also stipulate that flux thimble tubes that cannot be stipulate be inspected over the tube length and inspected and cannot be shown analysis to be satisfactory by analysis continued service, satisfactory for continued service, removed from service must be removed service to ensure ensure the integrity system pressure boundary.
of the reactor coolant system
NL-08-057 NL-08-057 Attachment Attachment 33 Docket' Nos.
Docket 50-247 &
Nos. 50-247 & 50-286 50-286 Page Page 66 of of 13 1IP2:
IP2: NL-07-039 NL-07-039 A.2.1.16 A.2.1.16 10 10 Enhance the Enhance the Heat Heat Exchanger Monitoring Program Exchanger Monitoring Program forfor September 28, f A.3.1.16 A.3.1.16 I P2 and IP2 and IP3 include the to include IP3 to following heat the following exchangers September 28, heat exchangers 12013 2013 8.1.17, B.1.17, in the in scope of the scope the program.
of the program.
NL-07-153 NL-07-153 Audit Item Audit Item
- Safety Safety injection pump lube injection pump lube oil oil heat heat exchangers IP3:
exchangers IP3: 52 52 December 12, December 12,
~015 RHR pump seal coolers
- pump seal coolers
- Non-regenerative heat Non-regenerative heat exchangers exchangers
- Charging Charging pump pump seal water heat heat exchangers exchangers
- Charging Charging pump pump fluid fluid drive coolers coolers
- Charging Charging pump crankcase oil coolers pump crankcase coolers
- Spent fuel pit pit heat heat exchangers exchangers
- Secondary Secondary systemsystem steam steam generator generator sample sample coolers coolers
- Waste Waste gas compressor exchangers compressor heat exchangers
- Appendix R diesel jacket SBO/Appendix S80/ jacket water heat exchanger exchanger (IP2 only)
Enhance the Heat Monitoring Program for Exchanger Monitoring Heat Exchanger IIP2 P2 and IP3 perform visual inspection I P3 to perform inspection on heat exchangers where non-destructive exchangers non-destructive examination, examination, such inspection, is not possible due to heat as eddy current inspection, exchanger exchanger design limitations. \
Enhance the Heat Exchanger Monitoring Monitoring Program for consideration of material-IP2 and IP3 to include consideration material-environment environment combinations when determining sample population population of heat exchangers.
Enhance the Heat Exchanger Monitoring Program for establish minimum tube wall thickness IP2 and IP3 to establish exchangers identified for the new heat exchangers identified in the scopescope of Establish acceptance criteria for heat the program. Establish exchangers visually visually inspected to to include include no no unacceptable siqns unacceptable delradation.
sians of degradation.
1P2:
IP2: NL-07-039 NL-07-039 A.2.1.17 A.2.1.17 11 11 Enhance the lSI Program for ISI Program IP2 and for IP2 IP3 to and IP3 provide to provide inspections to confirm the periodic visual inspections absence of the absence of September September 28, A.3.1.17 A.3.1.17 periodic effects for lubrite sliding supports used in the 12013 013NL-07-153 Audit 8.1.18item aging aging lubrite supports used in the coolant pump reactor coolant generator and reactor support pump support IP3: NL-07-153 Audit59item steam generator systems. IP3:
December 12, 59 December 12, 12015 12015 1 1
NL-08-057 NL-08-057 Attachment 33 Attachment Docket Nos. 50-247 Docket 50-247 & 50-286 50-286 Page 77 of
, Page of 13 13 IP2:
IP2: NL-07-039 NL-07-039 A.2.1.18 A.2.1.18 12 12 Enhance Enhance the Masonry Masonry Wall Program Programfor for IP2 IP2 and and IP3 IP3 September September 28, .' A.3.1.18 A.3.1.18 to to specify specify that that the IP1 intake intake structure structure is included included in the program.
program.
2013 12013 B.1.19 B.1.19 the IP3:
IP3:
December December 12, 2015 12015 Enhance Enhance the Metal-Enclosed Metal-Enclosed Bus Inspection Inspection Program IP2: IP2: NL-07-039 NL-07-039 A.2.1.19 A.2.1.19 13 13 to add add IP2 IP2 480V 480V bus bus associated associated with with substation substation A to September September 28, A.3.1.19 A.3.1.19 the scope of busbus inspected.
inspected. 2013 12013 B.1.20 B.1.20 NL-07-153 Audit Items NL-07-153 Items Enhance the Enhance the Metal-Enclosed Metal-Enclosed Bus Bus Inspection Inspection Program Program IP3:
1P3: 124, for IIP2 P2 and IP3 IP3 to visually inspect inspect the external surface December 12, external surface NL-08-057 NL-08-057 133, 519 133,519 of MEB enclosure enclosure assemblies assemblies for loss of material material at 2015 12015 least once every 10 years.
least once every 10years. The The first inspection will inspection occur prior to the period of extended operation and extended operation and the acceptance criterion will be no significant acceptance criterion significant loss of material.
material.
Enhance the Metal-Enclosed Enhance Metal-Enclosed Bus Inspection Program to add acceptance acceptance criteria criteria for MEB internal internal visual inspections to include include the absence of indications indications of dust accumulation accumulation on the bus bar, on the insulators, and in the duct, in addition to the absence of indications indications of moisture intrusion into the duct.
Enhance the Metal-Enclosed Enhance Metal-Enclosed Bus Inspection Program for IP2 and IP3 to inspect bolted connections connections at least once every every five years ifif performed performed visually or at least once every every ten years using quantitative quantitative measurements such as thermography measurements thermography or contact resistance measurements. The first inspectioninspection will occur prior to the period of extended extended operation.
The plant will process a change to applicable site procedure to remove the reference to "re-torquing" connections for phase bus maintenance and a~d bolted maintenance.
connection maintenance.
Connections Cable Connections IP2: NL-07-039 NL-07-039 A.2.1.21 14 Implement the Non-EQ Bolted Cable Program for IP2 and IP3 Program described in IP3 as described in LRA September LRA Section September 28, Section A.3.1.21 B.1.22. 12013 2013 B.1.22 IP3:
IP3:
December 12, 12015
_015
NL-08-057 NL-08-057 Attachment Attachment 33 Docket Docket Nos.
Nos. 50-247 50-247 && 50-286 50-286 Page Page 88 of of 13 13 IIP2:
P2: NL-07-039 NL-07-039 A.2.1.22 A.2.1.22 15 Implement Implement the the Non-EQ Non-EQ Inaccessible Inaccessible Medium-Voltage Medium-Voltage A.3.1.22 September 28, September A.3.1.22 Cable Program Cable Program for for IP2 IP2 and and IP3 IP3 as as described described in in LRA LRA Section B.1.23.
B.1.23. ~013 2013 B.1.23 B.1.23 Section NL-07-153 NL-07-153 Audit item item This This new new program program will will be implemented implemented consistent consistent with with IIP3:
P3: 173 173 the the corresponding corresponding program program described described in NUREG-NUREG- December December 12, 12, 1801 1801 Section Section XI.E3, XLE3, Inaccessible Inaccessible Medium-Voltage Medium-Voltage ~015 2015 Cables Not Cables Not Subject T010 Subject To CFR 50.49 10 CFR 50.49 Environmental Environmental Qualification Reauirements.
Qualification Requirements.
, IP2: NL-07-039 A.2.1.23 16 Implement IP2: NL-07-039 A.2.1.23 16 Implement the Non-EQ Instrumentation Circuits Non-EQ Instrumentation Circuits Test September 28, A.3.1.23 A.3.1.23 Program for IP2 Review Program Review and IP3 IP2 and described in as described IP3 as LRA September 28, in LRA Section B.1.24. 12013 2013 B.1.24 B.1.24 Section NL-07-153 NL-07-153 Audit item item This new program This program will be implemented consistent with IP3:
implemented consistent IP3: 173 173 the the corresponding corresponding program program described NUREG-described in NUREG- December December 12, 12, 1801 1801 Section Section XI.E2, XLE2, Electrical Cables and Electrical Cables and 2015 2015 Connections Connections Not Not Subject Subject to 1010 CFR 50.4950.49 Environmental Environmental Qualification Qualification Requirements Requirements Used in in Instrumentation Instrumentation Circuits.
17 Implement the Non-EQ Implement Insulated Cables Non-EQ Insulated Cables andand IP2:
IP2: NL-07-039 A.2.1.24 A.2.1.24 Connections Program for IIP2 Connections P2 and IIP3P3 as described in as described in September 28, September A.3.1.24 A.3.1.24 Section B.1.25.
LRA Section ~013 2013 B.1.25 B.1.25 NL-07-153 Audit item item program will be implemented This new program implemented consistent with IP3: 173 the corresponding corresponding program program described described in NUREG-NUREG- December December 12, J 1801 Section XI.E1, Electrical Cables XLE1, Electrical Cables and 2015 12015 Connections Not SU.bject Connections Subject to 1010 CFR 50.49 Requirements.
Environmental Qualification Requirements.
IP2:
IP2:
NL-07-039 A.2.1 .25 Program for for IIP2 sample to sample NL-07-039 A.2.1.25 18 Enhance the Oil Analysis Program P2 to in the SBO/Appendix September September 28, A.3.1.25 A.3.1.25 and analyze analyze lubricating oil used SBO/Appendix consistent with oil generator consistent R diesel generator analysis for oil analysis for ~013013 B.1.26 B.1.26 generators.
other site diesel generators. IP3:
IP3:
Enhance the Oil Analysis Program for IP2 IP2 and IP3 IP3 to December 12, sample and analyze generator generator seal oil and turbine 2015 2015 hydraulic control oil.
Enhance the the Oil Oil Analysis Program Program for IP2 IP2 and IP3 IP3 to to formalize preliminary oil screening for water and analyses including defined particulates and laboratory analyses defined acceptance criteria for all components included included in in the the scope of this program. The The program will specify corrective actions in corrective in the event event acceptance acceptance criteria criteria are are
,
met.
not met.
Enhance the Oil Enhance Oil Analysis Program Program for IP2 IP2 and IP3 IP3 to formalize trending of formalize of preliminary preliminary oil oil screening screening results as well as well as as data data provided provided from from independent independent 1laboratories.
laboratories.
, NL-08-057 Attachment 3 Docket Nos. 50-247 &
& 50-286 50-286 Page 9 of 13 IP2:
IP2: NL-07-039 NL-07-039 A.2.1.26 A.2.1.26 19 19 Implement Inspection Program for IP2 Implement the One-Time Inspection IP2 September September 28, A.3.1.26 A.3.1.26 and IP3 as described in LRA Section B.1.27.
~013 2013 B.1.27 B.1.27 This new program program will be implemented implemented consistent with with NL-07-153 NL-07-153 Audit item item the corresponding corresponding program program described described in NUREG-NUREG- IP3:
IP3: 173 173 1801,Section XI.M32, 1801, XLM32, One-Time Inspection.
One-Time Inspection. 12, December 12,
~015 2015 One-Time Inspection -- Small Bore Small Bore IP2:
IP2: NL-07-039 A.2.1.27 A.2.1.27 20 Implement the One-Time in LRA September September 28, A.3.1.27 A.3.1.27 Program for IP2 and IP3 as described in LRA Piping Program
~013 2013 B.1.28 Section B.1.28.
Section NL-07-153 NL-07-153 Audit item item This new program program will be implemented implemented consistent consistent with IP3: 173 173 the corresponding program described described in NUREG-NUREG- 12, December 12, 1801, Section XLM35, 1801, XI.M35, One-Time One-Time Inspection Inspection of ASME ~015 2015 Code Class II Small-Bore Piping.
IP2:
P2: NL-07-039 A.2.1.28 21 Enhance the Periodic Surveillance and and Preventive Preventive necessary to as necessary to September September 28, A.3.1.28 Program for IP2 Maintenance Program Maintenance and IP3 IP2 and IP3 as be managed 2013 such 2013 B.1.29 B.1.29 assure effects of aging will assure that the effects will be managed such that applicable applicable components will continue to perform perform IP3&
IP3:
their intended intended functions consistent consistent with the current current December De r112, licensing basis through the period of extended extended 2015 operation.
operation. 015 IP2: NL-07~039 NL-07-039 A.2.1.31 22 Reactor Vessel Enhance the Reactor Enhance Vessel Surveillance Program for Surveillance Program for IP2:
September capsule withdrawal September 28, specimen capsule withdrawal A.3.1.31 IP2 and IP3 revising the specimen a standby capsule to cover' 2013013 B.1.32 B.1.32 schedules to draw and test a standby capsule to cover' the peak reactor reactor vessel vessel fluence fluence expected through the the IP3:
end of the period of extended extended operation.
operation. December 12, December 12, Enhance Enhance the Reactor Surveillance Program Reactor Vessel Surveillance Program for 20152015 IP2 and IP3 to require that tested and untested specimens from all capsules pulled from the reactor specimens I vessel are maintained maintained in storage.
IP2:
IP2: NL-07-039 NL-07-039 A.2.1.32 A.2.1.32 23 Implement the Selective Selective Leaching Leaching Program Program for IP2 Sptb 28, A.3.1.32 and IP3 as described in LRA Section B.1.33. September September 28, 28, A.3.1.32 A.3.1.32 and IP3 as described in LRA Section B.1.33. 2013 B.1.33
~013 B.1.33 This new program will be im'plemented implemented consistent consistent with NL-07-153 NL-07-153 Audit item item the corresponding corresponding program described described in NUREG-NUREG- IP3: 173 1801, Section XI.M33 Selective 1801, Section XLM33 Selective Leaching of Materials. December 12, 2015 12015 Generator Integrity Enhance the Steam Generator Program for IP2:
IP2: NL-07-039 A.2.1.34 A.2.1.34 24 Enhance Integrity Program for that the results of the condition September September 28, A.3.1.34 A.3.1B.34 IP2 and IP3 to require the results of the condition assessment are compared to are compared the to the 2013 013 B.1.35 monitoring assessment monitoring operational assessment assessment performed performed for the prior IP3:
operating cycle with differences differences evaluated. IP3:
December 12, December 12, 2015 2015
NL-08-057 NL-08-0S7 Attachment Attachment 33 Docket Nos.
Docket Nos. 50-247 50-247 && 50-286 50-286 Page Page 10 of 13 10 of 13 Enhance Enhance the the Structures Structures Monitoring Program to Monitoring Program to IIP2:
P2: NL-07-039 NL-07-039 A.2.1.35 A.2.1.35 25 25 explicitly specify explicitly specify that that the following structures the following structures are are September September 28, A.3.1.35 A.3.1.35 included included in in the the program.
program. 2013 2013 B.1.36 B.1.36
- AppendixAppendix R R diesel diesel generator generator foundation foundation (IP3)
(IP3) NL-07-153 NL-07-153
"* AppendixAppendix R R diesel diesel generator generator fuel oil oil tank tank vault vault IIP3:
P3: Audit Audit items items (IP3) December December 12, 12, 86, 87, 88, 86,87,88,
"* AppendixAppendix R R diesel diesel generator generator switchgear switchgear andand 2015 2015 NL-08-057 NL-08-057 417 417 enclosure (IP3) enclosure (IP3)
- city water water storage storage tanktank foundation foundation
- condensate condensate storage storage tanks tanks foundation foundation (IP3)
"* containment containment accessaccess facility facility and annex annex (IP3)
- discharge discharge canal canal (IP2/3)
- emergency emergency lighting lighting poles poles and and foundations (IP2/3)
(IP2/3)
- fire pumphouse pumphouse (IP2)
- fire protection pumphouse (IP3) protection pumphouse (IP3)
- firefire water storage storage tank foundations foundations (IP2/3)
(IP2/3)
- gas turbine 1 fuel storage storage tank foundation
- maintenance maintenance and outage outage building-elevated building-elevated passageway passageway (I (I P2)
- new station security building building (IP2)
"* nuclear nuclear service service building building (IP1)
(IP1)
- primary water storage tank foundation foundation (IP3)
- refueling refueling water storage storage tank foundation (IP3)
- security access access and office building (IP3)
- service service water pipe chase chase (I(IP2/3)
P2/3)
- service water valve pit (IP3)
- superheater superheater stack
- " transformer/switchyard transformerlswitchyard support structures (I(IP2) P2)
- waste holdup tank pits (IP2/3)
Enhance the Structures Monitoring Monitoring Program for IP2 IP2 and IP3 IP3 to clarify that in addition to structural steel and concrete, the following commodities (including their anchorages) are inspectedinspected for each structure structure as applicable.
- 0 cable trays and supports
- 0 portion of reactor concrete portion reactor vessel supports
- 0 conduits and supports
- 0 rails and cranes, rails and girders girders
- 0 equipment pads and foundations and foundations
- 0 proofing (pyrocrete) fire proofing (pyrocrete)
- 0 cranes jib cranes
- 0 manholes and duct manholes banks duct banks
- 0 manways, hatches manways, hatches and and hatch hatch covers
- 0 monorails monorails
NL-08-057 NL-08-057 Attachment Attachment 3 Docket Docket Nos.
Nos. 50-247 50-247 && 50-286 50-286 Page Page 11 11 of 13
- new new fuel storage storage racks racks
"* sumps, sump screens, strainers strainers and and flow flow barriers barriers Enhance Enhance the Structures Monitoring Program Structures Monitoring Program for IP2 IP2 and IP3 to inspect inaccessible inaccessible concrete concrete areas areas that are are exposed exposed by excavation excavation for any any reason. IP2 and IP3 will also inspect inaccessible inaccessible concrete concrete areas areas in environments environments where observed conditions where observed conditions in accessible areas exposed accessible areas exposed to the the same environment environment indicate indicate that significant significant concrete concrete degradation degradation is occurring.
occurring.
Enhance the Structures Monitoring Enhance Program for IP2 Monitoring Program IP2 and IP3 to perform perform inspections inspections of elastomers elastomers (seals, gaskets, gaskets, seismic joint filler, and roof elastomers) to identify cracking and change identify change in material material properties properties andand for inspection of aluminum vents vents and louvers to to identify loss of material.
identify material.
Enhance the Structures Monitoring Enhance Program for IP2 Monitoring Program IP2 and IIP3 P3 to perform perform an engineering engineering evaluation evaluation of groundwater samples to assess groundwater aggressiveness of assess aggressiveness groundwater groundwater to concrete concrete on a periodic basis (at least once every five years). IPEC will obtain samples samples from at least 5 wells that are representative representative of the ground ground water surrounding below-grade water surrounding below-grade site structures.
Samples will be monitored for sulfates, pH and chlorides.
Enhance Enhance the Structures Structures Monitoring Program Program for IP2 IP2 and IP3 to perform perform inspection of normally submerged submerged concrete portions of the intake structures at least once every 5 years. Inspect the baffling/grating partition and support platform of the IIP3 P3 intake structure at least once every 5 years.
26 Implement the Thermal Aging Embrittlement of Aging Embrittlement Cast of Cast IP2:
I P2: NL-07-039 A.2.1.36 Austenitic Stainless Steel (CASS) Program for IP2 September September 28, A.3.1.36 Austenitic Stainless (CASS) Program for IP2 B.1.37.
Section B.1.37.
described in LRA Section :2013 2013 B.A1.37 B.1.37 and IP3 as described NL-07-153 NL-07-153 Audit item Audit item new program This new program will be implemented implemented consistent with 1P3:
IP3: 173 the corresponding program described in NUREG- December 12, December 12, 1801, Section 1801, Section XI.M12, Thermal Aging Embrittlement Embrittlement 015 12015 of Cast Austenitic Stainless Steel (CASS) (CASS) Program.
NL-08-057 NL-08-057 Attachment 3 Docket Nos. 50-247 & 50-286 50-286 Page 12 of 13 Aging and Neutron Irradiation IP2:
IP2: NL-07-039 NL-07-039 A.2.1.37 27 Implement the Thermal Thermal Aging and Neutron Irradiation September September 28, A.3.1.37 A.3.1.37 Embrittlement of Cast Austenitic Stainless Steel Embrittlement Stainless Steel _>013 B. 1.38 and IP3 IP2 and IP3 as described in as described LRA in LRA 013 2013 B.1.38 (CASS) Program for IP2 NL-07-153 NL-07-153 Audit item Section B.1.38.
IP3:
IP3: 173 173 This new program will be implemented implemented consistent with December December 12, the corresponding program described corresponding program described in NUREG-NUREG- 2015 2015 1801 1801 Section Section XI.M13, Thermal Aging and Neutron Neutron Embrittlement Embrittlement of Cast Austenitic Stainless Steel (CASS) Program.
Closed Control - Closed Chemistry Control-Water Chemistry IP2:
IP2: NL-07-039 A.2.1.39 A.2.1.39 28 Enhance the Water September 28, A.3.1.39 A.3.1.39 Cooling Water Program to maintain water chemistry of water chemistry of September 28, the IP2 SBO/Appendix R diesel generator cooling ~013 2013 .1.40
.
B.1.40 the IP2 SBO/Appendix R diesel generator cooling IP3: NL-08-057 Audit 509item system per EPRIEPRI guidelines.
IP3: 509 Enhance the Water Chemistry Control- Control - Closed December December 12, Cooling Water Program to maintain the IP2 and IP3 ~015 2015 security generator generator and fire protection protection diesel cooling cooling water pH and glycol within limits specified specified by EPRI guidelines.
Primary and
- Primary and IP2: IP2: NL-07-039 A.2.1.40 29 Enhance the Water Chemistry Control Control-for IP2 to test sulfates monthly in September 28, September B.1.41 B.1.41 Secondary Secondary Program to test sulfates monthly in the RWST with a limit of <150 ppb.
of <150 ppb. 013 12013 internals, IP2:
IP2: NL-07-039 A.2.1.41 30 management of For aging management reactor vessel the reactor of the vessel internals, the industry programs for September September 28, A.3.1.41 A.3.1.41 participate in IPEC will (1) participate in the industry programs for effects on reactor 011 12011 investigating investigating and managing aging and managing aging effects on reactor internals; internals; (2) evaluate and implement implement the results of IP&
IP3:
the industry programs as applicable to the reactor reactor December 12, internals; and (3) upon completion of these programs, December 2013 12, 2013 but not less than 24 months before before entering entering the period of extended extended operation, operation, submit an inspection plan for for reactor internals internals to the NRC for review and approval.
IP2: NL-07-039 A.2.2.1.2 IP2:
I NL-07-039 A.2.2.1.2 A.2.2.1.2 31 curves will Additional P-T curves submitted as be submitted will be as required required prior to the period G prior to the period of of September September 28, A.3.2.1.2 A.3.2.1.2 per 10 CFR 50, Appendix Appendix G 12013 2013 4.2.3 extended operation as part of extended operation Reactor Vessel the Reactor of the Vessel Surveillance Program.
Surveillance Program. IP3:
IP3:
December 12, December 12, 2015 12015 32 As required required by 10 CFR 50.61 (b)(4), IP3 will submit a IP3:
IP3: NL-07-039 A.3.2.1.4 A.3.2.1.4 32 plant-specific plant-specific safety analysis for plate B2803-3 to the December 12, December 12, 4.2.5 NRC three years prior to reaching the RT RTPTS PTS ~015 2015 screening screening criterion.
criterion. Alternatively, Alternatively, the site may choose choose to implement implement the revised PTS (10 50.61) rule (10 CFR 50.61) rule when approved, which would permit use of Regulatory Guide 1.99, Revision 3.
,
NL-08-057 NL-08-057 Attachment Attachment 33 Docket Nos.
Docket Nos. 50-247 SO-247 & 50-286 SO-286 Page Page 1313 of of 13 13 1~ *1~ I P2:
IP2: NL-07-039 NL-07-039 A.2.2.2.3 A.2.2.2.3 33 33 At At least least 2 years prior to years prior to entering entering the the period period of September 28, September 28, A.3.2.2.3 A.3.2.2.3 extended extended operation, operation, for for the locations identified the locations identified inin LRA LRA under ~011 2011 4.3.3 4.3.3 Table 4.3-13 Table 4.3-13 (IP2) and and LRALRA Table Table 4.3-14 4.3-14 (IP3),
(IP3), under NL-07-153 NL-07-1S3 Audit Audit item item the the Fatigue Fatigue Monitoring Program, IP2 Monitoring Program, IP2 and and IP3IP3 will will P3:
IP3: 146 146 implement implement one one or more more of of the the following:
following:
December 12, December 12, NL-08-021 NL-08-021 (1) Consistent Consistent with the Fatigue with the Fatigue Monitoring Monitoring Program, Program, 2013 12013 Detection of Detection of Aging Effects, Effects, update update the fatigue usage the fatigue usage calculations using refined calculations refined fatigue analyses to fatigue analyses to determine valid CUFs less determine less than than 1.0 1.0 when when accounting accounting for the for the effects effects of reactor reactor water water environment.
environment. This This includes includes applying applying the the appropriate appropriate Fen factors to Fen factors to valid valid CUFsdetermined CUFs determined in accordance accordance with one one of the the following:
- 1. For locations locations in LRA Table 4.3-13 (IP2) and LRA Table and LRA Table 4.3-14 LRA Table 4.3-14 (IP3), with existing existing fatigue fatigue analysis valid for the period of extendedextended operation, use the existing operation, use existing CUF.
- 2. Additional plant-specific locations Additional plant-specific locations with a valid valid CUF may be evaluated.
evaluated. In particular, particular, thethe lower shell will be reviewed pressurizer lower pressurizer reviewed to ensure ensure the surge nozzle remains the limiting component.
Representative CUF values from other plants,
- 3. Representative enveloping the IPEC plant specific adjusted to or enveloping specific external external loads may be used if if demonstrated applicable applicable to IPEC.
- 4. An analysis using an NRC-approved NRC-approved version of NRC-approved alternative the ASME code or NRC-approved alternative NRC-approved code case) may be (e.g., NRC-approved be performed performed to determine a valid CUF.
(2) Consistent with the Fatigue Monitoring Program, Program, Corrective Actions, repair or replace the affected before exceeding a CUF locations before CUF of 1.0.
34 SBO // Appendix R IP2 SSO generator will R diesel generator be will be April 30, 30, 2008 NL-07-078 NL-07-078 2.1.1.3.5 2.1.1.3.S IP2 and operational by installed and 2008. This by April 30, 2008. This committed change to the facility facility meets meets the the requirements of requirements 50.59(c)(1) and, therefore, aa of 10 CFR SO.S9(c)(1) to 10 CFR SO.90 50.90 is is not not -
amendment pursuant t010 license amendment required.
required.
ATTACHMENT ATTACHMENT 4 TO NL-08-057 NL-08-057 TLAA TLAA Audit Database Database Report ENTERGY NUCLEAR NUCLEAR OPERATIONS, OPERATIONS, INC.
INDIAN INDIAN POINT NUCLEAR GENERATING NUCLEAR GENERATING UNIT NOS. 2 &
&3 DOCKET NOS. 50-247 50-247 AND 50-286
TLAA TLAA - All All Items Items Item Request Request Response 33 TLAA 4.3-1 (a) This statement statement was not intended intended to identify any specific operating operating practice; however the reduction in rate of plant trips in recent recent operating history versus the the In LRA Table 4.3 In applicant states that the 4.3 1 the applicant the early years years of operation operation is common in in the nuclear industry industry due to lessons learned learned projected 60 year reactor trips were based on an yearreactor an leading to better better operating operating practices. There were substantially more reactor trips in in operating history history from 1999 to 2005, while the the the early years of operation at IPEC and this change in rate alone supports this this other transients transients were based based on the initial plant plant statement. Recent Recent plant data provides realistic projections projections of number of reactor reactor trips trips startup. expected during the period of extended operation operation while use of operating operating data for the the life of the plant provides unrealistically unrealistically conservative (high) projections.
(high) projections.
(a) The LRA states that because plant operating operating practices have changed and some of the the Based on the response to audit questions TLAA 4.3-9 and TLAA 4.3-10, the effects effects transients occur occur moremore or less often as an an of fatigue due due to these transients transients will be managed managed by the Fatigue Monitoring Monitoring explanation for using explanation using the six year year operating operating history Program. The Fatigue Monitoring Program Program will count the actual actual transients transients (1999 - 2005). Please explain what plant plant experienced by the units and require appropriate action if any of the analyzed experienced operating practices operating practices have have been been changed and why numbers of transients transients are approached. Consequently, these projections projections are only only these changes were not considered in the other other used to show that the analyzed analyzed numbers numbers of transients are not going to be exceeded exceeded transients' projection.
transients' projection. in the near future and not to justify that the existing fatigue fatigue analysis remain valid valid through the period of extended extended operation.
(b) From February 2000 2000 to January January 2001, 2001, IP2 IP2 was was shutdown shutdown because because of a steam generator generator tube tube For other transients, the change in rate of occurrence occurrence is not as significant as it is for rupture (SGTR) event and subsequent subsequent steam reactor trips. Cycle projections projections for other transients transients were thus based based on data for the the generator generator replacement replacement activities. Considering this this life of the plant plant rather than data just from recent years.
period of shutdown, please explain the impact itit has on 60-year 60-year projection projection for reactor trips. Also, (b) IfIf this extended (b) extended shutdown shutdown period was eliminated eliminated from the timeframe timeframe used for provide provide reasons why itit does not lessen the 60- determining determining the rate, the timeframe would be reduced from the 2032 days days to year projection projection cycle number number for reactor trips. approximately approximately 1696 1696 days. The projected number number of trips would increase increase by 9 to 301 trips which is still well below the 400 analyzed analyzed cycles. Additionally, this is only a (c) Page Page 4.3 2 of the LRA LRA describes describes linear linear projection projection and the actual actual number of accumulated accumulated cycles will be monitored against extrapolation of transients cycles. As the plant plant the numbernumber of allowable allowable cycles. Should the number of allowable allowable cycles be be aged, the aging effects effects were not consideredconsidered in in the the approached, approached, appropriate appropriate corrective corrective actions including repairs and/or modifications modifications linear linear extrapolation extrapolation method;method; please justify the would be implemented implemented consistent with the requirements of the ASME Code.
validity of using linear extrapolation.
LRA Table 4.3-1 4.3-1 will be modified modified to reflect this revised revised projection projection of reactor trips as as (d)
(d) (Previously question #138) #138) The extrapolation extrapolation follows.
of reactor trips with excessive cooldown in Table Table 4.3-1 projects only 159 events events after 60 years even In LRA Table 4.3-1, In 4.3-1, the values for 60-year 60-year projections will change from 292 to 301 though there are 148 148 events to date. Please for "Reactor trip", from 124 to 131 for "No excessive excessive cooldown", from 159 159 to 160 for for explain this projection explain this projection in in detail.
detail. "Excessive cooldown", cooldown", and from 9 to 10 for "Excessive cooldown with safety injection". Footnote 3 to the table will be revised revised to indicate that the 336 days days during which the unit was shut down in in 2000-2001 were not used in in the projection.
projection.
Clarification to be incorporated incorporated into into the LRA.
(c) A linear extrapolation is appropriate.
linear extrapolation appropriate. Operating Operating data shows that the rate of of occurrence of transients is decreasing. decreasing. Continued reduction reduction of transient transient rate is economically desirable desirable and thus will continue continue to be pursued. As operating operating experience is accrued and lessons learned experience learned are implemented, implemented, the reduction in in the the rate of transient occurrence is expected to continue. Many transients transients are projected using a linear rate that is much higher than actually actually experiencedexperienced in recent years.
The reactor trips used the more recent timeframe to determine determine the projection projection rate, but the results results are still realistic. The projection projection of cycles is not relied on to assure code compliance. As described described in in LRA section B.1.12, the Fatigue Monitoring Monitoring Program ensures Program ensures the validity of analyses that explicitly analyzed aa specified number of fatigue fatigue transients transients by assuring that the actual effective effective number number of transients does does not exceed the analyzed analyzed number of transients without appropriate corrective corrective action. action.
(d) The reactor trips with excessive cooldown cool down were projected based on data from from 1999 to 2005. There were only 22 transients during this time. There There were 2032 days days in this timespan, but 336 days have been removed removed as discussed discussed in in part (b) above.
The resulting resulting rate is 0.00118 cycles per day, which projects to 160 (160.21) (160.21) cycles in in 60 years. LRA Table 4.3-1 will be amended as discussed in in part part (b) above.
44 TLAA 4.3-2 TLAA4.3-2 The IP2 and IP3 Class 1 systems were designed designed for similar cyclic cyclic duty during original design and construction. construction. Both units track these design cycles, which are are a) FSAR Tables indicate FSAR Tables indicate the the same same design design included included in the FSAR, to ensure that the original design design requirements requirements are not transients for both iP2 IP2 and IP3. However, LRA exceeded during plant operation.
exceeded operation. In In addition to the original design cycles, IP2 has has provides a more extensiveextensive list of transients transients for IP2 IP2 added added a number number of additional additional duty cycles to its fatigue monitoring program to to (Table 4.3-1) 4.3-1) than IP3 (Table 4.3-2). Explain the the address enhancements developed developed during the design of newer newer vintage plants plants but
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Item Request Response basis for the differences. differences. which which werewere notnot included included as part of the as part the original original plant design basis. IP3 plant design IP3 is reviewing reviewing its fatigue monitoring program fatigue monitoring determine if additional program to determine additional transients should be transients should be added added The The initialinitial response response for for question question 4.3-2 4.3-2 has has nono to its monitoring to its monitoring program program to improve its to improve its effectiveness.
effectiveness. This enhancement is This enhancement references.
references. What What supports supports this response? response? identified in identified in Commitment Commitment 6.
This response is supported This response supported by by IP2 IP2 procedure 2-PT-2Y015, IP3 procedure 2-PT-2Y015, IP3 procedure procedure 3PT-M051, and M051, WCAP-12191, "Transient and and WCAP-12191, and Fatigue Fatigu.e Cycle Monitoring Program, Cycle Monitoring Program, Transient Transient History Evaluation Report History Evaluation Report for for Indian Indian Point Unit Unit 2" which which provide provide inputs inputs to to the Fatigue Monitoring the Monitoring Program.
Program. A A printed copy of printed copy of Section Section 33 of of WCAP-12191 WCAP-12191 was was provided on 10/23 provided 10123 for onsite review.
55 TLAA4.3-3 TLAA 4.3-3 During past operation, (a) During (a) operation, IP2 has has experienced experienced leakage through the pressurizer leakage through pressurizer safety valves. After Code safety After review of industry operating experience industry operating experience and discussions discussions LRA Table 4.3 LRA 4.3 1 lists some IP2 analyzed numbers IP2 analyzed numbers with Westinghouse, it was concluded that lowering with Westinghouse, lowering the the RCS pressure pressure by by of cycles for some some transient transient con ditions that conditions that do do not not approximately approximately 250 psi, would allow psi, would allow the safety valves properly seat therefore valves to properly therefore agree with their agree their designdesign cycle cycle nun mbers listed numbers listed in IP2 eliminating the leakage. However, since the RCS the leakage. RCS had had not not been been explicitly explicitly analyzed analyzed FSAR FSAR Table Table 4.1 8. For example example: analyzed transients for this transient, the list of analyzed transients was was reviewed determine if any reviewed to determine Transient Transient Condition Condition FSA FSAR R (of (of Cy)
Cy) already analyzed already analyzed transient bounded this RCS transient bounded RCS depressurization.
depressurization. This This review review LRA LRA (of (ofCy) Cy) indicated that a 50%
indicated that 50% step step load load decrease resulted in RCS pressure decrease resulted pressure and and temperature temperature Step load load decrease decrease of of 50-percen 50-percent nt of full full power power changes changes similar to to an an RCS RCS depressurization depressurization to correct correct safety safety valve leakage. Based Based on this, this, 50 cycles cycles were subtracted from the were subtracted allowable number of step the allowable step load load 200 150 decreases and decreases and aa new limit of 50 cycles was created for RCS depressurizations depressurizations for for Hydrostatic Hydrostatic test test at 2485 psig psig anandd 400°F 400°F the purpose of reseating reseating safety valves.
5 50 50 (b) During the early phase of (b) of plant operation, IP2 IP2 routinely performed primary side performed a primary side pressure determine steam generator pressure test to determine generator primary primary to secondary side leakage.
to secondary leakage.
(a)
(a) Please Please explain explain the discrepancies discrepan cies and and discuss discuss These pressure tests tests consisted of pressurizing pressurizing the primaryprimary side to 22502250 psi while while the impactimpact on the the cumulative cumulative usage us age factors maintaining the maintaining the secondary essentially 00 psi. A total of 41 of these secondary side at essentially these tests were tests were (CUFs) for various components.
(CUFs) performed performed during early early plant life (i.e. prior generator replacement) but steam generator prior to steam but this this practice practice has discontinued. This test has since been discontinued. test had had essentially essentially no impact on on the the (b) Indicate (b) Indicate which number number is used userd in the the design design other than the steam generators.
RCS other Although this test was generators. Although was notnot an RCS RCS calculation calculation for the hydrostatic hydrostatic tes st at 2485 test 2485 psig hydrostatic test (i.e. the hydrostatic the RCS pressure was 2250 RCS pressure 2250 notnot 2485), these tests were were and and 400 F. F. conservatively added to the conservatively primary side hydros because the 22 primary because the generators the steam generators secondary side was essentially secondary depressurized. Since this transient essentially depressurized. transient only impacts the the fatigue generators, Westinghouse fatigue life of the steam generators, Westinghouse reviewedreviewed the steam generatorgenerator stress reports and concludedconcluded that the steam generators had been steam generators been designed designed for 50 of these cycles.
cycles. InIn addition, since the steam generators generators have since been replaced replaced and these leak tests are no longer longer performed, the impact of these tests on the current fatigue usage has been eliminated.
RCS fatigue eliminated. However, the 43 cycles remains in the the monitoring program for historical purposes.
monitoring program 6 TLAA 4.3-4 These transients have never occurred and.are and are not expected to occur. As such, zero zero is the projected expected number of transients. The projected projected or expected projected numbers are not not In LRA Tables 4.3 1 and 4.3 2, a number of In used in any stress calculations. The in any The column "Analyzed Number Number of Cycles" provides provides transient conditions conditions for both IP2 and IP3 IP3 have 0 the number of cycles used used in in the stress analyses.
as the value for the 60 year proj ection. Please projection. Please explain the conservatism conservatism behind behind I projecting projecting no no transient conditions. Are these projected pprojected values values used in in any component's component's fatigue fatigue evaluation?
evaluation?
77 TLAA 4.3-5 (a) The statement on Page 4.3-2 includes includes an administrative administrative error in in referring to 10/31/1999. The LRA will be amended cycles as of 10/31/1999. amended to read as follows.
In LRA Table 4.3-1, In 4.3-1, the applicant lists the steady state fluctuation cycles (781,209), as of projections for IP2 The 60-year projections IP2 show the following.
5/24/2005. This date contradicts contradicts to the the statement statement The only normal projecting above the analyzed number normal condition projecting number of cycles is steady made in made in LRA page 4.3-2, where where the applicant state fluctuations. The projection is 1.5E6 analyzed number 1.5E6 while the analyzed number is 11E6.
states that this cycle number is calculated as of However, the value shown shown in in Table 4.3-1 is not based based on actual cycles.
10/31/1999. The value shown in in Table 4.3-1 is a calculated value based on the assumption that the transients occur at a constant rate that results in in the analyzed number of (a) Please (a) Please explain explain the discrepancy. transients occurring over 40 years of operation. Hence, the projection projection to 60 years calculated value is 1.5 times the analyzed based on this calculated number of transients. In analyzed number In (b) LRA indicates that steady state fluctuations are accordance with the Fatigue accordance Monitoring Program, prior to the period of extended Fatigue Monitoring not monitored. Do steady state fluctuations not fluctuations operation, actions will be taken to confirm that monitoring is not required (based on contribute to the design fatigue usage factors contribute factors for the insignificance to fatigue of of these cycles as discussed any any component? below) or below) to establish or to establish appropriate monitoring.
appropriate monitoring.
(c) (Previously Question (c) Question 121) 121) Address whetherwhether (b) Steady state oscillations are not a significant contributor (b) contributor to to the fatigue of any any steady state state oscillations are significant to to existing existing component. See See the response to item c) c) below.
fatigue analyses.
c) ASME Section III, c) III,Article 415.1 415.1(d)(d) states "A "A temperature temperature fluctuation fluctuation shall be be considered to be considered be significant ififits its total algebraic~range exceeds the quantity S/(2Me algebraic range exceeds S/(2Me
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Thursday, March Thursday, March 20, 20, 2008 Page2 of16
Item Request Response Cte) where S is the value of Sa obtained from the applicableapplicable design curve for 1E6 1E6 cycles." From Figure N-415(A) of ASME Section Figure N-415(A) III,Sa for 11E6 Section III, cycles (carbon steel)
E6 cycles 13000 psi.
is 13000 From Table Table N-426, N-426, the coefficient coefficient of thermal expansion, Cte, for carbon carbon steel at 500'F is 7.94 E-6 in/in/°F.
500°F in/inI"F. From Figure N-427 of ASME Section III III the modulus of of elasticity, Me, for carbon carbon steel of less than than 0.3% carbon carbon at 500°F is 26.4E6 26.4E6 psi/in/in.
This results in aa significant temperature temperature change change of 13000/(2 x 7.94E-6 x 26.4E6) for for a value of 31'F.
31°F.
As the steady state oscillations oscillations have an algebraic algebraic range of +/-3°F maximum, maximum, they are not significant as defined by the ASME ASME code.
A reevaluation reevaluation of the number of steady state cycles cycles is included in in Commitment 6.
Clarification to be incorporated into the LRA.
Clarification 8 TLAA4.3-6 TLAA 4.3-6 (a) The internals internals component component fatigue calculations calculations use a subset of the design transients for the reactor vessel. (Not all vessel transients affect affect the internals. The The (a) LRA LRA Section 4.3.1.2 addresses addresses the reactor reactor internals internals see no delta-temperature delta-pressure during heatup/cooldown delta-temperature or delta-pressure heatup/cooldown as as vessel internals. Indicate Indicate whether the CUFs listed they are surrounded by reactor coolant and and not exposed exposed to containment containment in Tables 4.3-5 and 4.3-6 are based only on in atmosphere.)
atmosphere.) The reactor vessel that are significant The design transients for the reactor significant for a design thermal thermal transients used in the reactor specific specific internals component component are included in the individual component individual component vessel analysis. calculation.
calculation. The CUFs are then determined determined based on the component-specific component-specific loadings during these transients. No other transients transients are included in the internals internals (b) Explain why the CUF (0.173) for the IP2 upper fatigue fatigue analyses.
analyses.
support plate is so different different from the IP3 (0.81)
(0.81) value. For a specific calculation CN-RCDA-03-51 evaluated specific example, IP2 internals calculation evaluated 5% 5% unit unit unloading, 10%
10% step step load, load, step load reduction from 100% to 50%, loss of flow in one one loop, loss loss of load, reactor trip, and loss of secondary secondary pressure.
For additional additional information, information, the summaries of the power uprate uprate evaluations for the the reactor vessel vessel internals internals are available in section section 5.2.5 of WCAP-16156 WCAP-16156 for IP2 and WCAP-16211 for IP3.
(b) The IP3 analysis was aa later analysis performed for the IP3 power power uprate that used aa different cross cross section of the upper support support plate than for the older IP2 IP2 analysis. The IP3IP3 analysis resulted in in a higher higher CUF of 0.81.
0.81. The result of the.IP3 the,lP3 analysis is also applicable applicable to IP2. The LRA will be revised to change the CUF value value for the IP2 upper upper support plate in Table 4.3-54.3-5 to 0.81.
0.81.
Information Information to be incorporated incorporated into the LRA.
9 In LRA 4.3.1'.3 In 4.3.1-.3 (Pressurizer),
(Pressurizer), the applicant states (a) Section 6 of WNET-108, "44 Series ofWNET-108, Series Pressurizer Pressurizer Stress Report," states that that that the impact impact of steady state fluctuations fluctuations on steady state state oscillations oscillations are not significant in meeting condition condition (b) of code code pressurizer pressurizer fatigue determination determination is "not paragraph N415-1 for the pressurizer paragraph pre~surizer shell. All six conditions were met, and no no significant." fatigue analysis (calculation of CUFs) of the pressurizer pressurizer shell was performed.
Please describe any engineering (a) Please engineering analysis that (b) LRA Section 4.3.1.3 contains aa typographical error. ItIt should have stated stated 10 to was performed performed to make the determination of "not the sixth power or 1 E6 oscillations oscillations rather than 106 oscillations. WNET-108c1early WNET-108.clearly significant." uses 1 E6 steady steady state oscillations.
(b) The second second paragraphparagraph on LRA LRA 4.3.1.3 states: Clarification Clarification to be incorporated into the LRA.
"The stress "The stress report analyzed analyzed the 106 steady state oscillations oscillations only for condition N 415.1(b)," Please 415.1(b):" Please (c)
(c) See See Section Section (c) of Question Question 7 for aa discussion of the significance significance of these these confirm if if the analysis is based on 1 106 06 steady oscillations. WNET-108 utilizes the code code of record for IP2/IP3 - ASME ASME Section III, III, state oscillations, oscillations, and not 1 10E6 OE6 steady state state 1965 through through the Summer Summer of 1966 addenda.
oscillations.
(c) What supports the statement statement that the steady state oscillations oscillations are not significant to fatigue.
Quote the code year used to justify justify this response.
10 TLAA 4.3-8 The The original design bases bases of the IP2 RCS did not includeinclude any feedwater feedwater cycles even though though the original steam generators had had been been designed designed for 25,000 feedwater The first sentence sentence of LRA page 4.3-3 states: cycles. This was basedbased on the assumption that feedwater feedwater cycling had no significant significant impact on the RCS beyond the steam generators.
"Feedwater cycling, a replacement replacement steam generator design transient limited to 18,300 generator 18,300 However, during the design of newer newer vintage plants, Westinghouse Westinghouse added 2,000 2,000 cycles, does not appear appear on Table 4.3-1.4.3-1. The value value feedwater feedwater cycles cycles to the RCS specification. The rationale rationale for the difference between of 18,300 18,300 is the projected value value for 40 years of of the steam generator generator and the RCS cycles was that a majority of the 25,000 steam steam generator steam generator operation." operation." generator cycles consisted of relatively generator relatively low amounts of cooler water which had littl~ little impact on the bulk secondary secondary side water temperature and therefore no measurable water temperature measurable Feedwater Feedwater cycling, cycling, however, is listed as a design design impact on the RCS components. During subsequent designs, Westinghouse During subsequent Westinghouse v;;-:-; r'
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Thursday, Thursday, March March 20, 20, 2008 Page 3 of 16
Item Request Response transient in Table 4.3-1 with 2,000 analyzed decreased the number decreased number of steamsteam generator feedwater cycles from 25,000 18,300 25,000 to 18,300 cycles. Please clarify which number number is the correct to better better reflect actual operating operating conditions. The 2,000 cycles (from Table Table 3-3 of design basis. . WCAP-12191, WCAP-12191, Revision 3) listed in in Table 4.3-1 relate relate to the RCS cycles which correspond to 18,30018,300 (from Table 6.1-2 of Westinghouse Westinghouse Calculation Calculation Note CN-SGDA-02-214) (25,000 for the original steam generators) feedwater feedwater cycles cycles experienced by the steam generators, primarily primarily the feedwater nozzles.
WCAP-12191, Transient and Fatigue Cycle Monitoring Program Transient History WCAP-12191, Transient Evaluation Report for Indian Indian Point Unit 2, Addendum Addendum 1, September, 2003 CN-SGDA-02-214, 4.7% Uprate CN-SGDA-02-214, Uprate Structural Structural Evaluation Evaluation of Primary and Secondary Side Components Components for the Indian Point Unit 2 (44F), 10% 10% plugging, plugging, 2/25/2005 Section 4.3.1 4.3.1 at the top of LRA LRA Page 4.3-3, will be revised revised as follows.
follows.
Feedwater cycling is a transient Feedwater transient that affects the replacement replacement steam generators. The The generators are analyzed steam generators analyzed for 18,300 cycles. However, the 18,300 18,300 cycles do do not appear on Table 4.3-1 since these cycles have have no significant impact impact on the the Instead, Table RCS. Instead, Table 4.3-1 includes 2000 feedwaterfeedwater cycles. These are cycles that are significant significant enough to affect affect the RCS.
As part of IPEC Commitment #6, the IP2 procedure procedure will be reviewed to ensure for for the feedwater cycles, the number number of cycles listedlisted is consistent consistent with the design design requirements and to evaluate any necessary changes changes to the description of the event used in in the cycle cycle counting procedure.
11 TLAA 4.3-9 TLAA4.3-9 (a) The transients transients in in Table 4.3-1 that exceed the analyzed numbers are in the "Other analyzed numbers Events" category. These These events do not contribute to the reactor vessel fatigue. Thus Thus (a) LRA Table Table 4.3-1 includes IP2 IP2 design transients the vessel fatigue fatigue analysis remains valid. The exception exception is steady state cycles.
whose 60-year projections exceed 60-year projections exceed design cycles. Reevaluation Reevaluation of the number of steady steady state cycles is included included in in Commitment 6.
However, However, LRA Section 4.3.1.1 states "the "the projected projected numbersnumbers of transient cycles cycles used for Since Since the Fatigue Monitoring Program assures that the analyzed numbers of cycles Fatigue Monitoring cycles reactor reactor vessel fatigue analyses remain within are not exceeded, IPEC will clarify LRA LRA Section 4.3.1.1 to show that the effects of analyzed values," and invoked analyzed invoked the 10 10 CFR fatigue will be managed managed by the Fatigue Monitoring Program in accordance Fatigue Monitoring accordance with 10 2
54.
54.211(c)(1 (c)(1)(i)
)(i) for its reactor vessel TLAA. Please 54.21(c)(1)(iii).
CFR 54.21 (c)(1 )(iii). Section 4.3.1.1 will be revised revised to read as follows.
justify justify thisthis conclusion.
conclusion.
4.3.1.1 Reactor Vessel The response should clarify whether whether there are The reactor pressure pressure vessel (and appurtenances) appurtenances) fatigue analyses were performed performed certain events events that do not contribute to fatigue in accordance accordance with the requirements requirements of the ASME Boiler Boiler and Pressure Pressure Vessel Code, usage usage of the reactor vessel. Section I11,1965 Edition, 1966 and 1967 addenda.
Section 111,1965 addenda. (A complete complete listing of applicable applicable codes is given given inin Tables 4.1-9 of the IP2 and IP3 UFSARs.) UFSARs.) The existing fatigue fatigue (b)
(b) The LRA indicates indicates that no transients transients analyses analyses of the reactor vessel are considered TLAA because they are based on applicable applicable to the reactor vessel are projected to numbers numbers of cycles expected in 40 years of operation. operation. TheThe exceed exceed their analyzed analyzed number. CUFs for the reactor pressure vessel are given given in in Table 4.3-3 for IP2 and Table 4.3-Verify that the Loss of Load transient, predicted to 4 for IP3.
IP3. .
reach 12 12 cycles with only 10 10 allowed, was not Design cyclic cyclic loadings and thermal conditions for the reactor pressure vessel were were used in analysis of the reactor vessel. Provide Provide the originally originally defined defined in in the design design specifications specifications and analyzed analyzed in the original original vessel basis (reference) for your your response. stress reports. These analysesanalyses have beenbeen occasionally revised, revised, most recently recently for the the extended power uprate. These latest analyses are reflected in the current current UFSAR tables. As described described in Section 4.3.1,4.3.1, the projected numbers of transient projected numbers transient cycles used for reactor vessel fatigue analyses analyses remain within analyzed values. The effects of fatigue on the reactor vessel will be managed managed by the FatigueFatigue Monitoring Monitoring Program Program in in accordance with 10 10 CFR 54.21(c)(1)(iii) 54.21(c)(1 )(iii) for both IP2 IP2 and IP3.
(b) The 10 loss of power transients listed for IP2 in LRA LRA Table 4.3-1 are loss of the the turbine generator generator bus followed followed by reactor and turbine trips. LRA Table 4.3-1 will be be revised to clarify the definition of loss of power power transients. These transientstransients are not used in in the reactor reactor vessel fatigue analyses analyses for either either unit, and are not listed listed in either FSAR FSAR Table Table 4.1-8 4.1-8 or in in LRA LRA Table 4.3-1 for IP3. Loss of power is not not included included in in the original OEM OEM stress report for IP2 nor is itit includedincluded in the design design transients transients that support the power (C&MS/POAC(02)-007CN, "Design Transient Revisions power uprate (C&MS/POAC(02)-007CN, Revisions Indian Point 2.4% Uprating," Revision 1, March, 2005). Therefore the statement for Indian statement "the projected that "the projected numbers numbers' of transient cycles cycles used for reactor reactor vessel fatigue fatigue analyses remain analyses remain within analyzed values" within analyzed values" isis aa valid statement.
valid statement.
Loss of power events events were added to the IP2 cycle counting counting procedure becausebecause there are are 40 loss of power power transients analyzed in the power uprate analysis for the power uprate the IP2 steam generators generators [SGDA-02-214,
[SGDA-02-214, "4.7% Uprate Structural Evaluation of Primary and Secondary Secondary Side Components for Indian Indian Point Unit 2 (44F), 10% 10% Plugging,"
Revision 0, February, 2005]. As part part of License Renewal Commitment Commitment 6, IPEC will determine why there determine there are only 10 loss of powerpower events in in the IIP2 P2 transient transient monitoring monitoring procedure procedure while 40 are assumed in in the analysis. The Fatigue Monitoring Program Fatigue Monitoring will continue to manage manage the effects of fatigue by counting these cycles and requiring requiring u'-'~' ','-1:,;-~~~mE;'::::::::.:"?~~ommmmtt~"";11~>:tm~'.<,~:~X:~.'i ý-, z, Thursday, March Thursday, March 20, 20, 2008 Page 4 o 16
Item Request Response action to be taken if the actual number of cycles approaches the cycles allowed by action to be taken if the actual number of cycles approaches the cycles allowed by the procedure.
Clarification to be incorporated incorporated into the LRA LRA 12 TLAA 4.3-10 4.3-10 The transients associated associated with the charging system do not affect the reactor vessel internals (Section 4.3.1.2), pressurizer pressurizer (Section 4.3.1.3), steam generators generators (Section As described described in in LRA Section 4.3.1.24.3.1.2 through LRA 4.3.1.4), reactor reactor coolant pumps (Section 4.3.1.5), or control mechanisms control rod drive mechanisms Section 4.3.1.8, in light of IP2 design transientstransients (Section 4.3.1.6). TheseThese TLAA remainremain valid as stated as long as the analyzed whose 60-year 60-year projections projections exceed the design values for the relevant relevant transients transients are not exceeded. Since Since the FMP is relied on to to cycles, the applicant applicant made same statement (refer assure that the numbers of transients do not exceed the analyzed values, IPEC will to the previous question) question) for the fatigue analyses analyses credit the FMP for managing the effects effects of aging for the period of extended extended of the associated associated components. Please justify the the operation in in accordance accordance with 10 CFR 54.21(c)(1 )(iii). )(iii). .
conclusion conclusion for each component. Section 4.3.1.7, the regenerative As described in Section regenerative heat exchangerexchanger TLAA is projected component specific analysis and extrapolation based on aa component extrapolation of the transients incurred incurred Is the loss of power event event considered considered in the the at the time of that analysis. The projected CUF CUF based based on the projected number number of reactor reactor vessel internals internals CUFs?CUFs? What What is the basis basis cycles, 0.13, is well below the limit of 1.0 1.0 such that a detailed re-analysis re-analysis is not not (reference)
(reference) for this answer. required. The charging nozzles nozzles are more limiting than the heat heat exchangers exchangers and consequently there is no fatigue analysis for the heat exchangers. In consequently In Section 4.3.1.8, only the charging system piping is affeCted affected by the charging charging system transients. As described in Section Section 4.3.1.8, the charging charging system piping may exceed* exceed its analyzed number of transients. This piping, piping, including the charging nozzle, will be be reevaluated with the other NUREG/CR-6260 reevaluated NUREG/CR-6260 locations as discussed discussed in in LRA Section Section 4.3.3.
The latest 1P2IP2 reactor vessel vessel internals internals fatigue fatigue analysis analysis is in calculation calculation RCDA-03-51 Revision1, Revision1, which in in turn references references Westinghouse Westinghouse Leiter Letter LLTR-SSO-03-043, TR-SSO-03-043, Rev 1, dated April 25,2003, "Design TransientTransient Revisions for Indian Point Unit 2 4.7%
Uprate Program. This leiter letter is internal Westinghouse Westinghouse correspondence correspondence that is not not available available on site.
The latest IP3 reactor vessel internals fatigue analysis is in calculation RCDA calculation RCDA 108 which in in turn references Westinghouse turn references Westinghouse Leiter Letter LLTR-SCS-03-053, TR-SCS-03-053, "Design Transient revisions for IndianIndian Point 3 Stretch Power Uprate Project Project - Revised Figures", dated 21, 2003. There is no loss of power event in dated August 21,2003. in this reference.
reference.
Loss of power power was a transient considered in in the fatigue analyses for the the replacement steam replacement steam generators.
generators.
LRA Sections 4.3.1.2 thru 4.3.1.7 and all sub-parts of Section Section 4.3.1.8 except except ANSI B31.1 piping will be revised to state that the effects of aging will be managed 831.1 managed by the the Fatigue Monitoring Program for the period of extended operation Monitoring Program accordance with operation in accordance 54.21(c)(1)(iii). (See the response to question TLAA-4.3-9 10 CFR 54.21(c)(1)(iii). TLAA-4.3-9 for an example.)
LRA Tables Tables 4.1-1 and 4.1-2 will be revised to reflect the changes in Sections 4.3.1.2 Sections 4.3.1.2 thru 4.3.1.8. LRA Sections A.2.2.2.1 and A.3.2.2.1 A.3.2.2.1 will be revised to state state that thethe effects managed by the Fatigue Monitoring effects of aging will be managed Monitoring Program for the period of extended operation in accordance accordance with 10 CFR 54.21 54.21(c)(1)(iii).
(c)(1 )(iii).
Clarification to be incorporated incorporated into the LRA.
13 4.3-11 TLAA 4.3-11 (a) Table T~ble 4.3-7 4.3-7 lists the CUFs of record for the.IP2the IP2 pressurizer. These CUFs, from from the fatigue analyses of record in the current licensing licensing basis, do not assume assume LRA LRA Table 4.3-7 lists CUFs for various various insurge/outsurge transients. The LRA states th~t insurgeloutsurge that this analysis of record (a TLAA) will subcomponents subcomponents of IP2 pressurizer. The applicant applicant remain valid for the period of extended extended operation operation because because nothing associated associated with concludes: 20 more years of operation operation invalidates invalidates the analysis.
"None of the design design transients transients used in in the analysis of the pressurizer will be exceededexceeded as discussed (b) The pressurizer fatigue analysis (CN-SGDA-03-118, "Evaluation of the The latest IP3 pressurizer the in Section 4.3.1.
4.3.1. The pressurizer pressurizer fatigue analyses analyses Indian Indian Point Unit 3 Pressurizer Pressurizer for the 4.8% Uprate Program," September September 2003) will thus remain valid for the period of extended extended updated updated CUFs for the spray spray nozzle, the upper upper shell, and the SRV nozzle but did not operation operation in accordance accordance with with . update the CUFCUF for the surge nozzle. The The CUF of record for the IP3 IP3 surge nozzlenozzle 11OCFR54.21 (c)(1)(i)."
OCFR54.21 (c)(1 )(i)." comes from NYPA calculation IP3-CALC-RCS-00568, IP3-CALC-RCS-00568, "Calculation of Pressurizer Pressurizer Fatigue Fatigue Usage Factor from WCAP-13491 WCAP-1 3491 ," ," January, (a) Since Table 4.3-7 did not consider consider 1993. This utility analysis is based on WCAP-13491, WCAP-13491 , "Evaluation "Evaluation of the Effects of insurge/outsurge, insurgeloutsurge, explain how how you reach the the Insurge/Outsurge Transients InsurgelOutsurge Transients on the Integrity Integrity of the Pressurizer Pressurizer at New York Power Power above above conclusion.
conclusion. Indian Point Unit 3," October Authority's Indian October 1992. WCAP-13491 WCAP-13491 calculated the CUF at 0.4319 0.4319 at that point in in time, considering the insurges and outsurges outsurges that had (b) Table 4.3-7 shows that in in general the IP2 occurred during the 40 plant heatups occurred heatups that IP3 had experienced.
experienced. IP3-CALC-RCS-IP3-CALC-RCS-CUFs for the pressurizer pressurizer are higher than the IP3 IP3 00568 extended the CUF calculation in WCAPc WCAP-1349113491 to the 40 year life of the plant CUFs in Table Table 4.3-8. Discuss why the IP3 CUF CUF conservatively assuming insurges and outsurges would occur by conservatively occur during the the will be representative representative of the IP2 CUF for the the remaining remaining 160160 heatups that remained to reach the 200 200 heatups heatups previously analyzed pressurizer surge pressurizer surge line line nozzle. AreAre there there basis basis for fatigue. IP3-CALC-RCS-00568 IP3-CALC-RCS-00568 calculatedcalculated a 40 year CUF of 0.9612.
documents documents (references)
(references) to support support these CUFs?CUFs?
The review of the IP2 pressurizer pressurizer for the recent recent power uprate uprate (CN-SGDA-03-57, (CN-SGDA-03-57, Rev. 1,1, "Evaluation of the Indian Point Point Unit 2 Pressurizer Pressurizer for the 4.7% Uprate Uprate ltxr ,... :-L "t:,.}I.'~~~:,.~u, , '
Thursday, Thursday, March March 20, 2008 Page 5 of16 of 16
Item Request Request Response
Response
October 2003) updated CUFs for the spray Program," October spray nozzle, the upper shell, and and the SRV nozzle. It did not update the CUF for the surge nozzle. The CUF of record for the IP2 surge nozzle remains 0.264 calculated in 0.264 as calculated in WNET-108, "Consolidated Edison Company Pressurizer Pressurizer Stress Report," April 3, 1969.
WNET-108 does not account account for insurge/outsurge.
If If the IP2 surge nozzle nozzle was to be reanalyzed for insurge/outsurge, insurge/outsurge, itit is expected expected thethe resulting increase increase would be similar to the increaseincrease for IP3. Since both plants had CUFs of 0.26 (0.2589 and 0.264) without insurge/outsurge, insurge/outsurge, then both would be be expected to have CUFs of approximately 0.96 for 200 heatups with insurge/outsurge. However, this analysis was insurge/outsurge. was not performed performed for IP2.
Both the IP2 and IP3 surge nozzles nozzles must must be re-evaluated for environmentally environmentally assisted fatigue fatigue and IPEC has has committed to that re-analysis prior to the period of extended extended operation.
That re-analysis will include not only environmental factors, but also the effects effects of insurge/outsurge insurge/outsurge for both units.
Section Section 4.3.1.3 (bottom of page 4.3-13 to top of page 4.3-14) will be revised to include include the following following points points from the above above discussion.
discussion.
IfIfthe IP2 surge nozzle was to be reanalyzedreanalyzed for insurge/outsurge, insurge/outsurge, it is expected expected thethe resulting resulting increase would be similar to the increase for IP3. Both plants had CUFs of approximately approximately 0.26 (0.2589 and 0.264) without consideration insurge/outsurge, consideration of insurge/outsurge, both would would have CUFs of approximately approximately 0.96 for 200 heatupsheatups with consideration consideration of insurge/outsurge. However, no TLAA to address insurge/outsurge insurge/outsurge exists for IP2.
Both the IP2 and and IP3 surge surge nozzles will be re-evaluated re-evaluated for environmentally environmentally assisted fatigue fatigue prior to the period period of extended extended operation.
operation. That re-analysis will be performed performed under the Fatigue Monitoring Monitoring Program accordance Program in accordance with 10 CFR 54.21 54.21(c)(1)(iii)
(c)(1 )(iii) and will consider not only environmental environmental factors, but also the effects effects of insurge/outsurge insurge/outsurge for both units.
Clarification to be incorporated incorporated into the LRA.
14 TLAA 4.3-12 4.3-12 (a) At the time the LRA was was prepared, prepared, the IP3 cycle count for plant heatups and plant cooldowns had only been reduced from the raw data through through 12/31/1995.
LRA Table Table 4.3-2 does does not provide the actual Thus, this data was used in in the LRA. A review of additional data shows there there were cycles as of 3/21/2006 for "Plant Heatup Heatup at 100F 1OOF additional heatup/cooldown approximately 15 additional heatup/cooldown cycles from 1/1 /1996 through 1/1/1996 through per hour" and "Plant Cooldown at 100F 1OOF per hour." 3/31/2006, bringing the total to 55.
(a) What are the actual occurrence as of actual occurrence (b) The LRA projection was done done based on the data through 1995 because because that was was 3/31/2006?
3/31/2006? the data readily available. Subsequently Subsequently additional additional data through through 3/31/2006 has has identified and evaluated resulting in a new projection of 109 been identified 109 Please clarify clarify why there are no longer any heatups/cooldowns in 60 years, versus the 120 heatups/cooldowns 120 projected in the LRA. LRA Table Table hydrostatic tests required hydrostatic performed at IPEC.
required or performed 4.3-2 will be amended to show these revised revised values.
(b) Why do these two transients transients use a different different The reduced reduced rate of occurrence occurrence of heatups/cooldowns heatups/cooldowns from 1996 to 2006 2006 confirms confirms extrapolation method, which was projected based that the rate of on the operating operating history (1975-1995),
(1975-1995), in in occurrence of cycles was higher early in plant life, making occurrence making projections based on determining the 60-year projection.
determining projection. recent years years more more realistic. The projection of cycles cycles is not relied relied on to assure assure code compliance.
compliance. As As (c) (Added during breakout meeting during site site described in described in LRA audit.) Add aa note to the LRA that the hydro tests audit.) Section Section B.1.12, the Fatigue MonitoringMonitoring Program ensures the validity of analyses analyses that are no longer required by the ASME Section XI lSI ISI explicitly analyzed a specified explicitly specified number of fatigue transients transients by assuring that the the program.
program. actual effective number of of transients does does not exceed exceed the analyzed analyzed number number of transients.
(c) Section Section XI of the ASMEASME Code, Inservice Inservice Inspection, Inspection, has been modified such that that leak tests are now specified specified instead of hydrostatic hydrostatic tests. Footnote 2 to LRA Tables Tables 4.3-1 and Footnote 3 to LRA LRA Table 4.3-2 will be revisedrevised to say these these hydro test projections reflect changes changes to ASME Section XI. XI.
Clarification Clarification to be incorporated incorporated into the LRA. .
15 TLAA 4.3-13 4.3-13 (a) IP2 IP2 and IP3 instituted instituted operating changes consistent with the generic generic Westinghouse Westinghouse program to to On page On page 4.3-18, the the LRA describes describes IP2 and IP3 IP3 address surge line thermal cycling. There There were were two mainmain changes.
responses to NRC Bulletin 88-11,88-11, indicating indicating that changes were made to its operating operating procedures. First. A continuous (reduced flow) pressurizer pressurizer spray was established.
established. This This minimized the temperature temperature differential differential between the RCS, the pressurizer, and the the (a) Discuss Discuss the modified modified operating procedures operating procedures surge line, thereby reducing the thermal stresses associated with an insurge.
stresses associated used to mitigate pressurizer insurge/outsurge mitigate the pressurizer insurge/outsurge transients. Second. Startup procedures were changed to eliminate drawing and then collapsing (b) Is the mitigation strategy strategy factored into the the a pressurizer pressurizer bubble to run reactor coolant pumps pumps to sweep air out of the the
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Thursday, Thursday, March March 20, 20, 2008 Page 6 of 16 Page
Item Request Response determination determination of IP3 pressurizer pressurizer surge line nozzle RCS/RPV. The collapsing of this bubble bubble early in the startup procedure had resulted CUF of 0.9612? How was the fatigue usage usage prior in significant insurges in insurges that have now been eliminated.
to the use of modifiedmodified operating operating procedures procedures captured in in the fatigue evaluation?
fatigue evaluation? (b) The mitigation strategy strategy was not factored into the determination determination of the IP3 IP3 pressurizer surge line nozzle nozzle CUF. The calculation that determined determined the CUF of (c) What plant procedures were modified to 0.9612 assumed the operating operating conditions implementation of the conditions that existed prior to implementation the minimize the effects of pressurizer insurge and modified operating modified operating procedures.
procedures. The operating conditions before implementationimplementation of outsurge? Does the actual actual plant data before before and modified procedures modified procedures were conservatively conservatively applied applied to determine determine both both the contribution contribution after after these changes were made made support that these to the CUF from past operation and the contributioncontribution to the CUF due due to projected projected changes changes reduced the occurrence and the severity future operation.
operation. The delta-T(emperature)s delta-T(emperature)s used in in the analysis analysis were developed of these transients?
transients? Please Please provide provide the revised revised from plant operating operating records from a number of plants. This historical delta T procedure so that the onsite NRC auditors can information was information was used to represent the prior operating operating history of the Indian Point Point review the changes that were made. units, andand to calculate fatigue usage usage due to future operation.
operation. The IP3 surge nozzle nozzle CUF of record record was calculated in IP3-CALC-RCS-00568, IP3-CALC-RCS-00568, Revision 0, issued in in 1993.
Prior to this calculation, the CUF of record was the 0.259 calculated calculated in the original stress report for the pressurizer. The The original stress report had no analysis of insurge/outsurge.
insurgeloutsurge.
c) Plant procedures that were were changed 2-POP-1.1, "Plant Heatup changed include 2-POP-1.1, Heatup from Cold Cold Shutdown Condition; 2-POP-3.3, "Plant Cooldown, Mode 3 to Mode Shutdown Condition; Mode 5," 3-POP-1.1, 3-POP-1.1, "Plant Heatup from Cold Shutdown Shutdown Condition," 3-POP-3.3, "Plant Cooldown - Hot to to Cold Shutdown." Results Results of the changes are discussed discussed in in Interoffice Interoffice Correspondence IP-DEM-01-008MC, Correspondence IP-DEM-01-008MC, "IP3 Pressurizer Pressurizer Surge Line Stratification Stratification- -
WR-96-6280-02."
WR-96-6280-02."
The letter notes that after procedure changes, the maximum maximum difference between the the pressurizer pressurizer and surge line and the RCS was 227F, well within the 320F limit. The The letter letter concludes that the procedure effectively lowered the delta F and procedure changes effectively eliminated insurge/outsurge transients. Plant procedures, the interoffice eliminated insurgeloutsurge interoffice memorandum, memorandum, and and plant data were made available available for the NRC auditorsauditors to review on site.
16 16 TLAA TLAA4.3-144.3-14 The IP2 surgesurge line fatigue fatigue analysis was evaluated evaluated for SPU as described in the the following following paragraph paragraph from WCAP-16156, WCAP-16156, "Indian Point Nuclear Nuclear Generating Unit No.
LRA page 4.3-13 states: 'The "The IPEC pressurizers pressurizers 2, Stretch Power Uprate Uprate NSSS Engineering Report," February NSSS Engineering February 2004, 2004, Section were evaluated for the stretch power uprates and 5.4.1.2.2.
cumulative cumulative usage factors were updated," updated." This This resulted resulted in in no change change to the CUF, it remains "For the pressurizer pressurizer surge line, the effect of the designdesign transients transients with respect to the the 0.264. Explain Explain why the stretch power uprates uprates had thermal thermal stratification stratification and fatigue analysis was controlled by the L'.T AT between the the no impact impact on the surge line CUF. pressurizer temperature temperature and the hot leg temperature.
temperature. The controlling controlling L'ATs
.Ts for the the pressurizer surgesurge line were were associated associated with heatup and cooldown events that were not affected affected by the SPU.SPU. Therefore, Therefore, the SPU will have have no adverse effect effect 6n on either the thermal thermal stratification or the fatigue analysis for the pressurizer pressurizer surge surge line, and the limiting the limiting transients transients in in WCAP-12937 (Reference 8)
WCAP-12937 (Reference 8) remain remain valid."
valid."
Reference 8 is WCAP-12937, Reference WCAP-12937, Structural Structural Evaluation Evaluation of Indian Point Units Units 2 and 3 Pressurizer Surge Lines, Considering Pressurizer Considering the Effects of Thermal Stratification, Stratification, May 1991. 1991.
Section 5.4.1.2.2 of WCAP-16211, WCAP-1 6211, "Power UprateUprate Project, Indian Point Unit Unit 3 Power Engineering Report:
Plant, NSSS Engineering Report," June 2004 makes the same statement statement for IP3.
17 TLAA 4.3-15 (a) As can be seen by review of Tables 4.3-1 and 4.3-2, IP2 is projected to have have more cycles of heatups, cooldowns, and reactor trips than IP3, based in in part on IP3IP3 LRA 4.3.1.7 discusses bounding CUFs for IP2 and having having learned lessons lessons from the early operation of IP2. Based on these projections, projections, IP3 Class 1 heat exchangersexchangers and the use of IP2 it is expected that the IP2 CUF will exceed the IP3 CUF. Conservatively, assume Conservatively, assume CUF CUF to to project project the the IP3 IP3 CUF.
CUF. the CUFs are approximately the same. As identified identified inin LRA Section 4.3.1.7, since since the IP2IP2 CUF is only 0.13, it follows that the IP3 CUF is also well below the limit of 1.
(a) IP2 IP2 and IP3 IP3 were operated by different This large margin to a CUF of 1 makes this general statement statement appropriate.
appropriate. (WCAP-organizations organizations for a long time before before Entergy Entergy took 12191 calculated an IP2 CUF of 0.235 based on 2000 2000 thermal thermal cycles; however, the the over in 2001 2001 and 2000, respectively.
respectively. Hence, WCAP also noted that only 466 cycles had occurred through 10/31/1999. Projecting those those heat heat exchangers exchangers have have different different operating operating this number of this number cycles through of cycles through the the period period of extended extended operation gives 1072 operation gives 1072 cycles for for histories. Please justify why IP3 heat exchanger exchanger aa projected 0.235*1072/2000 =
projected CUF of 0.235*1072/2000 = 0.13.)
0.13.) As identified in Commitment 6, CUF is comparable comparable to IP2's IP2's CUF. enhancements enhancements are planned to the IP3 fatigue monitoring monitoring program provide program that will provide additional additional monitoring monitoring of the heat heat exchanger exchanger cycling.
cycling.
(b) This LRA section discusses discusses IP2 regenerative regenerative exchangers, IP2 excess letdown letdown heat exchangers, letdown (b) The term "auxiliary heat exchangers" used (twice) in LRA Section 4.3.1.7 4.3.1.7 heat exchangers, heat exchangers, and and IP3 IP3 auxiliary auxiliary heat heat includes the regenerative exchanger and the excess regenerative heat exchanger excess letdown letdown heat exchanger.
exchangers. There There are, however, no discussion discussion The generic Westinghouse determination determination that the regenerative regenerative heat heat exchanger exchanger is on IP3 regenerative regenerative letdown heat exchangers exchangers and limiting (WCAP-12191)
(WCAP-12191) applies applies equally to IP3 and to IP2. Thus the comparison comparison of the excess excess letdown letdown heat exchangers.
exchangers. Are IP3 the IP3 to IP2 is made in part (a) above. The The final two paragraphs paragraphs of LRA Section exchangers same as regenerative auxiliary heat exchangers regenerative 4.3.1.7 4.3.1.7 will be revised revised to read as follows.
letdown heat exchangers exchangers and the excess letdown letdown heat exchangers?
heat exchangers? Please Please explainexplain their their ... The IP3 auxiliary
... auxiliary heat heat exchangers exchangers have no plant-specific plant-specific evaluation.
evaluation. However, L....:1m'n.\'~~~,:~"!4~'..<,:~~~':,,~~1ll::'~""-~A-m~"';-c&'~".l::H~:<;.~.~a!wp.tt..-.
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Thursday, March Thursday, March 20, 20,20082008 Page 7 of 16
Item Request Request Response differences. operation between the two units indicates the results the similarity in design and operation results projected IP2 CUF is 0.13, itit follows that the IP3 CUF would would be similar. As the projected would plant-specific analysis, ifif performed, also be well below the limit of 1.0, such that aa plant-specific performed, would satisfy the code CUF limit. The Fatigue Monitoring Monitoring Program will count the the experienced by the units and require action if transients experienced if any analyzed analyzed numbernumber of approached during the period of extended operation.
transients is approached operation. Thus the aging aging effects due to fatigue fatigue on the Class 1 heat exchanges will be managed heat exchanges managed for the period period operation in accordance of extended operation OCFR54.21 (c)(1 accordance with 10CFR54.21 (c)(1)(iii).
)(iii).
IPEC design documents indicate that the auxiliary auxiliary heat exchangers exchangers are not the the components in the CVCS system. The charging nozzles on the cold legs are limiting components more more limiting. Therefore, monitoring monitoring of the charging nozzles will assure acceptability charging nozzles acceptability auxiliary heat exchangers. Because the charging of the auxiliary charging nozzle is one of the the locations identified by NUREG-6260 locations identified NUREG-6260 as requiring environmental adjustments to the environmental adjustments the fatigue analysis, this nozzle will be evaluated evaluated with the other NUREG-6260 NUREG-6260 locations locations as discussed in in Section Section 4.3.3.
Clarification to be incorporated Clarification incorporated into into the LRA.
18 18 TLAA 4.3-16 TLAA4.3-16 "At least 2 years prior to entering the period of extended operation, for the locations locations identified in LRA Tables 4.3-13 4.3-13 (IP2)
(IP2) and 4.3-14 4.3-14 (IP3), consistent with the Fatigue Fatigue LRA Tables 4.3-13 4.3-14 indicate that the 4.3-13 and 4.3-14 the Detection of Aging Effects, IP2 and IP3 will refine the current Monitoring Program, Detection following components' components' environmentally environmentally adjusted fatigue effects of reactor water fatigue analyses to include the effects water environment and verify that CUFs are all projected projected to exceed aa value of 1.0 usage factors (CUFs) are less than 1.0.
cumulative usage the cumulative 1.0.
during period of extended operation: IP-2 operation: IP-2 pressurizer surge pressurizer surge line piping, IP2 piping IP2 RCS piping This includes includes applying factors to valid CUFs determined applying the appropriate Fen factors determined in in charging system nozzle, and IP-3 charging IP-3 pressurizer accordance accordance with one of the following.
surge line nozzles and piping.
piping. The two tables also 1. For locations identified
- 1. in LRA Tables identified in (IP2) and 4.3-14 Tables 4.3-13 (IP2) 4.3-14 (IP3) existing (IP3) with existing indicate that there are no environmentally environmentally fatigue analyses valid for the period fatigue period of extended operation, use extended operation, use the existing CUF.
adjusted adjusted CUFs for the RCS piping SI nozzle (IP-2 (IP-2 plant-specific locations with a valid CUF may be evaluated.
- 2. Additional plant-specific evaluated. In and IP-3), RHR RHR Class 1 piping (IP-2 (lP-2 and IP-3) particular, the pressurizer pressurizer lower shell will be reviewed to ensure ensure the surge nozzle surge nozzle and RCS piping charging system nozzle (IP-3).
charging system (IP-3). remains the limiting component.
- 3. Representative Representative CUF valuesvalues from other plants, adjusted adjusted to or enveloping enveloping the IPEC IPEC On pages 4.3-22 and 4.3-23, Entergy Entergy provides its plant-specific external loads may be used if if demonstrated demonstrated applicable to IPEC.
corrective corrective action plan to address this issue. NRC-approved version of the ASME
- 4. An analysis using an NRC-approved ASME code or NRC-approvedNRC-approKed Please confirm fatigue usage factors will be confirm that fatigue be alternative (e.g., NRC-approved NRC-approved code case) may be performed performed to determine determine a valid developed developed for these locations this locations and that this CUF.
program will be included corrective action program included as aa commitment commitment on the Indian Indian Point LRA. During the period of extended operation, IPEC may also use one of the following extended operation, following options for fatigue management if ongoing monitoring indicates a potential for a fatigue management condition outside outside the analysis bounds noted above.
- 1. Update and/or refine the affected analyses describeddescribed above.
Consistent with the Fatigue
- 2. Consistent Fatigue Monitoring Program, Corrective Corrective Actions, repair or replace the affected locations replace exceeding aa CUF of 1.0.
locations before exceeding Option 1 Details Details processes that will be used to develop the calculations The processes calculations for Option (1) are management processes. These established design and configuration management established processes are These processes governed by Entergy's 10 CFR 50 Appendix B Quality Assurance governed Assurance (QA) program program and include design input include independent reviews ensuring that valid input verification and independent valid assumptions, external loadings, analysis methods, and assumptions, transients, cycles, external and environmental fatigue life correction factors will be used in environmental in the refined refined or new fatigue fatigue analyses.
analyses.
The analysis methods for determination of stresses and fatigue usage will be in accordance accordance with an NRC NRC endorsed Edition of the AmericanAmerican Society Society of Mechanical Mechanical (ASME) Boiler and Pressure Vessel Code,Section III Engineers (ASME) IIIRules for Construction of Nuclear Power Plant Plant Components Division Division 1 Subsection NB, Class 1 Components, Sub articles NB-3200 or NB-3600 as applicable applicable to the specific specific component.
IPEC will utilize design transients specifications as well as design transients from design specifications design information from typical PWR references to bound all operational transient information operational transients.
The numbers of cycles evaluation will be based cycles used for evaluation based on the design number of cycles and actual cycle projected out to the end of license cycle counts projected license renewal period period (60 (60 years).
Environmental effect on fatigue usage will be assessed assessed using methodology consistent with the GALL Report, Rev. 1, that states, "The sample of critical components can be evaluated environmental life correction evaluated by applying environmental correction factors to to the existing ASME ASME Code fatigue analyses. Formulae for calculating analyses. Formulae calculating the the environmental life correction factors are contained contained in NUREG/CR-6583 for carbon in NUREG/CR-6583 carbon
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Item Request Response and low-alloy steels and in NUREG/CR-5704 for austenitic in NUREG/CR-5704 austenitic stainless steels."
stainless steels."
The Fatigue Monitoring Monitoring Program tracks actual plant transients transients and evaluates evaluates these against the design transients. Cycle counts show no limits are expected to be be approached for the current license approached license term. The Fatigue Monitoring Program will ensure ensure that experienced by the plant remain within that the numbers of transient cycles experienced within the analyzed numbers of cycles, hence, the component CUFs remain below the the values calculated in the design basis fatigue evaluations. If If ongoing monitoring indicates a potential for a condition outside indicates outside that analyzed analyzed above, IPEC may perform further reanalysis of the identified identified configuration configuration using established configuration configuration management processes management processes as described described above.
Option 1 for refined CUF calculations is consistent with the NRC's recommendations NRC's recommendations for the periodic CUF updatesupdates in the "detection of aging effects" (i.e., program program element 4) 4) of GALL AMP X.M1, X.M1, "Metal Fatigue of the Reactor Reactor Coolant Coolant Pressure Pressure Boundary". .
Option Details Option 2 Details If Option (2) becomes If becomes necessary, necessary, repair repair or replacement replacement of the affected components components before fatigue usage calculations determine the CUF exceeds 1.0 will be in in accordance with established accordance established plant procedures governing repair and replacement procedures governing replacement activities. procedures are governed activities. These established procedures governed by Entergy's Entergy's 10 CFR 50 50 Appendix Appendix B QA Program and and meet the applicable applicable repair and replacement replacement requirements of the ASME ASME Code Section XI. Xl.
Repair or replacement replacement of the affected affected locations locations is aa corrective corrective action.
action. If If this option is selected selected for corrective corrective action, the repair or replacement replacement activities would be in in applicable provisions of the ASME Code Section Xl.
compliance with applicable compliance XI. Since the the implementation of repair and replacement replacement activities will be basedbased on applicable applicable ASME Code Section XI requirements, Option (2) is consistent the "corrective actions actions recommended in in GALL AMP X.M1,X.M1, "Metal Fatigue of the Reactor Coolant Coolant Pressure Boundary." .
,
Commitment 33 describes IPEC IPEC activities under the Fatigue Fatigue Monitoring Program Monitoring Program that will manage manage environmentally environmentally assisted fatigue in accordance with 10 CFR 54.21 (c)(1)(iii).
54.21 (c)(1 )(iii).
19 TLAA 4.3-174.3-17 Close Question 19 to Question Question 18. A combined response is provided provided as the the Question 18 response.
response.
Regarding TLAA on environmentally-assisted Regarding environmentally-assisted fatigue fatigue issues, in in Section 4.3.3 of the LRA (page (page 4.3-22), the applicant states that it will implement one or more more of the three three options described described on that page. Please provide information information on thethe methodology that will be used for the chosen option or options. Specifically, please address the the followings:
(a) IfIf Option Option (1) is chosen, describe the the methodology and methodology and the the process process that will be used to ensure that ensure that assumptions, cycles, transients, cycles, assumptions, transients, external loadings, Fen Fen values, and analysis analysis methods are valid valid for the refined or new fatigue analyses.
In the event the refined analyses performed In performed under Option (1) (1) result in CUFs greater greater than 1.0, 1.0, describe the option(s) that may be used in in addition to Option (1).
(b) IfIf Option (2) is chosen, describe describe the AMP in sufficient detail detail with regard regard to inspection inspection scope, inspection methods, inspection inspection methods, inspection frequency, frequency, andand inspection qualification techniques.
inspection qualification techniques.
(c)
(c) IfIf Option Option (3)
(3) is chosen, describe is chosen, describe how how the repair repair or replacement replacement activity will be implemented implemented in in accordance accordance with applicable applicable repair or replacement replacement requirements of the ASME Code Section XI. XI.
101 101 TLAA TLAA4.3-18 4.3-18 (a) This change was made in Entergy R-4147-00-1, "Reactor Vessel Entergy Calculation R-4147-00-1, Tensioning Tensioning Optimization Optimization Stress Report IndianIndian Point Units 22 and 3", dated 9 March (a) In (a) In the the LRA LRA Tables Tables 4.34.3 33 and and 4.3 4.3 4, 4, closure closure 2005, and covers 2005, and covers both IP2 and both IP2 and IP*3.
IP3. Table Table 11-1 I1-1 of this calculation of this lists the calculation lists the stresses stresses Thursday, March Thursday, March 20, 2008 Page Page 9 of of1616
Item Request Request Response studs are studs are listed listed with with aa cumulative cumulative usage usage factor factor of of and usage usage factors before before and and after after the optimization.
optimization. The The revised revised tensioning tensioning process process 0.944 along 0.944 along with an explanation explanation note note that that states, resulted in resulted in increased increased values of peak peak stress.
stress.
"The CUF CUF of of the reactor reactor vessel vessel studs studs was was revised The The main main reason reason for for the the increased increased stress stress is is that the revised revised tensioning tensioning procedure procedure based on the based the optimization optimization of of the stud stud tensioning tensioning relaxed relaxed the tolerance tolerance for for the the finalfinal elongation elongation of the the studs.
studs. TheThe maximum maximum stressstress with with procedures procedures and and aa UFSAR UFSAR change change is in process process to to the previous previous procedure procedure was was 93.10 93.10 ksi ksi while while the the maximum maximum stressstress with with the revised revised reflect reflect this this revision."
revision." procedure is 104.1 procedure 104.1 ksi. Calculation Calculation R-4147-00-1R-4147-00-1 is available available onsite onsite for for review.
Please Please describe describe how the revised revised tensioning tensioning (b)
(b) process process impacted impacted the stress calculation. Please stress calculation. Please 1) The site provided a copy site provided copy of pending FSAR of the pending change to the FSAR change the NRC auditors for NRC auditors for include the specific include specific values of of peak peak stresses, onsite review.
before before and after the revised revised tensioningtensioning process.
2)
- 2) The basis basis calculation calculation for this statement statement is R-4147-00-1, R-4147-00-1, which was was provided provided to Part Part (b) (b) came from from breakoutbreakout meetings meetings during during the the the NRC NRC for for on onsite site review review as Reference 9.5.73 as Reference 9.5.73 to LRD04, LRD04, the basis document document for site audit. This This was initially initially in the database database as as Section 4.3 of the LRA. The equations Section equations that were were used used to determine determine the revised question 136.
question stresses stresses are summarized summarized in Section Section 66 of this this calculation.
calculation.
(b)
(b) The The NRC NRC would would like like to review review the the basesbases 3)
- 3) Section Section III III of R-4147-00-1 and the associated of R-4147-00-1 Dominion Engineering associated Dominion Engineering behind Note 1 to LRA behind LRA Table 4.3-3 4.3-3 concerning conceming the the memorandum discuss using memorandum using the Westinghouse Westinghouse design design transients transients to to perform perform the the re-analysis re-analysis of of the RPV studs as follows: fatigue fatigue evaluation.
evaluation.
(1) The The new new FSAR FSAR change that that is is in progress.
progress. Copies Copies of the FSAR FSAR change change in progress progress and and Calculation Calculation R-414 7-00-1 were R-4147-00-1 were provided provided (2)
(2) The new new CUF CUF that that is is based based on the old old CUF. CUF. to the NRC NRC auditors auditors for for onsite onsite review. review.
(3)
(3) The CUFs CUFs are based based on on the old design design cycles.
102 102 TLAA 4.3-19 (a) There is no specific conservatism conservatism in the the assumption assumption of zero cycles cycles of this one one particular transient, "charging flow shutoff shutoff with delayeddelayed return return to service", however, LRA Section 4.3.1.8 4.3.1.8 states, "The IP2 charging IP2 charging conservatism conservatism does exist exist in the analysis from other other numbers transient cycles being numbers of transient being system system piping failure failure analyses determined determined the the less than than the analyzed analyzed values. Zero Zero projected projected cycles is realistic based on reviews of realistic based limiting CUF limiting CUF for the charging nozzle the charging nozzle as as 0.990.99 for for plant data data that show show that this event has not not occurred occurred to date.
date.
number of of analyzed analyzed transients transients shown in the last WCAP WCAP 12191 12191 Revision Revision 33 "Transient and and Fatigue Cycle Monitoring Program Program nine entriesentries in Table Table 4.3 1." Transient Transient History History Evaluation Report Report for Indian Point Unit 2-Addendum 1" Unit 2-Addendum 1" provides provides the basis for the IP2 transient cycles that that areare tracked tracked in procedure procedure 2-PT-2Y015.
(a) Please Please explain the conservatism conservatism behind behind Table Table 2.3-3 of of WCAP 12191, 12191, indicates indicates the projected number number of of cycles based on on the the projecting no transient projecting transient condition condition for "the "the charging charging detailed review of actual actual plant data through 10/31/99, and shows this projection data through projection flow shutoff flow shutoff with delayed delayed return to service." results in in an an acceptable acceptable CUF. CUF.
WCAP-12191 Revision 2 had 55 analyzed cycles cycles of charging flow shutoff with (b) Please Please explain why there will be no following delayed retum return to power. Revision Revision 3 modified analyzed numbers of cycles modified the analyzed cycles based transient conditions conditions in the future: letdown letdown flow on operating operating history. While the analyzed analyzed number number for charging charging flow shutoff shutoff with shutoff with delayed delayed return to service and charging charging delayed return to power power was reduced to 0, the analyzed numbers for other events analyzed numbers events flow shutoff with prompt return to service. were increased.
(b) ItIt is not expected expected that there will be a letdown letdown flow shutoff with delayed retum return to service nor nor a charging flow shutoff with prompt prompt return to service during the period peribd of extended operation operation based based on operating experience. The projections projections are based on the number of occurrences occurrences from 1999 through through 2005. Since Since there there were no cyclescycles experienced in experienced in this time period, the rate used in projection is zero and thus no in the projection no additional cycles are projected additional projected for the rest of plant life. This is a projected projected number, not the number that was analyzed analyzed to calculate calculate the CUF. The projected projected values in in' LRA Table 4.3-1 do not change change the analyzed analyzed number of cycles. Three letdown Three (3) letdown flow shutoffs with delayed return retum to service were analyzed analyzed and 101 charging flow shutoffs with prompt retum return to service were analyzed. analyzed.
The Fatigue Monitoring Monitoring Program will manage the effects effects of aging due to fatigue by monitoring the numbers of cycles and requiring action ifif the analyzed numbers are monitoring approached. Note that several of the other charging system transients approached. transients project above their analyzed analyzed numbers, and re-analysis of the charging charging system is anticipated prior to the period of extended operation. The Fatigue Monitoring Program will prior determine exactly determine exactly when that reanalysis reanalysis is required considering the number of occurrences of all analyzed occurrences analyzed transients. Also, as identified in in LRA Section 4.3.1.8, the charging charging nozzle nozzle is is one of of thethe locations requiring environmental locations requiring environmental adjustments adjustments to to the fatigue analysis, which will require require aa reanalysis of this nozzle as discussed discussed in in LRA Section 4.3.3.
When performing the fatigue analyses, appropriate conservatism will be added to appropriate conservatism to the analyzed the analyzed numbers numbers of of cycles.
cycles.
112 112 Section 4.3 of the Section the LRA has has no references references while while IPEC included the references references in in LRD04, the basis document for LRA Section 4.3.
other sections and other and SectionSection 4.3 of other Copies of the LRD04 references Copies references were were provided provided to the NRC NRC audit teamteam for onsite applications do. Why don't applications don't we have have references references for review. IPEC review. IPEC will review the key key references references in in LRD04 and add to to LRA Section 4.3 4.3 Section 4.3? any previously docketed any docketed references that that pertain pertain to that section.
section. References References that have not have not been previously docketed docketed are are available on site for review.
Clarification to be Clarification be incorporated incorporated into into the LRA.
,~;.<,~~~l~':~'J<~,'~~.::.~).'m&::r;h""%:..,~~,::rZ:t<l<~t.~t~,~m:~s::Y:~~~~~"0&-::::,::::*m~, ,,;r;::<<:rnF~7~~:,-::;;;, " :, ':~~:;;~;."~"i:':~'~m~,::m;w1lw;-/*t?:':'~'!m..'llliW.::X,':~'.~\l:>:,~c~"t'U~,':tr:lmtm:tlt::~,,: ::1""?:'i:l>'~~:~~~4;~<:l<~F"~~~'~~\:"A .. '," :',,~llifu>tm~
Thursday, Thursday, March March 20, 20, 2008 2008 Page 10 of 16 Page
Item Request Response 113 113 Reference 9.5.79 to LRPD04 LRPD04 is SE&PT-7712.
SE&PT-7712. SE&PT-SSAD-7712 was able to be be done quickly because it did not redo any of the quickly because the provides CUF estimates for Indian This letter provides Indian Point Point finite element analyses analyses to determine individual usage factors. Rather determine individual Rather it usedused the the 2 based MT-SME-281 (Ref. 1 to SE&PT-based on MT-SME-281 existing individual usage factors and merely summed them to estimate estimate the number number 7712). The reference 7712), reference is dated dated 6/3/1988 and the the occurred to that point in of transients that had occurred in time.
response was transmitted on 6/24/1988.
6/24/1988. How was was performed so quickly?
this performed quickly? SE&PT-SSAD-7712 does not calculate design CUFs based on design cycles.
SE&PT-SSAD-7712 Rather, it estimated the CUFs at that point in time. This calculation was part of a larger project project that also included WCAP-12191. calculation was to determine WCAP-12191. This calculation determine components had the largest actual CUFs which plant components CUFs in order to develop the the requirements for a transient and fatigue functional requirements fatigue cycle monitoring monitoring system; however, no such system was ever installed. Note that LRPD04, Section 2.5.9 2.5.9 concludes that this report does concludes does notnot calculate design CUFs CUFs and therefore is not a therefore is not a TLAA. Thus, this report is not mentioned calculation of record, and therefore calculation in the license renewal application.
application.
OW. '. T2 444~222 114 Why is MT-SME-281 MT-SME-281 quoted for design cycles in SE&PT-SSAD-7712 SE&PT-SSAD-7712 does not use an E-specification E-specification for input because because itit was not Reference 9.5.79 Reference 9.5.79 to LRPD04 (SE&PT-7712) calculate design CUFs based attempting to calculate based on design cycles. Rather, itit determineddetermined instead of an E-spec?
instead E-spec? Does IPEC have an the CUFs at that point in based on the transients that had occurred to date.
in time based specification or design specification equipment specification equipment specification for The input input document (MT-SME-281) provided the transients to date. The cycles (MT-SME-281) provided cycles piping?
piping? were actual cycles, not design cycles. This calculation quoted were calculation was part of a larger included WCAP-12191.
project that also included project WCAP-12191. The calculationcalculation was to determine determine which components had the largest plant components largest actual eUFsCUFs in in order to develop the functional requirements for a transient and fatigue requirements monitoring system; however, no such fatigue cycle monitoring system was installed. Note that LRPD04, Section 2.5.9 concludes was ever installed. concludes that this this calculation does does not calculate design CUFs and therefore is not a calculation of calculate design record, and therefore is not a TLAA. Thus, this report is not mentioned mentioned in in the license license renewal application.
IPEC does have an equipment equipment specification specification for piping. The specification was was provided provided for onsite review.
115 Note 2 to Tables 4.3-13 and Note and 4.3-14 states that 4.3-14 states As stated in LRA Section Entergy intends to calculate the CUFs for subject Section 4.3.3, Entergy RCS piping is designed to ANSI B31.1 831.1 and nono B31.1 locations, including consideration 831.1 locations, consideration of the effects of reactor reactor water water environment, environment, analyses were performed and no CUFs fatigue analyses CUFs at least two years prior to .the period of extended the period extended operation. .
calculated. Does the applicant were calculated. applicant intend toto calculate CUFs for these calculate locations?
these locations?
116 components on the IP2 LRA Table 4.3-13 has 2 components the Neither Neither unit (1P2 1P3) had eUFs (IP2 nor IP3) CUFs for three locations locations (the charging system nozzle, NUREG-6260 list that have NUREG-6260 have no eUFCUF while IP3 LRA LRA the safety injection nozzle, or the RHR class 11 piping) piping) as part of the original design, design Table 4.3-14 4.3-14 has 3 components that have no no All of these locations locations were were built to USAS 831.1 B31.1 rather than ASME III. Ill.
CUF. Please explain CUF. Please explain this this difference difference between between units.
units. After a period of operation, IP2 IP2 noticed that they were were using the charging system recommended by the OEM.
nozzle at a higher rate than recommended OEM. (I.e. they they weren't using the the alternate charging alternate charging nozzle as frequently recommended.) Consequently, IP2 frequently as was recommended.)
performed a fatigue analysis of the charging nozzle to assess assess the effect effect of this this operation. The result of that analysis is quoted in LRA Table operation. Table 4.3-13.
IP3 did not perform calculation and they therefore have no corresponding perform such a calculation corresponding CUF in Table Table 4.3-14.
117 IP3 Section 4.3.1.8 of the LRA discusses discusses the IP2, As stated in LRA Section 4.3.1.8, these nozzles designed and built to USAS nozzles were designed USAS loop 3 accumulator accumulator nozzle. Explain in in more detail B31.1 and did not require the calculation 831.1 CUF. However, after calculation of a CUE. after a period period of why an analysis was done specific nozzle done for this specific nozzle discovered that the Loop 3 accumulator nozzle thermal sleeve was no operation, IP2 discovered no and not and not the accumulator nozzles other accumulator the other nozzles on on IP2 and IP2 and place. IP2 performed aa fatigue analysis of this nozzle (without a thermal longer in place.
IP3 IP3 acceptable for service in that condition.
sleeve) to show that itit was acceptable condition. The analysisanalysis done specifically for this one was done one nozzle and does not apply to the remaining remaining nozzles as the thermal sleeves remain in place. place.
118 118 The final paragraph of LRA LRA section section 4.3 discusses The subject paragraph will be revised to include the replacement replacement option as follows.
options for dispositioning a flaw, which include include analyses of flaws discovered Fracture mechanics analyses discovered during in-service in-service inspection inspection may analysis or repair. Why did the applicant not be TLAA for those analyses based on time-limited assumptions defined by the the include replacement as an option.?
include option.? operating term. When aa flaw is detected current operating in-service inspections, detected during in-service inspections, the the component may be replaced, component replaced, repaired, or evaluated for continuedcontinued service in accordance with ASME Section XI.
accordance XI. These evaluations evaluations may show that the the component is acceptable acceptable to the end of the license term based projected in-based on projected growth. Flaw service flaw growth. Flaw growth predicted based on the design thermal growth is typically predicted and mechanical mechanical loading cycles.
Clarification to be incorporated Clarification incorporated into the LRA.
119 LRD04:
LRD04: What are the alertalert values (i.e. values values IPEC Procedure 2-PT-2Y15 IPEe Procedure 2-PT-2Y15 calculates calculates "alert levels" by adding adding twice twice the numbernumber of initiation of corrective actions) which trigger the initiation actions) for cycles that occurred occurred inin the last fuel cycle to the total number of cycles cycles to date.
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Thursday, March 20, 2008 Page 110f16 11 of 16
Item Request Response the Fatigue Monitoring Program. Corrective action is initiated initiated if if this alert level exceeds exceeds the number of analyzed analyzed transients.
In In other other words, if if the number of cycles is projected projected to remain at or below the the analyzed level for 2 additional analyzed additional fuel cycles, no corrective corrective action is required.required.
120 Related Related to Question Question 4.3-1, 4.3-1, Item Item #3 This question was a clarification Question 3. The response has been clarification to Question incorporated into the response incorporated response to Question 3. This question should be closed and and (a) For reactor trips, IP2 based the cycle cycle the issue resolved via Question Question 3.
projections on the recent 6 years of operation projections while the cycle projections for all other events are based on the full operating operating term. Why the the difference?
difference?
(b)
(b) The LRA should be amended to include include the the revised revised projections projections provided in the first response response to this question.
c) Explain Explain why itit is acceptable acceptable to use a linear linear extrapolation extrapolation to project project transients.
121 Relative to existing question TLAA 4.3-5, the the The response to this question has been incorporated incorporated into into the response to database database second second half half of the question is 7(c) and and itit should be be question #7, question #7, TLAA 4.3-5.
7(b). Answer question in more more detail, with references. In references. In particular, address address whether or not not This question should be closed to question question #7. #7.
steady steady state oscillations are significant to the the existing existing fatigue analyses analyses (b) The (b) The second second half half of of the the question question should should be (b), (b),
not (c)
Answer Answer the second part part more clearly, with with references.
Explain whether or not steady state oscillations oscillations important in are important in the fatigue analysis.
134 134 Item 14 on LRA Table 4.3-2 gives the number number of Table 4.3-2 4.3-2 is for IP3, and IP3 FSAR Table 4.1-8 states that there are 10 cycles in events events (5) for the Operating Basis Earthquakes Earthquakes every every earthquake earthquake event. The footnote from FSAR Table 4.1-8 will be added added to LRA rather than the number of cycles. Please Please provide Table Table 4.3-2 as follows:
the number of cycles that were were analyzed.
analyzed. 5. The upset conditions include the effect of the specified conditions include earthquake for which the specified earthquake the system must remain operationaloperational or must regain its operational operational status. The faulted faulted conditions include include the earthquake earthquake for which safe safe shutdown shutdown is required. For fatigue For fatigue studies, Class II components components were were analyzed analyzed for five OBE's and one DBEin DBE in addition to other fatigue producing producing events in in the above above listed listed four loading conditions. Each earthquake is considered considered to produce produce ten peak stress magnitudes.
Clarification to be incorporated incorporated into the LRA.
135 Note 1 to LRA be revised.
to LRA Tables 4.3-13 revised. Please Please verify 4.3-13 and 4.3-14 verify this this statement 4.3-14 needs to The note note will be clarified as shown below. Also the footnote in in the table is moved be statement is correct is correct from the from the pressurizer pressurizer surgesurge line nozzle to the surge line piping piping to better better show that 0.6 0.6 and make itit clearer which nozzles nozzles are being is the bounding bounding CUF CUF for the pressurizer pressurizer surge lines.
discussed.
discussed.
- 1. The maximum maximum usage usage factor on Indian Indian Point surge surge lines occurred at the pipe side side of the pressurizer pressurizer nozzle safe end with a value of 0.60. (Section 5.4 of WCAP-12937, 12937, "Structural Evaluation Evaluation of Indian Point Units Units 2 and 3 Pressurizer Pressurizer Surge Lines, Considering the Effects of Thermal Stratification,"
Considering Stratification," May, 1991). 1991).
Clarification Clarification to be incorporated incorporated into the LRA.
136 136 The NRC would would like to review review the bases behind behind This question is a followup to question 101. 101. This question should should be closed and the the Note 1 to LRA Table 4.3-3 concerning concerning the re- answer answer tracked in 101. 101.
analysis of the RPV studs as follows:
a) The FSAR a) FSAR change change is in progress.
b) The new CUF CUF is based on the old CUF. CUF.
c) The CUFs CUEs are based on the design cycles 137 137 Table 4.3-3 says the CUF Table CUF for the IP2 core support reason for the difference in CUF The primary reason CUF is the difference difference in the analytical pad is 0.904 while Table 4.3-4 says the CUF CUF for methods methods (i.e. plant specific vs. multi plant bounding analysis). For IP2, the core core the IP3 the IP3 corecore support support pad pad is 0.052. 0.052. Please Please explain explain support support pad was evaluated in a calculation which also included Diablo Diablo Canyon Canyon and difference between the two units.
this large difference Salem. This evaluation Salem. evaluation used the limiting geometry geometry for the core support pad. The The
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Item Request Response Diablo Diablo Canyon Canyon geometry geometry (two supports joined by a ligament) was significantly significantly more more limiting than the IP2 geometry (individual supports suppqrts welded directly to the vessel vessel wall). The resulting CUF was based based on the Diablo Canyon geometry geometry and is thus thus higher than a realistic CUF for IP2. For IP3, the evaluation was performed performed solely for the specific IP3 geometry geometry and therefore itit did not include include the added added conservatism introduced as aa result of evaluating introduced evaluating a more limiting geometric geometric configuration.
138 The extrapolation of Reactor Reactor Trips with excessiveexcessive Based on the response to Item 120, 120, the LRA will be amended amended to show 160 160 events events cooldown in Table 4.3-1 projects only 159 events events instead instead of 159. 159. This amendment amendment will be included included in in the response to Question Question #3.
after 60 years even even though there are 148 events are 148 to date. PleasePlease explain this projection projection in more The reactor trips with excessive excessive cooldown were projected based on data from 1999 1999 detail. to 2005. There There were were only 2 transients transients recorded during this time. There There were were 2,032 2,032 days in in this time span, but 336 days were removed because that time was spent in a steam generator generator replacement replacement outage. The resulting rate was still only 0.00118 0.00118 cycles per day, which projects projects to 160 cycles in in 60 years years of operation. (160.21) (160.21)
The fatigue monitoring monitoring program will continue continue to monitor the number number of reactor trips with excessive excessive cooldown cooldown and and require require action if if the analyzed number number of cycles is approached.
approached.
139 Table Table 4.3-2, item 11, 11, is for an infinite number number of The exact values of temperature temperature and pressure pressure involved involved in in these steady steady state cycles cycles steady state cycles. Please Please identify the delta- varies among references. The temperature temperature change change is stated as +/-3°F and as a 6°F 6°F Temperature Temperature associated associated with these cycles. change. The stated stated pressure pressure change change varies varies from 25 psig to 100 psig.
The conservatively bounding variation is a 6°F change change with a 100 100 psi pressure change.
This question will be closed to Question Question #9.
140 LRA Section 4.3.1.2 4.3.1.2 states that the reactor vessel Subsection NG to ASME III IIIdid not exist when the IP2/IP3 IP2/1P3 internals were designed.
internals were designed to meet the intent of The statement statement in in question was taken taken directly from WCAP-16156, "Indian Point Point Subsection NG of ASME Section Ill.
Subsection Please III. Please Nuclear Generating Nuclear Generating Unit Unit No. No.2, 2, Stretch Power Uprate, NSSS Engineering Engineering Report",
explain explain what this means. means, dated dated FebruaryFebruary 2004. This statement statement means means that when the internals internals were reviewed were reviewed for the power uprate, they were found to be designed and built in in essentially the the same way way that internals would be built today, ifif built in in accordance accordance with Section NG.
It says itit meets the "intent" It "intent" of Section NG because because while the construction construction is similar, documentation of material, the documentation material, inspections, and and analyses were were not to Section NG NG requirements.
141 These These comments are relative relative to the pressurizer a) The basis document document for LRA Section 4.3.1.3 4.3.1.3 is WNET-108. This was reference reference analysis discussed in LRA Section 4.3.1.3 on 9.5.67 to LRD04, the fatigue report basis document. A copy of the reference reference was was pages 4.3-12 4.3-12 and 4.3*13 4.3-13 provided to the NRC for onsite review.
a) What is the basis document document for the pressurizer B) There B) There is an extra "the" "the" in in the first sentence sentence of the last paragraph. paragraph. The sentence sentence analysis discussed in LRA Section 4.3.1.3 on includes the phrase "of the all transients". The word "the" includes "the" betweenbetween "of' "of" and "all" will page 4.3-12? Please provide provide a copy of this be removed. That sentence sentence will be revised to read as follows:
calculation. Section 4.3.1 projected projected the numbers numbers of cycles cycles of all transients used in in the the pressurizer fatigue determination, pressurizer determination, except except steady state oscillations, would would remain b) There appears appears to be an extra "the" "the" in the last below the numbers analyzed by the stress report through the period of extended paragraph on page 4.3-12.
paragraph operation.
operation.
c) Verify the second second sentencesentence on page page 4.3-13 4.3-13 (the C) The second sentence on page 4.3-13 is correct as written. written. However, this this surge and and spray nozzles nozzles were analyzed) sentence sentence can be misleading misleading and Entergy Entergy will reword reword itit as follows.
d) d) Amend the LRA as needed needed for items a) throughthrough While the original original stress report did not analyze the pressurizer pressurizer shell, it did analyze c) c) the surge surge nozzle and spray nozzle. The resulting resulting CUFs are not the CUFs of record as both the surge and spray nozzles nozzles were subsequently subsequently re-evaluated re-evaluated for the stretch power uprates.
The usage factors of record are given in in Tables 4.3-7 and 4.3-8.
Clarification to be incorporated incorporated into the LRA. (Applicable to parts b) and c).)
142 The following questions refer to LRA paragraph a) While the FSAR says the regenerative regenerative heat exchanger exchanger is qualified to 2000 cycles, 4.3.1.7 4.3.1.7 on page 4.3-17. Section 2.4 of WCAP-12191, WCAP-12191, Addendum Addendum 1 to Revision 3, goes goes into greater detail paragraph 4.3.1.7 says the regenerative a) LRA paragraph regenerative and showsshows that the heat exchanger is analyzed analyzed to the following cycles.
letdown heat exchangersexchangers are qualified qualified to 2000 cycles. Explain Explain what these 2000 cycles are. 1. 2000 step change in shell side fluid from 100 100 deg F to 560 deg F (stops and and b) Clarify the statementstatement that the CUF of 0.13 does starts of charging and and letdown) not require aa plant specific analysis.
c) Clarify Clarify the statement that charging charging nozzle is 2. 24000 24000 step change change in in shell side fluid from 400 deg F to 560 deg F (changes in in limiting. Does this refer to the nozzle in the heat charging and letdown) letdown) l<D:Z~'~~ \,; ',"~:1~~~~,*:X~':;.,\d~:"'" "~:.",' '::<<.'~~v.~~<;;~~i ' *""~,m:::m%m:>~2:;.~'r';:'.:'tX{tlt~,ffi<<<::<<:::::~w.~.{ '.~~::l'kl':;.;t.:\::,,,;,; ~'::"::~::::Y.X~.k.::::m::::.<~,t.x~:'.J,',,1:,;,:~:r'"\\':::~ ."::-'%:>~hl&~:...~f~tlmt:l:J.':;~S';1~
Thursday, March Page 13 13 0(16of 16 Thursday, March 20, 2008 Page
Item Request Response
Response
exchanger exchanger or the nozzle in in the RCS piping piping 200 changes in 3.200
- 3. in shell side fluid from 100 100 deg F to 560 deg F over 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> (plant heatups and cooldowns)
- 4. 200 pressurizations pressurizations of shell and tubes to design pressure pressure (plant heatups and cooldowns) cooldowns)
WCAP-12191 WCAP-12191 states "Furthermore, based on the evaluation evaluation of all four transient transient categories, the design usage is essentially categories, essentially due to Transient Category 1." It does not 1." It not give individual usage factors for each category of transient, only this summary statement.
statement.
The description description in Section Section 4.3.1.7 will be clarified as shown below to specify that that these cycles represent represent step changes from 100 deg F to 560 deg FF due to stops and starts of charging and letdown.
letdown.
b) The paragraph paragraph for the IP3 heat exchangers exchangers will be modified as shown below. The The change removes reference to a TLAA for IP3 IP3 since there is no IP3 analysis.
analysis.
In addition, addition, the paragraph paragraph of the sectionsection will be revised to say the TLAA for the IPEC regenerative heat regenerative heat exchangers exchangers fatigue remains valid for the period period of extended operation in in accordance accordance with 11OCFR54.21(c)(1)(i).
OCFR54.21 (c)(1 )(i). See the revised section section below.
c) WCAP-12191 WCAP-12191 Section Section 2.4, Conclusion 3, says the charging nozzle nozzle is limiting limiting compared to the auxiliary auxiliary heat heat exchangers. WCAP-12191, Section exchangers. From WCAP-12191, Section 2.3, itit is clear that the nozzles nozzles being being discussed discussed are the RCS piping nozzles (the (the normal nozzle in nozzle the cold in the cold leg leg and and the the alternate nozzle in alternate nozzle in the the hot leg).
hot leg).
LRA Section 4.3.1.7 will be clarified to specify that the nozzle is the nozzle at the LRA Section 4.3.1.7 will be clarified to specify that the nozzle is the nozzle at the RCS cold leg piping.
The LRA LRA will be clarified as shown below to reflect answers a), b), and c).
4.3.1.7 Class-1 Class-1 Heat Exchangers Exchangers manufacturing equipment The original manufacturing eqUipment specification specification for the regenerative letdown exchangers and the excess heat exchangers letdown heat 6xchangers excess letdown exchangers says that these heat exchangers are to be qualified for various exchangers various transients. The E-specE-spec suggests that the the manufacturer should verify in writing that all conditions of Paragraph manufacturer Paragraph N-415.1 N-415. 1 ofof Section IIIIIIare satisfied for the transient conditions; otherwise, a fatigue analysis is required. The IPEC UFSARs say the regenerative required. regenerative letdown heat exchangers exchangers and the letdown heat exchangers excess letdown exchangers are qualified to 2000 temperature temperature cycles from 100 100 degrees F to 560 degrees F associated with charging and letdown letdown starts and stops.
Westinghouse determined that the regenerative heat exchanger Westinghouse controlling exchanger was the controlling heat exchanger with regards to fatigue, and therefore only that heat exchanger heat exchanger exchanger was was analyzed. The associated analyzed. associated report concludes concludes that by 10/31/1999, 10/31/1999, Unit 2 had accumulated accumulated 466 of the analyzed 2000 cycles (23.3%) on the regenerative regenerative heat exchanger. Further, since the analyzed analyzed CUF was only 0.235, the CUF as of of 10/31/1999 was equal to 0.235 x 23.3% =
10/31/1999 = 0.05. For license renewal, the thermal cycles seen by the regenerative regenerative heat exchanger can be projected through through the period period of extended extended operation operation to show that only 1072 cycles (54%) (54%) are expected in 60 years, corresponding =
corresponding to a projected CUF of 0.235 x 54% = 0.13. The IP3 auxiliary heat heat exchangers exchangers have no plant-specific plant-specific evaluation, and therefore, there is no TLAA.
However, the similarity in design and operation between the two units indicates the the results would be similar, if if an analysis had been performed.
performed. As the projected IP2 IP2 CUF is 0.13, it follows that the IP3 IP3 CUF would also be well below 1.0. Thus Thus thethe TLAA for the heat exchanger exchanger fatigue remains remains valid for the period period of extended operation operation in in accordance with 10CFR54.21 (c)(1)(i). (c)(1 )(i).
IPEC design documents documents indicate that the auxiliary heat exchangers exchangers are are not the the limiting components components in in the CVCS system. The charging nozzles at the RCS cold leg limiting. Therefore, monitoring of the charging piping are more limiting. charging nozzles will assure acceptability of the auxiliary auxiliary heat exchangers.
Because the charging nozzle 8ecause nozzle isis one of the the locations locations identified identified by by NUREG/CR-6260 NUREG/CR-6260 as requiring environmental adjustments to the fatigue analysis, analysis, this nozzle will be be evaluated with the other NUREG/CR-6260 NUREG/CR-6260 locationslocations as discussed in Section 4.3.3. 4.3.3.
Clarification Clarification to be incorporated incorporated into the LRA.
143 Section 4.3.1.8 4.3.1.8 refers to ANSI 831.1 B31.1 and to USAS The B31.1 831.1 power piping code originatedoriginated in in 1955 1955 as ASA 831.1.B31.1. InIn 1967 itit became became B31.1; please be consistent 831.1; consistent in in the naming naming of the USAS 831.1.
B31.1. It later became ANSI 831.1 B31.1 and is currently currently ASME B31.1. The code ASME 831.1. code code. of record for most of IP2 and some of IP3 1P3 is ASA 831.1 B31.1 (1955) while the code of
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Thursday, March Thursday, March 20, 2008 2008 Page 14 ot of 16 16
Item Request Response
Response
record for some of IP2 and most most of IP3 is USAS 831.1 B31.1 (1967). Throughout Throughout thethe evolution of this code, the fatigue analysis analysis requirements requirements have remained have remained fundamentally the same, and fundamentally different different from ASME Section III IIIfatigue fatigue requirements. As the intention here analysis requirements.
analysis here is only to separate separate B31.1 831.1 fatigue fatigue analyses from Section analyses Section III analyses, the distinction between between ASA - USAS - ANSI -
ASME is not critical to the discussion. Consequently, the LRA ASME LRA will be amended as as follows.
follows.
The discussion above will be added added to LRA LRA Section 4.3.1.8.
The title of the first subsection of LRA LRA Section 4.2.1.8 will be changed to "831.1 "B31.1 Piping."
addition, all references In addition, references to B31.1 831.1 in remainder of the LRA in the remainder LRA will changed to to "B31.1" with no prefix.
"831.1" Clarification to be incorporated Clarification incorporated into the LRA.
(aTh tilVfScin432wl ecaiiessonblwt ed"o-ls 144 These questions questions refer refer to LRALRA Section Section 4.3-2 on on (a) The title of Section Section 4.3-2 will be clarified as shown below to read "Non-Class 1 I page 4.3-20: Piping and Component Fatigue: Fatigue.
a) Shouldn't the title of this section be Non-Class a} Non-Class 1 Piping and Component Fatigue rather than just (b) The contradictory contradictory statements statements will be revised as shown below.
Non-Class Non-Class 1 Fatigue?
b) contradictory statements on whether b} There are contradictory assumption in Section 4.3.2 that the RHR heat exchanger had a TLAA was aa (c) The assumption or not there is a fatigue analysis for the RHR heat conservative conservative assumption assumption based solely on statements statements in in the original original equipment equipment exchanger. Please Please resolve this apparent apparent specification specification and and the FSARs FSARs that the component component was designed based based on 200 discrepancy. cycles. Given that no fatigue analysis for the residual heat exchangers has been c) If c} If no analysis exists for the RHR heat heat found, there is no basis for the assumption that there is aa TLAA for this component.
exchanger, that analysis analysis cannot remain valid. The 200 200 cycles associated with the component were were based heatups and based on the 200 heatups Consider saying there is no TLAA, which may Consider cooldowns for the reactor coolant system, and these transients are cooldowns are monitored by the the mean deleting the paragraph from the LRA.
m~an deleting LRA. Fatigue Fatigue MonitoringMonitoring Program and are projected projected to stay well below 200 through the the period period of extended extended operation (LRA Tables 4.3-1 4.3-1 and 4.3-2). Section 4.3.2 of the the LRA LRA will be revised as follows.
REVISED LRA SECTION 4.3.2:
REVISED 4.3.2 Non-Class 1 Piping and Component Component Fatigue Fatigue Piping and in-line components components The design design of ASME III IIICode Class 2 and 3 piping systems incorporates Code incorporates the Code stress reduction factor factor for determining acceptability acceptability of piping design with respect to to thermal thermal stresses. In In general, general, 7000 thermal cycles are assumed, allowing a stress stress reduction factor of 1.0 1.0 in in the stress analyses. IPEC evaluated evaluated the validity of this this assumption for 60 years of plant assumption operation. The results of this evaluation plant operation. evaluation indicate indicate that the 7000 thermal cycle assumption assumption is valid and bounding bounding for 60 years of operation.
operation. Therefore, Therefore, the pipe stress calculations calculations are valid for the period period of of extended extended operation in in accordance accordance with 10 CFR 54.21 (c)(1)(i). (c}(1 }(i).
Non-piping Components Components Review of potential TLAAs for IPEC non-Class 1 components identified no TLAA.
Clarification to be incorporated Clarification incorporated into the LRA.
145 commitment on the top of page There is a commitment page 4.3-22 4.3-22 The pressurizer pressurizer re-analysis re-analysis is included included in in Commitment 33.
pressurizer fatigue analysis. 8e to redo the pressurizer Be sure there is an official commitment commitment to do this.
146 The third paragraph paragraph on page page 4.3-22 states: states; "At This paragraph will be modified as follows:
least 22 years prior prior to entering the period of extended operation, extended operation, for the locations locations identified in At least 2 years prior to entering the period period of extended extended operation, operation, for the locations locations NUREG/CR-6260 for Westinghouse PWRs of the NUREG/CR-6260 the identified in LRA Table 4.3-13 (IP2) and identified and LRA Table 4.3-14 (IP3), IPEC will IPEC vintage, IPEC will implement implement one or more of implement implement one one or more of the following: .
the following:" Shouldn't this reference reference LRA Table Table 4.3-13 and LRA Table 4.3-14 4.3-14 instead of NUREG- NUREG- Closed to question #18. #18.
6260?
6260?
147 147 The third paragraph on page 4.3-21 misquotes misquotes The LRA paragraph will be revised to read as follows. "NUREG/CR-6260 "NUREG/CR-6260 identified NUREG-6260, please revise this paragraph.
NUREG-6260, paragraph. locations locations of interest interest for consideration consideration of environmental environmental effects in several plant There are are no fatigue curves with environmental designs. Section 5.5 of NUREG/CR-6260
. designs. Section 5.5 of NUREG/CR-6260 identified the following identified the following component component effects.
effects. locations to be evaluated for the environmental effects on fatigue for IPEC vintage vintage Westinghouse plants. These locations Westinghouse locations and the subsequent subsequent calculations are directly directly relevant to IPEC."
Clarification to be incorporated Clarification incorporated into the LRA.
',~" .L,~~~n::r:.:~::~>~~~r<.;,." . _~"'. '~~~1:w~~?:.;~,1 ~'U'",*:;'"*::::"Wh;~<',!d:w-::mmlmlm::=~~, '~~-::'7-:::::7<,~~ '.;~~m'fS.:%C:~"~' C:~~*~Lmr~'Wl::*",)Z;;:::;;lml':l:~,,'>~r;,l%&~~Y:'..i.';~:\':: *:":"~m:.r~.;'~'~~~~%l~,*~;i:r{'*: '\"m Thursday, March Thursday, March 20, 20,2008 2008 Pagi6"15 of16 Page a -
Item Request Response 162 TLAA The crack crack growth analysis for this flaw shows that after after 40 years itit could from could grow from Inservice In service Inspection Inspection - Fracture Fracture Mechanics Mechanics 0.33 inches inches to 0.3640 inches, which is still well below the maximum maximum allowable allowable 1.00 1.00 Analyses Analyses inches. This analysis, which is based upon the design cycles occurring occurring during those those Section Section 5.1 (SGN 23R-2) of the basis document document 40 years, actually covers the 40 years from 2006 2006 to 2046. Thus, even though this is (IP-RPT-06-LRD04 (IP-RPT-06-LRD04 Rev. 0) describes the fatigue fatigue a 40 year calculation calculation based on the design operating operating cycles, itit extends through through the the crack growth evaluation was performed performed and statesstatees period of extended extended operation and thus is not a TLAA. TLAA. Section 5.1 of LRD04 will be be that "this TLAA will remain valid for the period of revised to reflect this. LRD03 and the license renewal application remain correct as as extended extended in in accordance accordance with 54.2(c)(1 54.2(c)(1)(i)".
)(i)". But, written.
the attachment attachment 1 (Listing of potential potential TLAA and Resolution) of the other basis basis document (IP-RPT document (IP-RPT-06-LRD03 06-LRD03 Rev. 0) describes describes the "Inservice "Inservice Inspection - Fracture Fracture Mechanics Mechanics Analyses" is "No "Notot TLAA" and this TLAA is not incorporated into the the LRA. Please explain discrepancy between explain discrepancy between abovabovee two basis documents documents including LRA.
163 163 TLAA TLAA The final assessment was provided to the NRC audit team for onsite review. The The Inservice Inspection - Fracture Fracture Mechanics Mechanics final document document is Entergy Entergy calculation IP-CALC-06-00181 (which includes calculation IP-CALC-06-00181 includes Analyses Analyses Westinghouse Westinghouse calculation calculation note CN-PAFM-06-61)
CN-PAFM-06-61) dated dated August 2006.
The letter in reference document (9.5.74, COR-in the reference CC )R-06-00178, Assessment Assessment of IP2 steam generator feedwater feedwater nozzle toshell nozzle to shell weld indication) indicated indicated that this assessment preliminary assessment was preliminary and and will be verified verified and issued as aa final evaluation evaluation soon. Please provide the final assessment assessment results for onsite review.
164 The enhancement to the Fatigue The enhancement Fatigue Monitoring Monitoring Yes, the LRA should include feedwater cycling. cycling. Entergy will revise two places places in the Program on LRA page B-45 B-45 discusses discusses steady application. Page B-45 and page A-22 to clarify that feedwater application. feedwater cycling cycling is included in in state state cycles while while the enhancement enhancement in the the the enhancement.
document (LRD02)
Program basis document (LRD02) pagepage 43 43 discusses discusses both steady steady state state cycles and feedwater feedwate r Note that commitment #6 #6 to make this enhancement enhancement already addresses addresses feedwater cycles. Shouldn't Shouldn't the LRA include feedwater cycling.
cycling.
cycles?
cycles?
Clarification Clarification to be incorporated incorporated into the LRA.
l.::~,-:';~i'r"~~"'~~3~'~.:'::>~"*':::::L~~<:'r.rt<:<~;r."~;::'T'-:-."%..,~"'ill""f%,~"1,~~s:t-'r.l'$.:,r;m.t~'~~~I,~~<:>'U'Mrrm"'"""rnt.m~~~r<,'-\~~,~".1::,~l'!,;~~~~l..:l:.-£':<<
Thursday, March Thursday, March 20, 20, 2008 Page 16 of 16 Page
ATTACHMENT 5 TO NL-08-057 ATTACHMENT NL-08-057 AMP Audit Database Report Report ENTERGY NUCLEAR ENTERGY OPERATIONS, INC.
NUCLEAR OPERATIONS, INDIAN NUCLEAR GENERATING INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 &
&3 DOCKET NOS. 50-247 DOCKET 50-247 AND 50-286 50-286
NRC AMP Audit - All All ItemsItems Item Request Request Response 1 Section Section 3.6-1 3.6-1 The single line schematics (FSAR Figures 8.2-1 8.2-1 and 8.2-2) were providedprovided for review.
Describe SBO restoration restoration paths RAI for IP2/IP3.
IP2/1P3. As stated inin the IPEC LRA, Section 2.5, Page 2.5-2, "The offsite power sources sources Included appropriate Included appropriate drawings for discussion. required to support support SBO recovery actions are are the offsite sources that supply the the station auxiliary transformers. Specifically, the offsite power recovery path includes the station auxiliary auxiliary transformers, transformers, the 138KV138KV switchyard switchyard circuit breakers breakers supplying the station auxiliary auxiliary transformers, breaker-to-transformer and transformer-transformers, the circuit breaker-to-transformer to-onsite electrical distribution interconnections, and the associated control circuits distribution interconnections, circuits and structures."
Based on IP2 UFSAR Section 8.1.2.1, 8.1.2.1, "10 CFR 50 Appendix A General Design Design Criterion 17 - Electric Systems," IP2 is supplied with normal, Electric Power Systems," normal, standby, and emergency power sources. Offsite (standby) power required required during during plant startup, shutdown, and after a turbine trip is supplied from the Buchanan Buchanan Substation Substation by the the Con Edison Edison 138 kV system feeders and the 13.8 kV system feeders. The 138 kV feeder is the preferred preferred standby standby power source and is connected to the 6.9 kV buses through the station auxiliary auxiliary transformer. The 13.8 kV feeder is the alternate alternate standby power and is connected connected to the 6.9 kV buses through through the GT autotransformer. The Buchanan Buchanan 13.8 kV system system is available available for immediate immediate manual connection to the auxiliary connection auxiliary buses. The 480 volt engineered safety feature feature buses are are connected connected to the 6.9 kV buses through through station station service transformers.
transformers. LRA Figure Figure 2.5-2 shows the 6.9kV source for Busses 5 and and 6 as the 138kV/6.9kV 138kV/6.9kV station auxiliary auxiliary transformer, which is shown connected to two separate 138kV 138kV transmission conductors conductors through through Breaker F2 and through through Breaker BT 4-5. Figure 2.5-2 will be be revised revised to show the 138 138 kV feeder connection via the station auxiliary transformer transformer and the 13.8 13.8 kV feeder connection via the GT autotransformer.
autotransformer. The GT GT autotransformer is connected to the alternate autotransformer alternate feed from the Buchanan 13.8 13.8 kV substation via breaker F2-3. Because breaker BT 4-5 is a connection Because breaker connection to IP3 and not a boundary or interface between the plant and transmission interface point between transmission system, Figure 2.5-2 will be revised to show 13.8 kV Breaker Breaker F2-3F2-3 instead of BT 4-5. Breaker Breaker F2-3 is interface between the interface between the plant and the interconnected interconnected grid at the Buchanan substation substation 13.8 kV bus. Figure Figure 2.5-2 will be revised to show motor operated disconnect F3A instead of breaker F2, because breaker F2 is an integral disconnect integral component in the Buchanan Buchanan substation. F3A is the interface between between the plant and the the interconnected interconnected grid at the Buchanan Buchanan substation substation as shown shown on interface agreement interface agreement drawings drawings with Con Edison.
Based on IP3 UFSAR UFSAR Section 8.2.1, "Network Interconnection",
Section 8.2.1, Interconnection", and 8.2.3, "Emergency "Emergency Power - Sources Description," IP3 is supplied with normal, standby, and and emergency emergency power power sources. Offsite Offsite (standby) powerpower required required during during plant startup, shutdown shutdown and after a turbine trip is supplied from the Buchanan Substation by the the Con Edison 138 kV system feeders and the 13.8 13.8 kV system feeders. The 138 kV kV feeder feeder is the preferred standby power source and is connected connected to the 6.9 kV buses buses through through the station auxiliary transformer. The 13.8 kV feeder is the alternate alternate standby power and is connected to the 6.9 kV buses through the GT GT autotransformer. The Buchanan 13.8 13.8 kV system is available available for immediate manual auxiliary buses. The 480 volt engineered connection to the auxiliary engineered safety feature buses are are connected to the 6.9 kV buses buses through station serviceservice transformers. LRA Figure 2.5-3 shows the 6.9kV 6.9kV source source for Busses 5 and 6 as the 138kV/6.9kV 138kV/6.9kV station station auxiliary transformer, which is shownshown connected to two separate separate 138kV 138kV transmission transmission conductors through through Breaker Breaker BT2-6 and through Breaker Breaker BT5-6. Figure 2.5-3 will be be revised to show the 138 138 kV feeder connection connection via the stationstation auxiliary transformer, and the and 13.8 kV the 13.8 feeder connection kV feeder connection viavia the the GT GT autotransformer.
autotransformer. The The GT GT autotransformer is connected autotransformer connected to the alternate alternate feed from the BuchananBuchanan 13.8 kV kV substation via breaker F3-1. F3-1. Because Because breaker BT 5-6 is aa connection connection to IP2 and and not a boundary interface point boundary or interface between the plant and transmission point between transmission system, Figure Figure 2.5-3 will be revised to show Breaker F3-1 instead instead of Breaker BT 5-6. Breaker Breaker F3-1 is between the plant and interconnected the interface between interconnected grid at the Buchanan Buchanan substation 13.8 kV bus.
13.8 kV bus. Breaker Breaker BT BT 2-6 2-6 is is the interface between the interface between the plant and the plant and interconnected interconnected grid at the Buchanan substation substation as shown on the interface agreement drawings with interface agreement Con Edison Edison Information Information to be incorporated to be incorporated into into the the LRA.
LRA.
2 Section 3.6-2 The only high voltage direct direct burial insulated insulated cable (>35 kV) kV) is part of the IP2 SBO SBO recovery path.
recovery High voltage direct burial insulated cable (>35 kV) The cable is a portion portion of the 138 kV path from the Station Station Aux Transformer to
!:':mm:mm~m<!!lli<::~mmtffitx~1&~>><:"~~r~~::--;:::::::;::-""~~~== __==""",,,,_,,,,~~~~~J:\r:;:r.~~:,:"':~;::::,::"::~1:':::"~'>":::::::::'~7&m'~.~
Tuesday, March Tuesday, March 18, 2008 Page Page 1 of 48 0(48
Item Request Response
Response
may be exposed exposed to condensation condensation and wetting in in breaker F2 as shown inaccessible inaccessible location, location, such as conduits, cable cable in LRA Figure 2.5-2. This is a lead sheathed solid solid dielectric insulated cable. The dielectric insulated The trenches, cable troughs, troughs, duct duct banks, underground underground lead sheath sheath prevents prevents moisture in submerged cables from contacting the insulation, insulation, vaults or direct installation. When an direct buried installation. so water trees will not not be formed. Therefore, there there is no aging effect effect that requires requires energized energized high voltage cable is exposed exposed to wet management.
conditions for which it is not designed, water conditions water tree tree or aa decrease in in dielectric strength strength of thethe The specification specification for the 138 kV 750 MCM MCM solid dielectric dielectric cable states the cableis cable is conductor conductor insulation insulation can occur. This can supplied with a potentially lead to electrical electrical failure. Provide a moisture barrier. Radial water sealing sealing is achieved by a corrosion resistant lead lead manufacturer certification manufacturer certification that 138 kV direct direct burial sheath. Longitudinal Longitudinal water sealing is achieved by using a water water swelling swelling material insulated transmission qualified for transmission cable is qualified for applied under the lead sheath. The cable passed longitudinal water penetration cable passed continuous submerge condition or provide an tests as specified in the applicable AEIC specification. The cable is installed in a specified in AMP AMP to ensure that water water tree aging effect will not pipe-type system, system, which originally originally contained an oil-filled cable system. The anoil-filledcable The degrade the cable intended function during the the replacement cable was installed replacement installed in in the same route. '
period of extended operation.
operation.
This cable was designed with a thick layer of lead lead over the cable insulation insulation with an overall jacket jacket over the lead and insulation.
insulation. The construction construction of this cable differs differs from the typical medium medium voltage cable design of insulation insulation with an overall jacket.
This type of cable is used in in transmission substation networks networks to maximize the life of the cable, which is mainly associated with the good characteristics in in moisture moisture environments, and the dielectric constant environments, requirements of a 138 kV feeder constant requirements feeder cable.
The AEIC CS7 specification specification is for lead sheath power (69 kV to 138 138 kV) cables designed designed to be installed in in wet environments environments for extended periods. The insulation system for this cable is a cross-linked cross-linked polyethylene polyethylene (XLPE). The lead sheath combined combined with the overall jacket jacket provides a virtually virtually impenetrable impenetrable barrier against hostile environments --liquids, liquids, fire hydrocarbons, hydrocarbons, acids, c:austic, caustic, sev.:age, sewage, etc.
The license renewal electrical handbook states lead electrical handbook lead sheath cables prevent the the effects effects of moisture on the cable insulation.... A lead sheathed cable cable insulation comparable to cable is comparable aa submarine submarine cable.
A review of the IP2 and IP3 operating operating experience experience did not identify identify any failures of the the 138kV solid dielectric 138kV underground transmission dielectric underground transmission cables.
cables. Interviews Interviews with with knowledgeable plant staff did not identify any knowledgeable any additional IP2 or IP3 operating experience with these cables. Additional searches of industry operating experience operating experience did not identify any failures for this type of transmission cable.
Based on the above, the aging effects effects caused caused by moisture moisture and voltage voltage stress is not applicable to this cable. This 138 kV underground underground cable, which is part of the IP2 IP2 offsite power power path, does not have any aging effects that require require management; therefore, this cable is not included in the scope Inaccessible scope of the Non-EQ Inaccessible Medium-Voltage Cable program.
Medium-Voltage 20 AMP B.1.3-1 (Boraflex (Boraflex Monitoring)
Monitoring) The boraflex boraflex manufacturer manufacturer was was Brand Industrial Industrial Services Services Corporation Corporation who no longer supports the product. The recommendations recommendations for managementmanagement of boraflex at IP2 are are According According to GALL, the applicant's applicant's Boraflex Boraflex derived from industry experience and responses to NRC GL 96-04, Boraflex industry experience Monitoring Program, according to manufacture's Monitoring manufacture's Degradation in Degradation in Spent Fuel Pool Storage Racks.
recommendations, should assure that no no unexpected degradation unexpected degradation occurs occurs that would would Boraflex Boraflex is not used for criticality criticality control of the IP3 IP3 spent fuel pool.
compromise the criticality analysis.
manufacturer's recommendations What are the manufaciurer's recommendations for for IP-2 IP-3?
IP-2 AND IP-3?
21 AMP B.1.3-2 (Boraflex (Boraflex Monitoring)
Monitoring) Areal density testing provides a direct measurement of in-rack performance performance of boraflex boraflex panels through measurement measurement of gaps, erosion, and general thinning.
What is the justification justification for IPEC selection selection of areal Blackness testing provides only an indication of neutron absorber presence presence and density measurement over GALL specification specification for for does not quantitatively quantitatively measure measure the Boron-10 Boron-10 areal density of neutron absorber in measuring measuring gap formation by blackness testing. each each rack. Therefore, areal density density along with the monitoring monitoring of silica levels in the the spent fuel pool provides adequate detection provides adequate detection of boraflex degradation.
boraflex degradation.
24 AMP B.1.5-3 (Boric Acid Corrosion)
B.1.5-3 (Boric Corrosion) IPEC responses to the referenced referenced NRC generic generic communications communications are contained contained in in the letters letters referenced referenced below. Copies of the letters available on site for review letters were available review Discuss how the applicant applicant responded to the the or in in ADAMS.
NRC's order and bulletins listed below; explain how how these these responses have have been used used to update update Bulletin 2002-01, 2002-01, "Reactor Pressure Vessel Head Degradation Degradation and Reactor Coolant Coolant the component component list location location and visual inspection Pressure Boundary Boundary Integrity" within the scope of the Boric Corrosion Boric Acid Corrosion This bulletin was issued issued to alert licensees licensees of the significant significant corrosion of the Davis Davis Program. Besse reactor reactor vessel head which resulted from through-wall through-wall CRDM nozzle nozzle leakage.
leakage.
Licensees were required to review their GL 88-05 boric acid inspection programs programs to NRC Bulletin 2002-01 dated March 29 and May May ensure effectiveness effectiveness in in detecting detecting corrosion corrosion at RCS locations where Alloy 600 could Tuesday, March Tuesday, March 18, 2008 Page Page 22 of48 of 48
Item Request Response
Response
16,2002 16,2002 crack and result in accumulation accumulation of wet boron. In response to this bulletin, both IP2 IP2 NRC RAI on Bulletin 2002-01 dated January January 17, and IP3 committed to review their boric acid corrosion prevention programs as as 2003 originally required by GL 88-05. ProceduresProcedures 2PT-R1 2PT-R156, 56, "RCS Boric Acid LeakageLeakage and Corrosion Inspection", 3-PT-R114A, "Reactor Vessel and Closure Head Boric Boric NRC NRC Bulletin 2003-02 2003-02 dated September 19, 2003 dated September Acid Leakage and Corrosion Inspection", 3-PT-R1 14, "RCS Boric Acid Leakage Inspection", and 3-PT-R114, Leakage NRC NRC Order EA 03 009, dated March 3, April 11 11 and Corrosion Corrosion Inspection" were revised to include include inspection for signs of leakageleakage or or 18, 2003 and April 18,2003 boron deposits detected detected during bare metal visual inspections of the reactor vessel NRC Bulletin 2004 - 01, 01, dated May 28, 2004 head head near near the CRDM CRDM nozzles. The procedures procedures also warn that signs of possible possible RCS leakage may include include boron or rust on containment radiation monitor monitor filters, FCU cooling fins, and some parts of containment. Refer Refer to the following letters letters for for bulletin response specifics.
NL-02-050/IPN-02-023, "Submittal of 15 NL-02-050/IPN-02-023, 15 Day Response to NRC Bulletin 2002-01" NL-02-074/IPN-02-039, "Submittal of 60 Day Response to NRC Bulletin 2002-01" NL-02-074/IPN-02-039, 2002-01" NL-02-099/IPN-02-060, "Supplement to 15 Day Response for NRC NL-02-099/IPN-02-060, NRC Bulletin 2002-01" 2002-01" NRC RAIRAI on Bulletin 2002-01 This RAI further outlined outlined the requirements requirements of a comprehensive comprehensive boric acid corrosioncorrosion control program.
Refer to the following letter for response specifics.
NL-03-020, "Response to Request for Additional Information Regarding Regarding the 60-day60-day Response to NRC Bulletin 2002-01" 2002-01" NRC Bulletin 2003-02 2003-02 This bulletin informed facilities facilities that current methods of inspecting inspecting the reactor pressure vessel vessel (RPV)
(RPV) lower lower heads may need need to be supplemented supplemented with bare-metal visual inspections in order to detect detect reactor reactor coolant pressure pressure boundary boundary leakage. The The bulletin also requested requested licensees licensees provide the NRC with information information related to inspections that have been performed inspections performed to verify the integrity of the RPV lower head penetrations. IP2 IP2 and IP3 reported that bare bare metal visual inspection inspection of lower lower head penetrations revealed penetrations revealed no evidence evidence of pressure pressure boundary boundary leakage. Procedures 2-PT-leakage. Procedures R204, "Visual Inspection Inspection of Reactor Vessel Bottom Mounted Mounted Instrumentation Instrumentation Penetrations Penetrations for Leakage" and 3-PT-R204, 3-PT-R204, "Visual Inspection of Reactor Reactor Vessel Bottom Bottom Mounted Instrumentation Penetrations Penetrations for Leakage" were developed to meet were developed meet requirements of this bulletin. Refer to the following letters from the NRC the requirements NRC acknowledging completion of the bulletin requirements.
acknowledging COR-05-02835, "Indian Point Unit 2 - Response to NRC Bulleting COR-05-02835, Bulleting 2003-02, 2003-02, "Leakage From Reactor Vessel Lower Head Penetrations Penetrations and Reactor Reactor Coolant Coolant Pressure Boundary Integrity""
Pressure Boundary Integrity""
COR-05-02892, "Indian Point Unit 3 - Response to NRC Bulleting 2003-02, COR-05-02892, "Leakage From ReactorReactor Vessel Lower Head Penetrations Penetrations and Reactor Coolant Coolant Pressure Boundary Integrity""
Pressure Boundary First Revised Order EA-03-009 EA-03-009 This order extended the region of the CRDM considered susceptible susceptible to PWSCC and and required required both both visual and volumetric examination examination of all nozzles on a prescribed prescribed frequency. IPEC meets the requirements of this order. Refer to the following letter regarding regarding the IPEC response response to EA-03-009.
NL-04-026, "Answer to FebruaryFebruary 20, 2004 Revised NRC Order Regarding Interim Order Regarding Interim Requirements for Reactor Requirements Reactor Pressure Pressure Vessel Heads Vessel Heads Bulletin 2004-01 This bulletin requests that each PWR facility provide provide aa description of their Alloy materials used for pressurizer 82/182/600 materials pressurizer heater heater and steam steam space space penetrations penetrations and inspection plans for future refueling refueling outages. pressurizers outages. Neither IP2 nor IP3 pressurizers contain Alloy 82/182/600 components.
components. Refer to the following regarding the following letter regarding the IPEC response to bulletin 2004-01.2004-01.
NL-04-090, "Response to NRC Bulletin Bulletin 2004-01 Regarding Inspection of Alloy 2004-01 Regarding 82/182/600 Materials Materials Used Used In In Pressurizer Penetrations Penetrations and Steam Space Space Piping Piping Connections" 25 AMP B.1.7-1 (Containment Leak Rate) The Containment Containment Leak Rate includes Type A, Type B, and Type C tests of Rate Program includes primary primary containment pressure-retaining components as described pressure-retaining components described in in 10 CFR Part The applicant applicant indicates indicates that this AMP is consistent 50, Appendix J.
with GALL GALL AMP XI.S4, without exception or enhancement. GALL GALL Vol.2,Vo1.2, Rev. 1, 1, AMP XI.S4, Thus, IP2 and IP3 are crediting crediting 10 CFR Part 50, Appendix containment Appendix J, Type C containment Scope of Program, Program, states "Leakage testing for isolation valve leak rate testing testing during the period period of extended extended operation.
containment isolation containment isolation valves (normally performedperformed under Type under Type C C tests),
tests), ifif not not included included under under this this program, is program, is included included under under LRT programs for LRT programs for systems containing the isolation systems containing the isolation valves." valves."
Is Entergy Entergy crediting 10 10 CFR Part 50, Appendix Appendix J, ru~~",;:r'::"~ffi.""~:Jfu\iJ:<<<:ii!IJWU!M$ ..",,,&LA""~~~'~~~:t'1is..~-.::,:,~,::,::;,...r:~~U'!~lliMil&iMa~;.>;£:,~~..;."""~",,,.:u:t.u:ra>~t:"-"'V'''-~'=~='",,%'I<%:'!mt:;'~'=";~$
Tuesday, Tuesday, March March 18, 2008 Page 3 of 48 Page
Item Itern Request Request Response Item Request Type Ccontainment isolation valve leak rate Type C containment isolation valve leak Type leak rate testing testing during during the license renewal renewal period?period?
26 AMP B.1.8-1 (Containment Inservice) )
(Containment Inservice Entergy Entergy performed an element-by-element element-by-element comparison, available available on-site, of IPEC IPEC AMP B.1.8, Containment Inservice Inspection, to NUREG-1801 NUREG-1801 AMPs XI.S1, XI.S1, ASME ASME The intent intent of the staff inin writing GALL Vol. 2 Section XI, SubsectionSubsection IWE, and XI.S2, ASME Section XI, XI, Subsection Subsection IWL. This This will Chapter XI, XI, was to enable enable an applicant applicant to take take be added to the AMPER AMPER LRD-08 for AMP B.1.8. B.1.8. The comparison identifies and credit for an existing mandated mandated inspection explains exceptions to the ten elements of the NUREG-1801 explains NUREG-1 801 AMPs. IPEC AMP AMP program with minimal minimal effort (Le., (i.e., simply identify B. 1.8, Containment B.1.8, Containment Inservice Inservice Inspection does not require require enhancement enhancement to satisfy satisfy the the and explain exceptions exceptions and enhancements). recommendations of NUREG-1801 recommendations NUREG-1801 AMPs XI.S1 and XI.S2.
Entergy has identified AMP B.1.8 - Containment Entergy Containment Inservice Inspection Inservice Inspection as being plant-specific. The The The Unit 2 and and Unit 3 CLBs CLBs require that IPEC conduct conduct lSI ISI of containment containment in staff reviewed LRA Appendix B.1.8 B. 1.8 and concluded concluded accordance with 10 CFR 50.55(a). This requirement accordance requirement will continue during the period that the 1 10-element O-element evaluation does not identify extended operation.
of extended operation. For license license renewal, renewal, the applicable applicable code edition of ASME ASME any differences from GALL AMPs AMPs XI.S1 and and Section Section XI, subsections subsections IWE IWE and IWL will be determined in accordance accordance with XI.S2. Entergy Entergy is requested to document an requirements of 10 CFR 50.55(a).
element-by-element comparison of AMP B.1.8 element-by-element B.1.8 to to GALL AMPsAMPs XI.S1 and XI.S2, identifying and Results of comparison to be incorporated incorporated into the LRA.
explaining all exceptions and enhancements to to the GALL AMPs.
27 AMP B.1.8-2 (Containment Inservice)
B.1.8-2 (Containment (1) As shown in (1) in LRA LRA Table 3.5.2-1, 3.5.2-1, line item "liner plate insulation insulation jacket", jacket", there is no aging effect requiring management management for liner plate thermal insulation, therefore therefore The IP 2 and 3 containments containments have a somewhat somewhat there there is no AMP. AMP.
unique unique design design feature:
feature: thermal insulation insulation on the the steel liner plate, at the lower elevations elevations of the the (2) IP2 and and IP3 have approximately 20% 20% of the liner inaccessible due to the the cylindrical containment containment wall. In In both both UFSARs, this insulation at the lower lower elevations elevations of the containment.
containment. At the 46' Elevation, aa' insulation insulation is credited with limiting limiting the liner liner caulking sealant, used as a moisture barrier, is installed at the junction junction of the bottom temperature increase to 80 degrees temperature increase degrees F during a edges of the insulation insulation panels and the floor to prevent prevent moisture from reaching reaching the the design basis accident.
accident. Both UFSARs state that the the steel liner. When performing a visual examination of the liner, the insulation insulation is removable, removable, to permit periodic periodic covering portions of the containment containment liner is not removed. removed. The IWE examination examination inspection of inspection the containment of the containment liner liner plate.
plate. inspection of the moisture barrier includes inspection barrier to ensure that it has has not degraded. IP2 and IP3 will remove insulation during the required required IWE examinations if insulation IWE examinations irisulation (1) Identify Identify the AMP and and describe describe the specific specific removal is required to meet meet the requirements requirements in in Table 2500-1. 2500-1.
inspections inspections performed, performed, to ensure that this this insulation insulation will continue continue to perform its intended During the IWE IWE first interval interval for IP2, corrosion was discovered discovered on the liner during during the the function. first period (April 2000) 2000) containment containment inservice inservice inspection. The corrosion existed in in the portion of the liner where itit is abutted abutted by the fill slab that covers the base mat (2) Describe the plant-specific (2) Describe plant-specific operating liner. A number of inspections, inspections, investigations, and evaluations were were performed performed to to experience experience related related to removal of this insulation determine the acceptability of the liner to perform perform its design design function. The The and inspection of the containment liner plate plate inspection found several areas where inspection where the moisturemoisture barrier was missing or not normally covered by the insulation. How does the the properly bonded between between the floor slab and insulation. insulation. The degradation of the The degradation the condition of the normally normally insulated liner plate plate moisture barrier barrier raised aa concern concern relative to the condition condition of the liner. line*. In In order to to surface compare compare to the condition of the normally normally address these concerns, IP2 selected selected nine (9) panels of the liner insulation for uncovered liner plate surface? Has augmented Has augmented removal to facilitate augmented augmented inspection, per Category E-C. During the removal inspection, perCategory inspection, per Category Category E-C, been necessary? necessary? re-installation of these insulation and re-installation insulation panels, the opening covers are re-sealed with with the caulking sealant in order to re-establish the moisture moisture barrier.
When the insulation insulation was removed, minor corrosion corrosion (light rust) was noted. noted. Thickness Thickness readings readings were taken with no significant significant wall loss detected. detected. As a result of three three consecutive inspections of the nine (9) panel areas, the containment liner plate in consecutive these areas was found dry and the corrosion inactive, and the liner plate was was well within the required containment liner thickness. In In conclusion, conclusion, the IP2 VC liner will perform perform its' intended intended function and is within acceptance acceptance limits for continued operation. This augmented operation. augmented exam was completed completed during during the last IP2 Containment Containment ISI Interval.
lSI Interval.
28 AMP B.1.8-3 (Containment Inservice) Neither Neither IP2 nor IP3 have have any augmented inspections required augmented inspections required by IWE IWE or IWL during during the current inspection intervals.
current inspection augmented inspections required Identify all augmented required by IWE or IWL that are being implemented implemented during the the current current inspection inspection intervals.
intervals. For each case, describe describe the initial finding that necessitated necessitated augmented augmented inspection. ,
29 AMP B, B.1.8-4 1.8-4 (Containment Inservice) The liner plates plates of IP2 and IP3 containment containment are provided provided with appropriate appropriate protective protective coatings.
coatings. However, the Level II containment containment protective coatings are not credited for Entergy does not credit GALL AMP XI.S8 for liner plate corrosion prevention/mitigation prevention/mitigation in in the current design bases bases for IP2 and license renewal. Confirm that Level II containment containment IP3.
IP3, protective coatings are not credited for liner plate corrosion prevention/mitigation prevention/mitigation in in the current
\', '*~1:'lt,'1mt~nm' :,',Ml~.0.:"'" "~};~-'<"~"'t",,'1\lll~\!;mmw:m~.m~~:t~ '1 A' :-::::~,~""~'-l~k'"I'%w:mwmmltt~w~'";m~1W:' ,"~~~:,~A~*'*~"'.<@;'.'%c;;l::~;'l'~,~.~_~'~. '~'~.'~":: :mtt,",m:'.:m:~~~~
Tuesday, March 18, 2008 Page 4 of48 Page of 48
Item Request Request Response design design bases bases for for IPIP 22 and 3. 3.
30 30 AMP AMP B.1.8-5 B.1.8-5 (Containment (Containment Inservice) Inservice) (a)
(a) Describe Describe in in greater greater detail detail the the event event that resulted resulted in the the permanent permanent liner liner plate plate TLAA TLAA 4.6-1 4.6-1 deformation.
deformation.
In In its its review review of of TLAA TLAA Section Section 4.6, the staff staff noted noted Following aa reactor Following reactor trip trip from approximately approximately 7% power, aa break 7% power, break occurredoccurred in in the the that in that 1973 a significant in 1973 permanent deformation significant permanent deformation feedwater feedwater line line to Steam GeneratorGenerator No. No. 22 just inside containment near the inside containment the of of the IP Unit Unit 22 liner liner plate plate occurred occurred at the the feedwater feedwater line line penetration.
penetration. An area of the An area the containment containment liner liner adjacent adjacent to the the penetration for feedwater penetration feedwater line line #22.
- 22. The operating operating feedwater feedwater line line break break was was slightly slightly bulged, bulged, apparently apparently as aa result of steam and of steam and water water experience experience element element of AMP AMP B.1.8 B.1.8 does does not not impingement.
discuss discuss this existing condition nor the results this existing results of inspections conducted periodic inspections conducted under under the the The feedwater The feedwater line incident incident report NL-74-A07, dated January report NL-74-A07, January 14, 14,1974, 1974, from from William William Containment Containment ISI lSI Program.
Program. J. Cahill, Jr., President Indian Jr., Vice President Indian Point to John F. O'Leary, O'Leary, Director of of Licensing Licensing Atomic Energy Energy Commission Commission will be available available on site for for staff review.
(a) Describe Describe in greater greater detail detail the event event that resulted resulted in the permanent liner the permanent liner plate plate deformation.
deformation. specifically did itit occur?
When specifically occur?
When specifically specifically did occur? What was did it occur? was identified identified as the root root cause?
cause? How How was was thisthis corrected?
corrected? November November 13, 1973 1973 (b)
(b) Discuss the history of ISI the history lSI of the permanently permanently What was identified as was identified as the the root root cause?
cause?
deformed liner plate, from 1973 deformed 1973 to the present.
The bulging bulging of the containment liner the containment liner in the vicinity of the the steam steam generatorgenerator No. No. 22 22 feedwater line at feedwater at the penetration penetration was caused caused by the impingementimpingement of steam and water on the liner.
How How was was this corrected?
corrected?
The containment containment building building was pressurized to push ihe was pressurized ihe bulged bulged liner back back in in place.
The liner moved moved 5/8 of an inch inch during pressurization to 15 during pressurization 15 psig and no no further during during pressurization to 47 47 psig.
psig. This This ledled to the conclusion that the liner made contact with the concrete concrete after after the 5/8 inch inch shift and that the extent extent of of the deformation deformation was was not not as as great great as originally originally suspected.
suspected.
modifications were Numerous modifications were made prevent water made to prevent hammers in feedwater lines water hammers lines and improve piping and liner ability to withstand such forces. forces. These included adding adding an additional additional 18 18 feet of insulation above above the pipe break area completely around the the containment (an additional 8 feet in inside of containment in the vicinity of the steam and feedwater lines), changing the piping layout layout to steam generator No. 22 inside containment, steam generator additional pipe installing additional pipe supports, and installing"J installing "J Tubes"Tubes" on the feedwater feedwater ring inside the steam generators generators to delay delay the draining of the feedwater feedwater rings which allowed a steam/water steam/water interface to develop.
(b) General General visual examinations were conducted conducted under the Containment Containment Inservice Inservice Inspection Program between between June, 2004 and November November 2004 for all accessible accessible containment liner, including penetrations areas of the containment penetrations and and airlocks, airlocks, in accordance accordance with Table IWE-2500-1, Category Table IWE-2500-1, Category E-A, Item EU1. El 11.
Minor surface corrosion and/or coating deterioration deterioration were observed on the the penetrations. This is general general surface corrosion that has not not resulted in in any significant loss of material. material.
The containment containment leak rate test at IP2 in in 2006 was completed satisfactorily.
31 31 AMP B.1.9-1 (Diesel Fuel Monitoring) Monitoring) Diesel Fuel Monitoring Program currently includes The Diesel includes sampling activities and and
-analysis on the following tanks in accordance with technical specifications in accordance specifications on fuel oil Provide a more detailed description description of past and and purity and the applicable applicable guidelines of ASTM Standards D1796 (water (water and sediment present fuel oil monitoring present activities at the Indian mo'nitoring activities Indian centrifuge), D2276 (particulate gravimetrically),
by centrifuge), gravimetrically), and D4057 (sampling).
Point site, including surveillance and maintenance Point maintenance *EDG fuel oil storage tanks (21/22/23-FOST, EDG-31/32/33-FO-STNK)
-EDG EDG-31/32/33-FO-STNK) Properties Properties of procedures implemented to mitigate corrosion and procedures #2D Diesel fuel per ASTM D975, particulates particulates per per D2276, Tested 1/80 1/80 days days verify the effectiveness effectiveness of the Diesel Fuel *EDG fuel oil day tanks (21/22/23-FODT, EDG-31/32/33-FO-DTNK)
-EDG EDG-31/32/33-FO-DTNK) Viscosity, Water Monitoring aging management Monitoring management program. program. Provide Provide and Sediment Sediment only (D1796) Tested 1/month lImonth the frequency for the maintenance activities. ~Gas turbine fuel oil storage tanks (GT2/3-FOT, GT1-FOT-11
-Gas GT1 -FOT-1 1/12) /12) Properties of #2D of #2D Diesel fuel per ASTM D975, Diesel D975, particulates particulates per D2276, Tested 1/80 days days
-Diesel fire pump fuel oil
-Diesel oil storage storage tank (DFPFOT) (IP2) Properties of (IP2) Properties of #2D #2D Diesel Diesel fuel fuel per ASTM D975, particulates particulates per per D2276, Tested 1/184 1/184 days
-Security diesel
-Security diesel fuel oil day tank tank (SDDT) (IP2) (1P2) Viscosity, Water and Sediment only (D1796) Tested 1/month (D1796)
-Appendix R fuel
-Appendix fuel oil storage tank (ARDG-FO-ST) (IP3) Properties Properties of of #2D Diesel Diesel fuel fuel per ASTM per ASTM D975, particulates particulates per per D2276, Tested 1/184 1/184 days
-Appendix R
-Appendix R fuel oil day tank (ARDG-FO-DT) (IP3) Viscosity, Viscosity, Water and Sediment Sediment only (D1796)
(D1 796) Tested 1/month 1/month
-Diesel fire fire pump pump fuel oil storage tank (FP-T-3) (IP3) Properties of of #2D Diesel Diesel fuel fuel l~~'\~,~ "~~c:~~tl::~tmmmmmmmmm::mmmm:::::mE+,l!i.*,,,.i42~i~~:'~"'ht~t:,!:'~~~>':t:r:~~~;-.<mH1.1"'J,:;<W1Mi:.4"".<<,~mw.~m:Olm:mw....
~~'.m:m~""";>~"'~-:;~:'::'~'::-.m~~,t:.,;:~~~":"'l~i~.~,;m~m:'ltm~m.1mm%<'"m:m-:,,~0::; ;""'7*'--:;*~:~:.;>::' ," :'\':.;:..,;,,~,,'r:<~~w~.:t Tuesday, March Tuesday, March 18, 2008 Page55 of 48 Page
Item Request Response per ASTM D975, particulates particulates per D2276, Tested 1/184 days The specific specific fuel oil monitoring accomplished in accordance monitoring activities are accomplished accordance with the the specifications and procedure technical specifications procedure 0-CY-1810.
The EDG fuel oil storagestorage tanks, EDG fuel oil day tanks, GT1 gas gas turbine fuel oil storage tanks, GT2/3 gas turbine fuel oil storage tanks, diesel fire pump fuel oil storage tanks, security diesel fuel storage tank, and IP3 Appendix R R fuel oil day tank, are periodically sampled, near near the bottom, once per month to determinedetermine water content. Reference Reference the following following procedures procedures which which were provided provided on site for review:
(Ref. Attachment Attachment 4, 0-CY-1500; 0-CY-1500; Attachment 1, 0-CY-1810) 0-CY-1810)
(IP2 Ref. Section 4.3, 2-CY-1560)
(IP2 2-CY-1560)
The EDG and GT2/3 fuel oil storage tanks are drained, drained, cleaned cleaned and inspected inspected every ten years to detect potential degradation degradation and confirm confirm the absence absence of aging effects.
Reference the following procedures Reference procedures which were available on site for review:
(1P2 Ref. Section 4, 2-GNR-009-ELC; (IP2 2-GNR-009-ELC; GT2/3-FOT*001)
GT2/3-FOT*001)
(1P3 Ref. Section 4, GNR-024-ELC)
(IP3 GNR-024-ELC)
Thickness measurements were performed once on the IP3 were performed IP3 EDG fuel oil storage tanks (31 and 32) to verify that significant significant degradation degradation was not occurring. The Above Above Ground Steel Tanks Program Ground techniques (UT) for the Program includes the use of NDE techniques the GT2/3 fuel oil storage tank once every every ten years during visual inspections.
Reference Reference the following procedures procedures which were provided on site for review:
(IP3 (IP3 Ref. Section Section 4, GNR-024-ELC),
(PM
( PM task GT2/3-FOT*001)
GT2/3-FOT*001) 32 B.1.9-2 (Diesel Fuel Monitoring)
AMP 8.1.9-2 Monitoring) The only tanks known to have an internal coating are the security diesel fuel oil day tank (SDDT) and two EDG fuel oil storage storage tanks (EDG-31/32-FO-STNK).
(EDG-31/32-FO-STNK). The The The LRALRA is silent on the use of tank coatings. Are coating in in tanks is not credited to prevent agingaging effects effects that could result from the fuel the internal surfaces surfaces of any of the fuel oil storage oil environment. The EDG fuel oil storage tanks are inspected inspected on a 10 10 year tanks within the scope.of scopeof license renewal coated frequency frequency in in accordance with 3-GNR-024-ELC.
3-GNR-024-ELC. Step 4.4.1.30 requires an inspection inspection or lined? If If so, describe how the aging of the the of the internal internal of the tank for any any physical defects which would include include defects in the the coating or lining is managed.
managed. coatings. The The SDDT SDDT tank is non nonsafety-related safety-related tank tank that is not inspected due to its its small size (10 gallons). Degradation Degradation of the coating coating would be detected by sampling of the fuel oil in in the tank for particulates.
particulates.
Any coating degradation evaluated under the corrective degradation will be evaluated corrective action action program.
program.
Wr==U= ý-
33 AMP B.1.9-3 Monitoring) 8.1.9-3 (Diesel Fuel Monitoring) The GT-1 tanks are monitored in in accordance accordance with technical specifications on fuel oil technical specifications purity and the guidelines guidelines of ASTM Standards Standards D1 796 (water and sediment by D1796 LRA LRA AMP B.1.9 S.1.9 states that the the program program is being centrifuge), D2276 (particulate gravimetrically),
gravimetrically), and D4057 (sampling). In In addition addition enhanced enhanced to include cleanin cleaningg and inspection inspection of the GT1 GT1 gas turbine fuel oil storage storage tanks, EDG fuel oil day day tanks, and the GT1 fuel oil storage tanktanks,ks, EDG EDG fuel oil day SBO/Appendix R diesel generator SS~/Appendix generator fuel oil day periodically sampled, day tank are periodically sampled, near tanks, and SS~/Appendix SBO/Appendix R diesel generator fuel the bottom, to determine determine water content. The frequencies and acceptance criteria are oil day tank once every ten years. years. Provide Provide a more references below which were provided in the references were available available on site for review.
detailed detailed description description of past and and present present fuel oil (Ref. Attachment 4, 0-CY-1500; AttachmentAttachment 1, 1, 0-CY-1810).
0-CY-1810).
monitoring activities related to these tanks.
34 AMP 8.1.9-4 B.1.9-4 (Diesel Fuel Monitoring)
Monitoring) At IPEC the evidence of microbiological microbiological activity, ififany, is evaluated under the under the corrective action program. If If the evaluation determines a need to use biocides biocides The LRA LRA states that IPEC does not add biocides IPEC does based on additional additional sampling sampling and monitoring, monitoring, this will be handled in in the corrective corrective to diesel fuel oil storage tanks tan ks as recommended in action program.
program. However, the site does not immediately introduce biocides on the the GALL, to prevent prevent biological breakdown breakdown of the microbiological activity based on ASTM Special Technical Publication detection of microbiological Publication exist ing processes diesel fuel. Rather, the existing processes for 1005.
minimizing water contamina contaminationtion of the fuel and and reviewing site and industry operating operating experience The following is a summary of points pOints from ASTM Special Technical Publication appear to be credited. While Whi le these processes 1005, 1005, Distillate Fuel: Contamination, Storage Storage and Handling.
Handling. Copy of document may be effective effective in determin determiningning the existence of provided on site for review.
biological contamination, the biological theyey do not appear appear toto meet the intent of GALL for preventing preventing and detection of viable microorganisms "The mere detection microorganisms in in hydrocarbon hydrocarbon fuels or oils is not not minimizing the accumulation accumulationn of biological activity.
activity, evidence of a significant microbial involvement. Distribution of the microorganisms microorganisms is Also, the LRA does not address add ress an apparent apparent unlikely to be homogeneous, and obtaining aa representative representative sample can be difficult difficult exception to NUREG exception NUREG 1801, 1801, Element Element 7, regarding regarding or impossible. In contrast to this uncertainty uncertainty (that microbes are homogeneously homogeneously the addition of biocide to fuel fue l oil when the distributed) the appearance of corrosivity distributed) corrosivity in in stored petroleum products is good presence activity is confirmed.
presence of biological activity confirmed. Please presumptive sulfate-reducing bacteria presumptive evidence that sulfate-reducing bacteria are at work."
clarify. "As aa first step inin preventing preventing the adverse adverse effects of microbial microbial growth in in practical situations, water water should be eliminated from storage and and handling systems. As a last last resort the use of aa biocide may be necessary. The new problems that are introduced, introduced, as the result of usingusing a biocide biocide should should be carefully considered."
~~1m;,,~,,:,,::::::.~;:::::;:,::::~~"':.~~m:~...z.::.,,~;::::,':-:::.:::::::~t.'$'~':lMl~li'3;&",,..~'t~:m"~~"'{l2~:::..,::~mm::<a~*:::~"A~-;':":'::~':;U"~~
Tuesday, March 18, Tuesday, March 18, 2008 2008 Page 6 of 48
Item Request Response IPEC does take exception to Element 2 in in that biocides are not currently currently used at IPEC, However, this is not considered an exception exception to GALLGALL in in element 7 since biocides will be used if under the correction action program deems if evaluation under deems them necessary to correct the condition.
necessary 2-CY-1 560 section 4.5 and 3-CY-condition. Procedures 2-CY-1560 2615 section 4.1 allow the additionaddition of biocides biocides for IP2 IP2 and IP3 if needed.
needed.
35 AMP B.1.9-5 (Diesel Fuel Monitoring) Monitoring) Purchase specifications Purchase specifications for fuel oil have specific technical technical requirements that the fuel be ASTM 2D fuel oil meeting specifications of ASTM D975 in order to ensure meeting the specifications ensure it Describe how the quality Describe quality of initial initial fuel oil meets quality standards for delivery.
purchases and deliveries purchases deliveries is ensured.
36 AMP B.1.9-6 (Diesel Fuel Monitoring) Monitoring) procedures or tasks requiring NDE of the tank bottom The only fuel oil tanks with procedures bottom areare the IP3 EDG storage tanks and the GT2/3 storage tank. These inspections are These inspections The LRA LRA states that thickness measurements of of described in procedure GNR-024-GLC and PM procedure GNR-024-GLC PMitask
'task GT2/3-FOT*001 GT2/3-FOT*001 which are storage tank bottom surfaces are performed to available on site for review. The minimum acceptable available acceptable thickness for each tank bottom verify that significant significant degradation degradation is not occurring.occurring. when inspected is based upon a component component specific specific engineering evaluation. Wall engineering evaluation.
Provide Provide the procedures procedures used to perform this this ,thickness will be acceptable
.thickness acceptable if if greater than the minimum wall thickness thickness for the surveillance surveillance and describe the acceptance acceptance criteria criteria specific component. A copy of PM task was provided for review.
and basis for minimum minimum wall thickness. Also Also provide a technical provide technical basis for the specified 10 10 year year The basis for the 10 year wall thickness inspection inspection frequency is to perform the the surveillance surveillance frequencies. inspections in inspections in conjunction with other 10 10 year inspections and cleanings which is year inspections consistent with the recommended consistent recommended frequency frequency in in Reg. Guide 1.1371.137 and meets New New York State regulations for fuel oil storage tanks. Past visual inspections of fuel oil Past visual storage tanks have not detecteddetected significant degradation that would lead to a need for significant degradation for increased inspection an increased inspection frequency.
37 AMP B.1.9-7 (Diesel Fuel Monitoring) Monitoring) As specified specified inin the IPEC commitment list for Commitment implementation Commitment 7, the implementation schedule enhancements to this program are schedule for the enhancements are Provide the schedule Provide schedule for implementation of the the IP2:
enhancements to this AMP.
enhancements September September 28, 2013 28,2013 IP3:
December 12, 2015 2015 38 AMP B.1.11-1 (Extern~1 (External Surfaces Monitoring)
Surfaces Monitoring) The surfaces included in the program program are the external surfaces of carbon steel, stainless steel, copper alloy, cast iron, and aluminum aluminum components that are normally normally Give details details of surfacessurfaces included in the external Surfaces that are insulated are inspected when insulated. Surfaces when the external surface surface is Surface Monitoring Surface Monitoring Program Program accessible only when exposed, e.g.,
e.g., during maintenance. Routine maintenance occurs Routine maintenance occurs at such intervals intervals the insulation insulation is removed. that there is reasonable assurance effects of aging will be managed assurance that the effe'cts managed such that applicable applicable components will performperform their intended function during the period of extended operation.
operation.
39 AMP B.1.12-1 8.1.12-1 (Fatigue Monitoring) Monitoring) (a) IP2 andand IP3: Site data data is reviewed reviewed by a cognizant engineer to determine cognizant engineer determine transients that have occurred since the last review. The engineer then updates occurred since updates the the The LRA states in in the Program
Description:
list of total transients to date. Transients reviewed include those listed reviewed include in Table 4.3-1 listed in 4.3-1 (IP2) and 4.3-2(IP3) of the LRA and Table 4.1-8 of the UFSAR. Procedures 2-PT-The program program ensures the validity of analyses analyses that 2Y015, Thermal Cycle Monitoring Program 3PT-M051, Plant Operation Program and 3PT-M051, Operation explicitly analyzed a specified specified number number of fatigue fatigue Information Information was available for review review on-site on-site and provide provide further details.
transients by assuring assuring that the actual effective effective number of transients number transients does not exceed the the described in As described enhancement to the Fatigue Monitoring Program, IP3 will in the enhancement analyzed number of transients. transients. complete a review of existing fatigue analyses complete analyses of record and enhance the fatigue fatigue additional transient cycles similar to what has been monitoring program to include additional monitoring (a) Please describe describe the method method used to determine determine done for IP2. This enhancement to the IP3 identificationidentification and tracking tracking of transients is the actual effective number of transients. identified in Commitment 6.
identified in (b) Which component(s) will this methodology methodology be be (b) Determination of actual numbers transients is independent of specific numbers of transients specific applied to? components. The method method is applied to transients. Different components components are are different transients. The affected by different affected The basis for the IP2 designdesign cycles is described described in in WCAP-12191, Revision WCAP-12191, Revision 3, Fatigue Cycle 3, "Transient and Fatigue Cycle Monitoring Monitoring Program Program Transient History Evaluation Final Report for Indian Point 2". WCAP-12191 History Evaluation WCAP-12191 was was available available for review review on-site.
40 AMP AMP B.1.12-2 (Fatigue (Fatigue Monitoring) Monitoring) IP2: Alert cycles are defined as the number of cycles which may accumulate accumulate in in two monitoring monitoring periods. If If the number of analyzed exceeded using alert cycles, analyzed cycles is exceeded The LRA states in in the Exception Section Section that "The"The aa condition report is generated to ensure that correctivecorrective actions actions are taken prior to to IPEC program updates updates fatigue fatigue usage usage calculations calculations exceeding the analyzed number of cycles. The number of alert cycles is calculated exceeding calculated when the number of actual actual cycles approachapproach the the accumulated during by taking the cycles accumulated multiplying them by 2, and during the period, multiplying analyzed number number of cycles." adding them to the total accumulated adding accumulated cycles to 'date.date. IfIf this projection projection remains remains below the total number of analyzed further action is required.
analyzed cycles, no further, required.
What are the action or alarm alarm limits that will trigger
, ":.;'<:,' )"' ,'tA,W.~'i:-! *:;;';;;d/i .... .. : '3':,,,~~',,, ,',:,',' ,*.*7,V}~x~:r:'
Tuesday, March Tuesday, March 18, 2008 Page 70'48 Page 7 of 48
Item Request Response the corrective corrective action. fatigue monitoring program does not have action or alarm limits.
IP3: The current fatigue The cognizant supervisors determine cognizant engineer and the reviewing supervisors determine ifif a condition report is required. Plant operation operation is not allowed allowed ifif the analyzed number of aa appropriate engineering particular transient is exceeded unless appropriate evaluation under the engineering evaluation the corrective action program has determined it acceptable.
has determined acceptable.
This item has been closed to question question #119.
TIMOMMI-IMIMMMMý 41 AMP 8.1.12-3 B.1.12-3 (Fatigue Monitoring) Monitoring) (a) LRA LRA Table 4.3-2 reflects the transients monitoredmonitored by the IP3 fatigue monitoring monitoring program. IP3 has not expanded program beyond UFSAR Table 4.1-8.
expanded the program Under Enhancement Enhancement Section: Section: For IP3, the the IP3 will complete complete a review of existing fatigue fatigue analyses analyses of record and enhance the enhance the applicant proposes to "revise appropriate appropriate monitoring program to include additional fatigue monitoring transient cycles similar additional transient similar to what has procedures to include procedures include all the transients identified." been done for IP2. enhancement to the IP3 identification IP2. This enhancement identification and tracking of identified in Commitment 6.
transients is identified (a) Please list all applicable applicable transients.transients.
(b) IP2 has performed aa detailed review of required transients as documented (b) documented in in (b) Why does this enhancement (b) enhancement not apply apply to IP2?IP2? WCAP-12191, Revision 3, "Transient and WCAP-12191, and Fatigue Cycle Monitoring Program Program Transient History Evaluation Final Report for Indian Point 2". WCAP-12191 is History Evaluation available for review available review on-site.
42 AMP 8.1.12-4 B.1.12-4 (Fatigue Monitoring) Monitoring) (a) Cumulative usageusage factors (CUF) are re-evaluated re-evaluated when the actual actual number of cycles approaches approaches the design limit as shown in UFSAR Tables 4.1-8 for IP2 and The LRA states in the Operating Operating Experience Experience that IP3. Refer to the response to Audit Question AMP B.1.12-2. 8.1.12-2.
the Fatigue Monitoring Monitoring Program includes re evaluation evaluation of usage factors as appropriate. (b) The originallP2 original IP2 design did not include include a fatigue analysis for charging nozzles.
Westinghouse Westinghouse noted the transient in letter IPP-90-752 IPP-90-752 dateddated September 1990. The The (a) What factors/conditions would warrant a re-What factors/conditions IP2 charging nozzle nozzle transient transient cycle history was updated along with other analyzed evaluation.
evaluation. transients in the development development of WCAP-12191, WCAP-1 2191, Revision 3, "Transient and Fatigue Fatigue Cycle Monitoring Program Program Transient History Evaluation Final Report Report for Indian Point (b)
(b) Under What what circumstances circumstances that IP2 charging charging 2".
nozzles nozzles were re-evaluated? re-evaluated? Please describe describe the the re-evaluations re-evaluations process process for IP2 charging nozzles.
43 AMP B. 1.15-1 (Flow-Accelerated 8.1.15-1 (Flow-Accelerated Corrosion) The piping and affected affected components were included included in the FAC program prior to these inspections. As the wall thinning of these components components was discovered discovered during during The LRA states that the incidents of wall thinning the outage, they were replaced with like for like materials. Subsequent were replaced Subsequent to these were detected detected in in the the vent vent chamber chamber drain drain and and high high outages, the Wet Steam Pipe Replacement Project has has and will replace piping found found pressure turbine pressure turbine drain components during drain components during 3R1 3R13 3 in in to be worn by past FAC inspections with FAC resistant materials. The High materials. The High March 2005 March 2005 and in in a steam steam trap pipe during 2R17 2R17 Pressure Turbine Drain piping downstream downstream of the control valves was replaced replaced with in May 2006. These These incidents incidents resulted in chrome moly during 3R14. The Vent Chamber Drain piping i~
Vent Chamber is to be replaced with replacements of replacements of thethe affected components during affected components during chrome moly piping.
piping. The replacement is to be performed in* in three three phases. Phase 1 the respective respective outages. Describe if if the piping and included the "A""A" train and was completed during 3R14. Phase Phase 2, to be performed the affectedaffected componentscomponents were included included in in the FAC during 3R15 will include include the "B""8" Train, and Phase 3 to be performed during 3R16 3R16 program prior program prior to to these inspections and these inspections and if if the the will include include the common common "A" "A" and "B" "9" Train piping.
piping.
affected components components were replaced replaced with the like like for like like materials materials or or withwith aa FAC resistant resistant material material Actual thickness data of vent chamber chamber drain, high high pressure turbine drain and steam such as chrome-moly. chrome-moly. Also substantiate substantiate the the trap components components are provided below.
response with response with actual actual thickness thickness data, data, i.e.,i.e., the the nominal thickness, nominal thickness, minimum minimum acceptableacceptable thickness thickness Unit 3 and the and the measured measured thickness thickness at these affected Vent chamber drain drain piping -
locations. schedule 40 3" diameter, schedule 40 Nominal Nominal wall thickness thickness 0.216" Minimum Minimum acceptable thickness 0.123" acceptable thickness Minimum Minimum thickness required required for 22 more years years of service service after 3R13 0.135" Minimum Minimum measured measured thickness 0.052" High High pressure pressure turbine drain piping -
2" diameter, schedule schedule 80 80 Nominal Nominal wall thickness 0.218" 0.218" Minimum Minimum acceptable thicknessthickness is 0.083" Minimum thickness thickness required required for 2 more years of service after 3R1 3 0.116" after 3R13 Minimum measured thickness thickness is 0.085".
High pressure pressure turbine draindrain piping -
3/4"
- y." diameter, schedule schedule 80 80 Nominal wall wall thickness 0.154" acceptable thickness Minimum acceptable thickness 0.046" Minimum thickness required for 2 more more years of service after 3R13 0.059" measured thickness 0.059" Minimum measured Unit 2 Unit2
~,,~, ':~'~' ,,¥.<<~. ','.,;' "~ ,. ~~f> ,,~".~~m~wtmm~~tmmm:,,~r,:~:t,~~~, ~, , l' '" ~1,-::mm'~:mmmmmmmm~>::
Tuesday, March Tuesday, March 18, 2008 Page 8 of 48
Item Request Response Steam trap piping -
1" diameter, schedule 1" schedule SO 80 Nominal wall thickness Nominal 0.179" thickness 0.179" Minimum Minimum acceptable acceptable thickness thickness 0.054" Minimum Minimum thickness thickness required for 2 more years years of service after after 2R17 0.072" Minimum Minimum measured measured thickness thickness 0.063" 44 AMP B.1.15-2 B.1.15-2 (Flow-Accelerated (Flow-Accelerated Corrosion)
Corrosion) Timeline for CHECWORKS CHECWORKS update -
The LRA states that operating operating experience experience for IP2IP2 Unit2 Unit 2 and IP3 was was accounted for in in the most recent recent updates updates of the respective respective CHECWORKS CHECWORKS FAC CHECWORKS CHECWORKS Model Model update completed incorporating the wear rate completed 3/23/2005 incorporating rate models. The LRA further states that the the changes changes due to the power uprate.
CHECWORKS CHECWORKS models models were updated using the the CHECWORKS CHECWORKS Model Model update completed 9/12/2006 incorporating incorporating 2R17 inspection inspection inspection data from the outage outage inspections inspections and and data.
the FAC wear wear rate changes due to the recent power power uprates. Provide Provide aa time line whenwhen these Unit 3 Unit3 models models were updated updated and inspection data from which outages was utilized in the updates. Has utilized in Has IP CHECWORKS CHECWORKS Model Model update completed completed 3/23/2005 incorporating incorporating the wear rate rate ever ever experienced experienced situations situations in which the model changes due to the power uprate.
predicted wear rates may have been lower than CHECWORKS Model Model update completed 10/25/2005 incorporating 3R13 3R 13 inspection the actual actual wear rates measured during FAC FAC data.
inspections? IfIf yes, describe inspections? describe how were thesethese nonconservative wear nonconservative predictions handled wear rate predictions handled CHECWORKS Predicted wear wear rates rates -
and and what has been been done done to correct correct the model?
model?
Indian Point has adopted adopted EPRI EPRI recommendations recommendations and modeledmodeled plant piping using using realistic operating operating conditions. Therefore, Therefore, there are instances where the model predicted wear rate is less than the actual wear rates measured measured during FAC inspections. This results in in a Pass 22 analysis Line Correction Correction Factor (LCF) greater than 1.0, CHECWORKS algorithm 1.0, indicating the CHECWORKS algorithm is under-predicting under-predicting the wear rates.
In cases In cases where the wear rate is higher than predicted predicted and and remaining service service hours are low, these components components are selected inspection, thereby targeting the "worst" selected for inspection, "worst" components first and expanding the inspection components inspection scope to other components components that are are also likely worn. The increase increase in inspections provides assurance the components in inspections components are suitable for continued continued service, and additional additional inspection data data as input to the the model.
components have been inspected, aa trended Once the components approach (from trended wear rate approach section 4.7 of EPRI NSAC 202L) is used to schedule schedule the next time to inspect the the components, with safety conservatism.
safety factors for conservatism.
The CHECWORKS CHECWORKS model is corrected corrected every outage outage with the latest latest chemistry, operating, and inspection inspection data. Through the Pass 2 Wear Wear Rate Rate Analysis process process in CHECWORKS, CHECWORKS, predicted wear rates are adjusted to coincide with measured measured wearwear rates. In In the case where the model predicted wear rate is less than the actual actual wear rate, the predicted wear rates are increased increased (multiplied (multiplied by the LCF) to match the the inspection data. Over time, this approach approach aligns aligns CHECWORKS CHECWORKS predictions to actual conditions in in the plant.
45 AMP B.1.15-3 B.1.15-3 (Flow-Accelerated (Flow-Accelerated Corrosion)
Corrosion) 1. Update
- 1. Update of CHECWORKS CHECWORKS version from 1.0G 1.OG to SFA CHECWORKS CHECWORKS FAC Version 1.0 was released by EPRI in 1993. In 2000, in in Provide a few examples examples of modifications modifications and/or and/or recognition of the fact that CHECWORKS CHECWORKS would not function under future Windows Windows improvements to the FAC program at Indian Point improvements operating operating systems, EPRI began development development of the successor successor code, CHECWORKS CHECWORKS in the past in past five years. What were the specific specific SFA 2.0 (and later CHECWORKS SFA 2.1 and 2).
reasons (e.g., lessons learned, learned, plant operating The reason for the conversion conversion is twofold.
experience, industry experience experience or other (define)) The first was to stay current current with industry industry trends. With the release of CHECWORKS CHECWORKS for those changes and how have the changes changes SFA, EPRI will discontinue discontinue support support of the CHECWORKS CHECWORKS 1.0 1.0 software. To benefit made the FAC program program more effective with with from any future changes or improvements improvements to the CHECWORKS CHECWORKS software, the the respect to the management of aging? aging? database must be compatible compatible with CHECWORKS CHECWORKS SFA.
The second intention of the conversion conversion was to improve improve the accessibility accessibility to the the CHECWORKS database. Conversion to CHECWORKS CHECWORKS CHECWORKS SFA creates a model with with the ability ability to import import and export data (not possible possible in version 1.0), enabling us to more accurately accurately and efficiently compile program information such as outage program information outage inspection scopes.
- 2. Implementation of FAC Manager software software Use of FAC Manager software was implemented implemented at IPEC. Industry Industry experience experience using this software has been positive. The software allows us to efficientlyefficiently manage manage FAC FAC related activities.
activities. For example, FAC Manager Manager performs performs all the non safety-related safety-related wall thinning calculations calculations (100+ calculations per outage) using the Entergy (100+ calculations Engineering Engineering Standard "Pipe Wall Thinning StructuralStructural Evaluation" ENN-CS-S-OOS.
ENN-CS-S-008.
~'; .:.:mo.."tr'J';'>m.l$K1*,~i:'_;; "':;:~:r,s~:~mmmmW;W"&;?i';:
Tuesday, Tuesday, March March 18, 2008 2008 Page 9of 4 8
Item Request Reouest Response Resoonse Item Reauest ResDonse This This software software decreases decreases the the probability probability of of calculation calculation errorerror associated associated with with manual calculations resulting in less calculations less errors errors and and omissions.
omissions.
Other Other benefitsbenefits include: include:
provides aa consistent It provides consistent approach approach at at all facilities benefiting all facilities benefiting shared shared resource resource personnel.
personnel.
All All FAC related related data data is consolidated in one is consolidated one place, saving time and minimizing minimizing errors errors due to to referencing referencing several several data data sources.
sources.
Multi-user / site capability Multi-user capability allows analysis analysis from other other sites, utilizing resources and utilizing resources and expertise from across expertise across the fleet. fleet.
- 3. Updating Updating CHECWORKS CHECWORKS Model Model to to include include power uprate uprate Power Power uprate uprate changed changed feedwater feedwater and and steam steam flow rates, and and temperatures, temperatures, which in in turn changed changed local local chemistry values. values. All of these these factors affectaffect wear rates due to to FAC.
FAC. The The pre-uprate pre-uprate CHECWORKS CHECWORKS model model did not not address address the changes resulting the changes resulting from the the Appendix Appendix K and and stretch stretch power power uprate.uprate. The update of the the CHECWORKS CHECWORKS model reflects model reflects all plant power power level changes (the original level changes original power power level, level, Appendix Appendix K K uprate and stretch power uprate power Uprate).
Historical (pre-uprate Historical (pre-uprate and Appendix Appendix K uprate) uprate) operating operating conditions remain within conditions remain within the the model, associated with the applicable model, associated applicable operatingoperating cycles. This ensures that that the the model's model's predictionspredictions of total current current and future wear wear will be as accurate as possible as accurate possible because the predictions because predictions will be based on both historical historical and and current current operating operating conditions.
conditions.
4.
- 4. Development Development of fleet procedure EN-DC-315 fleet FAC procedure EN-DC-315 To support the Entergy To standardization effort, a fleet-wide FAC procedure Entergy standardization procedure was was developed to standardize developed standardize the FAC program program at all the Entergy Entergy Nuclear Nuclear sites. A A common corporate corporate procedure procedure provides a consistent approach to managing consistent approach managing FAC. FAC.
This This enables enables more more efficient efficient use of of shared resources, and shared resources, and facilitates the effective effective use use knowledge/expertise and operating of knowledge/expertise experience across operating experience the fleet.
across the Wili%
46 (Flow-Accelerated Corrosion)
AMP B.1.15-4 (Flow-Accelerated Corrosion) [1] If a component
[1]lf component is discovered that that has a current current or projected wall thicknessthickness lessless than the minimum acceptable wall thickness (Taccpt), then additional inspections of additional inspections measurements during If the thickness measurements If during FAC FAC identical or similar piping components identical components in parallel or alternate train is performed in aa parallel performed to inspection indicate degradationdegradation or wall thinning thinning bound the extent of thinning.
beyond the predicted predicted minimum wall thickness, [2] When When inspections of components components detect detect significant wall thinning, the sample size size how would the sample size be adjusted under under for that line is increased to include the following: following:
Indian Point's FAC Program to address the Indian the (a) Components within vwithin two diameters diameters downstreamdownstream of the component component displaying detected degradation?
detected degradation? Include Include actual inspection significant wear or within two diameters significant diameters upstream ifif the component component is an an expander data and examples examples to substantiate the response. or expanding elbow.
(b) A minimum of the next two most susceptible (b) susceptible components from the relative wear ranking in the same train as the piping piping component component displaying significant wall thinning.
significant wall thinning.
(c) Corresponding Corresponding components components in in each other train of a multi-train multi-train line with a configuration similar to that of the piping component configuration component displaying significant significant wall thinning.
Vent Chamber Drain Drain (VCD) pipe pipe thinning thinning during 3R13 3R13 3R1 3 inspection of a VCD elbow immediately 3R13 immediately downstream of MSR-31A PCV-7008 PCV-7008 found wall thinning less than the minimum acceptable acceptable wall thickness, requiring requiring replacement of the elbow. elbow. Based Based on on the results results of this exam, aa sample this exam, sample expansion expansion performed to determine was performed determine the extent of condition for this pipe thinning.
The expansion included included corresponding corresponding components components on on the the other other moisture moisture separator separator reheaters with a configuration similar similar to that of the elbow displaying displaying the the thinning.
Four additional inspections were performed. These inspections also found wall thinning less thinning less than than the the minimum minimum acceptableacceptable wall wall thickness, thickness, requiring replacement of requiring replacement of these components.
these The sample expansion The expansion was continued until until no no additional additional components components were were detected detected with significant wear. Four additional additional inspections inspections were were performed performed downstream downstream of of the the worn elbows. The results of this expansion did not find significant wear and the wom the sample expansion was terminated.
The vent chamber The chamber drain lines,on lineson Unit 22 were were replaced replaced with with FAC-resistant materials, FAC-resistant materials, and were were not not considered in in th*is this sample sample expansion.
expansion.
Reheater Drain Drain pipe pipe thinning during 3R14 3R14 A leak A leak in in the the reheater reheater drain drain system system was detected during was detected during cycle cycle 14.14. AA review review ofof both both Unit 2 and Unit 33 FAC programs was performed performed to determine determine ifif similar locations to to this leak have been been inspected inspected for for wall wall thinning thinning and determine ifif additional and determine additional inspections were required.
review of A review of thethe Unit Unit 22 FAC FAC inspection inspection history history foundfound that that all all similar similar locations locations hadhad
- l"
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Tuesday, Tuesday, March March 18, 2008 18, 2008 Page 10 of 48*
Page 48
Item Request Response
Response
been been recently inspected inspected or replaced. No additional additional inspections inspections were recommended.
A review of the Unit 33 FAC inspectioninspection history found some similar locations locations that diddid not have have recent inspections inspections and were recommended for inspection.
were recommended inspection. A total of 9 inspections were added added on the A and B trains at locations locations similar similar to the leak.
As a result of these inspections, two elbows elbows were found to have wall thinning and were were replaced replaced during 3R14. Review Review of the sample expansion expansion developed for the the initial leak determined determined that the wall thinning was bounded bounded by this expansion.
expansion. All similar similar locations have been identified and scheduled scheduled for inspection during 3R14.
Inspection of the remaining 7 components components found them acceptable for continued them acceptable continued service, and will continue continue to be monitored in the FAC Program. Program.
47 (Flow-Accelerated Corrosion)
AMP B.1.15-5 (Flow-Accelerated Industry experience is reviewed in Industry in accordance accordance with the corporate procedure procedure EN-OE-EN-OE-100 Operating Operating Experience Experience Program and is implemented in in conjunction with thethe How is the industry industry experience utilized utilized inin the FAC FAC corrective action program.
program. Details Details on the review and actions to be taken are Program at Indian Point? How does IP IP gets gets provided in in this procedure. A site OE coordinator coordinator screens screens incoming operating operating feedback from other plants? Are there any unique unique experience for site applicability. This-includes experience within the This*includes operating experience the differences between the FAC Programs of IP2 and differences corporation and the industry. In Entergy corporation In addition, addition, other other utilities participate in QA IP3?
IP3? IfIf wall thinning or degradation degradation is observed audits of programs where they provide provide their unique experience.
experience.
during FAC inspection inspection of one unit, are the the corresponding corresponding components on the other unit unit experience is evaluated, and if applicable Industry experience applicable to IPEC is incorporated incorporated into the the inspected for similar degradations?
inspected degradations? FAC inspection inspection scope. Feedback from other other plants is obtained obtained from attendance attendance at CHECWORKS users users group (CHUG) meetings where where industry OE is exchanged exchanged during the formal presentations presentations as well as an information information exchange exchange session where describes issues encountered each utility describes encountered since the last meeting.
meeting. Another source of OE is FACnet. It It is a communications communications tool used by FAC personnel to ask questions, share ideas, and and exchange exchange information via email.
The only previous differences between the Unit previous differences Unit 2 and Unit 3 FAC Programs Programs werewere dealing with how the data was stored and how specific component component evaluations were performed. With the implementation implementation of the corporate procedure and the use of corporate FAC procedure FAC Manager, the Unit 2 and Unit 3 FAC programs are now now very similar.
When thinning or degradation is observed during FAC inspection inspection of one unit, the the corresponding components components on the other unit are are evaluated evaluated for similar degradation.
degradation. '
Examples are provided in in the response to AMP B.1.15 Question # 46, where the the extent of condition condition review evaluates evaluates the other unit for similar degradations degradations 48 AMP B.1.15-6 (Flow-Accelerated (Flow-Accelerated Corrosion)
Corrosion) (a) This was an internal QA department an internal department audit with assistance assistance from an outside utility utility and the purpose was to confirm that several IPEC Unit 2 programs severallPEC programs including FAC FAC The LRA LRA states that the FAC Program for IP2 was were in in compliance compliance with the requirements requirements of the NRC Regulations, Codes, Industry audited audited in 2004 2004 and that the audit team Standards, IPEC Unit 2 Technical SpeCifications, Specifications, Final Safety Safety Analysis Reports and determined determined that the program was effective and in in commitments. A similar audit was recently recently performed performed for Unit 3 in in the spring spring of 2007 2007 compliance compliance with ASME code, with ASME code, EPRI EPRI standards, standards, and documented and documented in in audit audit report report QA-08-2007-IP-1.
QA-08-2007-1P-1. This This audit determined determined that the the and INPO guidelines and NRC regulations.
INPO guidelines regulations, program program was satisfactory satisfactory with no findings. There have also been QA surveillances surveillances performed performed of the IP3 programs in IP3 and IP2 programs in 2005 and 2006.
(a) Which organization organization performed this audit and (b)
(b) QA audits are performed in accordance accordance with corporate nuclear management nuclear management what was the purpose purpose of this audit? Was a similar manual procedure EN-QV-109 EN-QV-109 Audit Process. The following following specific documents of specific documents audit performed performed on IP3 FAC Program? , the organizations organizations stated in the question were reviewed as part of the audit:
(b) Explain documents of the stated Explain which specific documents NRC Generic Generic Letters 89-08 & 90-05, NUREG-1344, NUREG-1 344, ANSI B31.1, B31.1, EPRI Report TR-organizations werewere used in in the audit to establish 10611, NSAC 10611, 202L-R2, INPO SOER's NSAC202L-R2, SOER's 87-3 & 82-11.
82-11.
program compliance.
compliance.
. (c) The following features features of the FACFAC program were reviewed:
reviewed: procedures, FAC FAC (c) Which specific specific elements of the Indian Indian Point industry experience, wall thinning analysis inspections, industry analysiS and calculations, calculations, and FAC Program Program and what documentation what specific documentation corporate and IPEC commitments.
commitments. Though this inspection inspection was not an inspection inspection of pertaining to the program program was reviewed by the the FAC FAC program elements elements described in NUREG-1801, NUREG-1801, itit did review portions of the the audit team to establish that the program was encompass elements program that encompass elements of B.1.15. These elements would would be Scope, effective?
effective? Preventive Actions, Parameters Parameters Monitored, Detection of Aging Effects, Monitoring Monitoring and Trending, Trending, Acceptance Operating Experience.
Acceptance Criteria, and Operaiing Examples of Experience. Examples documents reviewed include ENN-DC-315 reviewed include ENN-DC-315 rev. 0, ENN-NDE-9.05, EPRI Technical Report NSAC-202L-R2, Report NSAC-202L-R2, IP-CALC-04-01727 IP-CALC-04-01727 and and IP-CALC-04-01620, IP-CALC-04-01620, and and IP-CALC-IP-CALC-04-01713, Revision 04-01713, Revision 00 49 AMP B.1.15-7 (Flow-Accelerated (Flow-Accelerated Corrosion) Identification of degradation Identification degradation and corrective corrective action prior to loss of intended intended function provide assurance that the FAC Program Program is effective effective for managing aging effectseffects duedue The LRA includes The LRA experience items operating experience includes operating items to flow accelerated to accelerated corrosion. Corrective actions are addressed corrosion. Corrective addressed by the wet steam which pertain to which pertain inspections during to inspections during 3R13 3R13 and and replacement project. This project is aa multi-year task to replace replacement replace FAC susceptible FAC susceptible 2R17 2R17 outages outages for IP3 and IP2 respectively. Both piping with FAC resistant resistant material. Replacement Replacement materials materials include include stainless steel, items iiems are are recent (March (March 2005 and May May 2006 chrome-moly and carbon chrome-moly carbon steel pipe with a stainless steel liner.
respectively) items. Provide Provide more more examples of
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Tuesday, March 18, 2008 Page Tuesday, March 18, 2008 Page 11 of of4848
Item Request Response inspection results to demonstratedemonstrate that the FAC The following are more more examples of inspection inspection results to demonstrate demonstrate that the FAC FAC program at Indian Point is effective in in managing program is effective effective in in managing the effects effects of aging.
the aging effect.
Wall thinning was found on the LP extraction steam lines to the Unit 22 22 feedwater feedwater heaters that are located inside the condenser heaters condenser neck. As part of the wet steam pipe pipe replacement project, these lines replacement lines are being replaced with FAC-resistant chrome chrome moly material. The The 22C feedwater heater extraction extraction steam lines were replaced replaced during during 2R17 (2006) and and the 22A and 22B feedwater feedwater heaters extraction steam lines are to heaters extraction be replaced during 2R18 2R18 with chrome moly material. Inspections Inspections performed performed for Unit 3 32 feedwater heater extraction extraction line found these components components acceptable acceptable for continued service continued service and and will will notnot require require replacement.
replacement.
Wall thinning was found on two 35 extraction extraction steam steam elbows elbows during during 3R14 FAC inspections.
inspections. As part of the wet steam steam pipe replacement replacement project, these lines are being being replaced replaced with FAC-resistant FAC-resistant chrome moly material during 3R15. 3R1 5. The 25 extraction steam line for Unit 2 was replaced entirely with stainless extraction stainless steel and chrome chrome moly material.
Wall thinning was found on the steam lines from the preseparators preseparators to the 35 35 extraction extraction steam header at Unit 3 during 3R12 3R1 2 FAC inspections. As part of the wet steam pipe steam pipe replacement replacement project project these these lines lines were were replaced replaced with with carbon carbon steel steel piping piping with a stainless stainless steel cladding during 3R13 (2005). The 25 extraction extraction steam line line for Unit 2 was replaced replaced entirely with stainless steel and chrome chrome moly material.
Additional Additional pipe replacements by the Wet Steam Pipe Replacement Replacement Project include:
3R14, 2007 3R14,2007 Due to wear found in FAC inspections, approximately approximately 700' of carbon steel Vent Vent Chamber Drain piping was replaced replaced with FAC resistant chrome chrome moly piping. In In addition, the carbon carbon steel discharge discharge piping from the High High Pressure Pressure Turbine Drain Drain Main Steam flow control valves (9 lines totaling approximately approximately 50 feet of pipe) to the the condenser were replaced replaced due due to wall thinning observed observed during FAC FAC examinations.
2R16, 2004 2R16,2004 Due to wear found in in FAC inspections, approximately approximately 200' of carbon steel Vent Vent Chamber Drain piping was replaced replaced with FAC resistant chrome chrome moly piping. Also Also replaced was approximately 10' of carbon steel MSR MSR drain piping downstream of piping downstream LCV-1 105A to LCV-1105A the 26 to the 26 FWHs FWHs with with FAC resistant chrome FAC resistant chrome moly. moly.
3R12, 2003 3R12,2003 Due to wear found in in FAC inspections, the carbon steel North to South Main Steam Trap header was replaced replaced with FAC resistant chrome moly piping; the 33 Feedwater Feedwater Heater Operating vent carbon steel piping was replaced Heater Operating replaced with FAC resistant chrome chrome moly.
2R15, 2002 2R15,2002 Due to wear found in in FAC inspections, approximately 150' 150' of carbon steel extraction steam piping to FWH23A was replaced replaced with FAC resistant chrome moly, and approximately approximately 200' of carbon steel Feedwater Feedwater Heater Heater 23 A, Band B and C operating operating vent piping was replaced with FAC resistant chrome moly.
3R11, 2001 3R11,2001 Due to wear found in in FAC inspections, approximately approximately 40' 40' of carbon steel extraction steam piping to the 35A and 35B FWH was replaced with FAC resistant chrome chrome moly piping, and the carbon steel 36 FWH operating vents were were replaced replaced with FAC resistant chrome chrome moly pipe. In addition 9 extraction extraction steam steam traps carbon steel piping piping was replaced replaced with FAC resistant chrome moly moly piping.
2R14, 2000, .
2R14,2000 Due to wear found in FAC FAC inspections, approximately approximately 1700' 1700' of carbon carbon steel Vent Vent Chamber Drain piping was replaced replaced with FAC resistant resistant stainless steel, and and approximately 115' of carbon carbon steel 25 FWH extraction extraction steam piping was replaced replaced with FAC resistant stainless steel.
50 B,1.16-1 (Flux Thimble Tube Inspection)
AMP B.1.16-1 Consistent with the program program description described in GALL, other applicant-justified applicant-justified NRC-accepted inspection and NRC-accepted inspection methods methods may be used. However, only eddy current current LRA AMP B.1.16, "Program Description" states: testing is used to monitor monitor thinning of flux thimble tubes at IP2 and IP3. IP3. The The "An NDENDE methodology, methodology, such as eddy current current program description description in in LRA Sections A.2.1.15, A.3.1 A.3.1.15, .15, and B.1.16 will be revised testing (ECT), or other other similar inspection method to state state that eddy current current testing is the NDE method used by the Flux Thimble Tube Tube is used to monitor for wear of the flux thimble Inspection Inspection Program. The phrase "or similar inspection method" will be removed.
tubes. This program implements implements the the recommendations recommendations of NRC NRC Bulletin 88 09, Thimble Thimble Clarification to be incorporated Clarification incorporated into the LRA.
m:~.:"ffill'~-;;-;-:~'~'.;',~<:::'.-.,':'~~5~~~i~u"t0\b,fu-.MMiisi!di&'i<lliiJ%i~ru*,h-:-::..,,':.¥M;;:<<:<-'Xh.::[0h ""h:'~" ..::::,;:.~::::-~'C'r::;:':';.'~.:::'::'tIT:,~:":~"",~~l~~~g~'lm:t~#\":l;;~:.t',~q;m;~rul::~::::'o..'1tm..~~:::::t.::tt;}.f<*~:~t::';1.1 Tuesday, March Tuesday, March 18, 2008Amm Page 12 of 48 Page
Item Request Request Response Tube Thinning in inWestinghouse Reactors."
Westinghouse Reactors."
Discuss what what other other similar inspection method is is used for monitoring monitoring the wear of flux thimble tubes for IP2 and IP3.
IP3. How does this method method compare with the ECT, ECT, as recommended recommended in in GALL?
GALL?
51 AMP AMP B.1.16-2 (Flux (Flux Thimble Tube Inspection) measurements from the last performance
- a. For IP2, the measurements performance will be trended with the the next scheduled wear wear rate measurement. While IP2 compares compares measured measured values in in LRA AMP AMP B.1.6 B.1.6 includes three three enhancements enhancements to enhancement to Element practice, the enhancement Element 55 will formalize formalize the process. For IP3, wear be implemented implemented prior to the period of extended measurements are trended per Attachment 1, measurements 1, Section 6.0 of procedure procedure THI-002-RVI operation for GALL consistency consistency in program where each tube inspection is recorded recorded on datasheets datasheets and a permanent permanent strip chart elements "Monitoring and Trending," "Acceptance "Acceptance recording is made at the time of the inspection. Inspection results are recorded on a Criteria," and "Corrective Actions." in listed in table in THI-002-RVI. Wear in THI-002-RVI. examination frequencies Wear rates and examination frequencies are are calculated calculated per RE-ICI-910625 RE-ICI-91 0625 which states that 80% wear would occur during cycle cycle a.GALL "Monitoring and Trending" recommends: 24 for IP2. Wear Wear rates and examination examination frequencies calculated per IP-CALC frequencies are calculated IP-CALC "The wall thickness "The measurements will be trended thickness measurements 0038 which requires an eddy current inspection inspection prior to 3R16 for IP3. Changing Changing thethe and wear rates will be calculated. Examination Examination . baseline baseline of the exam frequency has not occurred occurred and the flux thimble tube design frequency will be based upon wear predictions predictions has has not changed.
changed. Therefore, existing activities are are consistent with the Flux Flux Thimble Thimble that have been technically technically justified as providing providing Tube Monitoring Monitoring Program attribute "Monitoring and and Trending" With enhancement with the enhancement conservative estimates of flux thimble conservative thimble tube wear. to better formalize formalize the process.
The interval interval between inspections will be between inspections be established such that no flux thimble tube tube is b. IP2 and IP3 have established acceptance criterion of 80%
established acceptance 80% through through wall (thimble (thimble predicted predicted to incur wear wear that exceeds exceeds the the tube wall thickness is not less less than 20% of initial wall thickness). Tubes with 80%
established acceptance criteria before before the next through wall wear shall be replacedreplaced or isolated. Thimble tubes with wear exceeding exceeding inspection. examination frequency inspection. The examination frequency may may bebe 40% through wall but projected to remain remain under 80% by the next inspection may be be adjusted based on plant specific wear projections. projections. repositioned after engineering evaluation. Thimble tubes with wear projected projected to Re baselining baselining of the examination examination frequency exceed exceed 80% by the next inspection inspection will be repositioned, replaced, or isolated.
repositioned, replaced, This isolated. This should be justified using plant specific wear wear rate rate is conservatively conservatively based on WCAP-1 WCAP-12866 2866 recommendations recommendations which include potential data unless prior acceptance prior plant specific NRC acceptance inaccuracies. IPEC responses in April 1989 to Bulletin 88-09 cited acceptance cited acceptance for the re baselining was received.
received. If If design criteria of 50%
50% for IP2 and 60% for IP3. As recommended by the Bulletin, Bulletin, the the changes are made to use more wear resistant resistant Westinghouse Westinghouse Owners Owners Group completed completed WCAP WCAP 1286612866 in 1991 which determined determined materials (e.g., chrome plated thimble tube materials that aa thimble thimble can safely remainremain in in service with up to 80% (includes (includes conservatism) conservatism) stainless steel) sufficient inspections will be be through through wall loss. The results of the WCAP were were adopted by IPEC in 1991. 1991. As As conducted conducted at an adequate adequate inspection inspection frequency, described described above, existing activities consistent with the Flux Thimble Tube activities are consistent Tube as described described above, for the new materials." Monitoring attribute "Acceptance Criteria". The enhancement enhancement is intended to Discuss Discuss how the stated enhancement enhancement in in the LRA formalize these formalize these activities.
satisfies the GALL satisfies the GALL for both IP2 for both IP2 and IP3.
and IP3.
- c. Flux thimble
- c. thimble tubes are isolated, withdrawn, repositioned, or isolated, capped, plugged, withdrawn, replaced when wall thickness is less than the minimum required.
- b. GALL "Accptance Criteria" recommends:
"Appropriate "Appropriate acceptance criteria such as percent IP2: During the Spring 2006 IP2 outage, all flux thimble tubes were were repositioned repositioned by by through through wall wear will be established. The The approximately two inches approximately inches as part part of a seal table modification.
modificatiori. Nine flux thimble tubes tubes acceptance acceptance criteria will be technically technically justified to to have been capped.
adequate margin provide an adequate margin of safety safety to ensure ensure that the integrity integrity of the reactor reactor coolant system IP3: Two Two flux thimbles have been capped as recommended recommended by calculation IP-CALC- IP-CALC-pressure boundary boundary is maintained.
maintained. The acceptance acceptance 07-0038.
criteria will include allowances for factors such as uncertainties in instrument uncertainty, uncertainties in wear scar These existing activities are consistent existing activities consistent with the Flux Thimble Tube Tube Monitoring Monitoring geometry, geometry, and otherother potential potential inaccuracies, inaccuracies, as as Program attribute attribute "Corrective Actions". The enhancement enhancement is intended intended to formalize applicable, to the inspection methodology chosen these activities.
for use in the program. Acceptance criteria criteria different from those previously documented documented in in NRC acceptance acceptance letters for the applicant=s applicant=s response to Bulletin 88 09 and amendments amendments thereto should thereto should be be justified."
justified." Discuss Discuss how how the the stated enhancement enhancement in the LRA satisfies satisfies the the GALL for both IP2 and IP3.
- c. GALL "Corrective Actions" recommends:
recommends: "Flux thimble tube wall thickness which do not meet the the established acceptance criteria must be isolated, capped, plugged, plugged, withdrawn, replaced, or otherwise removed from service in in a manner manner that that ensures the integrity integrity of the reactor coolant coolant system pressure pressure boundary is maintained. Analyses may allow repositioning of flux thimble thimble tubes that are approaching approaching the acceptance acceptance criteria limit.
Repositioning Repositioning of a tube exposes aa different different portion of the tube to the discontinuity that is causing the the wear." Discuss how how the stated enhancement enhancement in the the
<**," ",:~",*~~m~mmmm;;m~lW:~
Tuesday, March 18, 2008 Tuesday, March Page Page 13 130'48 of 4d
Item Request Response LRA satisfies the GALL for for both IP2 andand IP3.
52 AMP B.1.17 B.1.17-1-1 (Heat Exchanger Exchanger Monitoring)
Monitoring) (a) This program program is only credited to manage the aging aging effect of loss of material material duedue to wear. The existing site eddy current heat exchanger inspection inspection program includes includes The staff compared the enhancements to the the safety-related nonsafety-related heat exchangers. Eddy current inspections safety-related and nonsafety-related inspections of Scope of Program Program with the specific specific AMR line items items safety-related heat Generic Letter 89-13 safety-related heat exchangers exchangers cooled by service water are in LRA Sections 3.2 and 3.3 that credit AMP AMP included as part of the Service Water Water Integrity Integrity Program. The existing heat Exchanger Monitoring. A total of 14 B.1.17 - Heat Exchanger exchanger inspections on IP2 and exchanger eddy current inspections and IP3 are detailed detailed in Appendix 1 and 2 AMR line item entries were located, located. all identified of procedure procedure IP3-RPT-UNSPEC-03499.
IP3-RPT-UNSPEC-03499. The only heat exchangers exchangers currently "Heat Exchanger only as "Heat Exchanger -- Tubes". TheseThese included included in the existing program are are the IP3 instrument instrument air heat exchangers exchangers SWN occurred under the occurred under following systems:
the following systems: CLC 31/32 HTX that were inadvertently inadvertently listed as needing added to the needing to be added the program as part of the enhancement. The existing program program will be continued continued into the the Table 3.2.2-1-1P2 RHR (1 Table 3.2.2-1-IP2 (1 line item) item) period of extended extended operation with enhancements.
Table Table 3.2.2-1-1P3 3.2.2-1-IP3 RHR (1 (1 line item) item)
Table 3.2.2-4-1P2 Table Safety Injection 3.2.2-4-IP2 Safety (1 line item)
Injection (1 item) 3.2.2-1-IP2 RHR I/ RHR heat exchangers (b) Table 3.2.2-1-1P2 exchangers (IP2 - 21/22RRHX) 21/22RRHX)
Table 3.2.2-4-1P3 3.2.2-4-IP3 Safety Safety Injection (1 line item)
Injection (1 item)
Table 3.3.2-2-1P3 3.3.2-2-IP3 Service Service Water (1 (1 line item) Table 3.2.2-1-1P3 RHR /I RHR heat exchangers Table 3.2.2-1-IP3 exchangers (IP3 (IP3 - ACAHRS1/2)
ACAHRS1/2)
Table 3.3.2-3-1P2 3.3.2-3-IP2 Component Component Cooling Water Water (2 line items) items) 3.2.2-4-1P2 Safety Injection Table 3.2.2-4-IP2 Injection /I safety injection injection pump lube oil heat exchangers exchangers Table 3.3.2-3-1P3 3.3.2-3-IP3 Component Cooling Water Water (2 (IP2 - CCW-HTEX-WCLR-1009/1010/101 CCW-HTEX-WCLR-1 009/1 01 0/1011) 1) line items)
Table 3.3.2-6-1P2 3.3.2-6-IP2 Chemical & & Volume Control Control (2 Table 3.2.2-4-1P3 3.2.2-4-IP3 Safety Injection Injection /I safety injection injection pump lube oil heat exchangers exchangers line items) (IP3 - SISP31/32/33 (IP3 SISP31/32/33 OC HTX). HTX),
Table 3.3.2-6-1P3 3.3.2-6-IP3 Chemical Chemical & Volume Control (2 line items) items) Table 3.3.2-2-1P3 Service Table 3.3.2-2-IP3 Service Water/The Water !The line line item in Table 3.3.2.2 IP3 Service Service Water Table 3.3.2-16-1P2 3.3.2-16-IP2 SBO/App. R Diesel Generator Generator refers to the IP3 instrument instrument air heat exchangers SWN CLC 31/32 HTX. The The (1
(1 line item) item) inclusion of this heat heat exchanger exchanger as part of the enhancement enhancement is an error sincesince these these exchangers are in the existing heat exchangers existing eddy current current inspection inspection program.
The staff staff could not correlate correlate the scope program, scope of program.
including the enhancements, including enhancements. with the AMR table table Table 3.3.2-3-1P2 Component Cooling Water 3.3.2-3-IP2 Component Water/I spent spent fuel pit heat exchangers exchangers entries; entries; and clarifications:
and requests the following clarifications: (21SFPHX), secondary (21SFPHX). secondary system system steam generator sample coolers (21/22/23/24 SGSC), waste gas compressor heat exchangers SGSC). exchangers (21/22 WGCSWC)
(a) Identify Identify the specific component inspections component inspections currently currently included in the existing existing program that are Table 3.3.2-3-1P3 3.3.2-3-IP3 Component Component Cooling Water /I spent fuel pit heat exchangers exchangers credited for license license renewal. (ACAHSF1),
(ACAHSF1). secondary system steam generator generator sample coolers coolers (SGBDS-31/32/32/34HX), waste gas compressor 31/32/32/34HX). compressor heat exchangers (WD-WGC-31/32HTX) exchangers (WD-WGC-31/32HTX)
(b)
(b) Correlate the 14 AMR table entries identified identified above above with the specific component indpections specific component inspections Table 3.3.2-6-1P2 3.3.2-6-IP2 Chemical Chemical & Volume Control /I non-regenerative non-regenerative heat exchangers exchangers included in the enhanced program.
included (IP2 - 21NRHX).
21NRHX), charging pump seal seal water heat heat exchangers exchangers (IP2 (IP2 - 2iSWHX),
21SWHX).
charging pump pump fluid drive coolers (IP2 (1P2 - 21/22/23CHPFCA),
21/22/23CHPFCA). charging pump charging pump crankcase oil cooler (IP2 - 21/22/23CHPFCB) crankcase Table 3.3.2-6-1P3 3.3.2-6-IP3 Chemical Chemical & Volume Control I/ non-regenerative non-regenerative heat exchangers exchangers (IP3 CSAHNRT), charging pump seal water heat (IP3 - CSAHNRT). heat exchangers exchangers (IP3 - CSAHSW1).
CSAHSW1),
charging charging pump fluid drive coolers (IP3 -- CHRG CHRG PP31/32/33 PP31/32/33 CASING HTX), HTX).
charging charging pump crankcase oil cooler (IP3 - CHRG PP31/32/33 PP31/32/33 CRANK HTX)
Table 3.3.2-16-IP2 3.3.2-16-1P2 SBO/App. R Diesel Generator Generator /I SBO/Appendix SBO/Appendix R diesel jacket water heat exchanger exchanger (ARDG-JWHX) .
Information to be incorporated Information incorporated into the LRA.
The charging pump crankcase oil coolers coolers were inadvertently inadvertently omitted omitted from the scopescope of heat exchangers to be included heat exchangers included in the program program and the IP3 instrument air heat exchangers SWN SWN CLC 31/32 HTX are already included in already included in the existing program and and should not be part of the enhancement enhancement 53 AMP B.1.17-2 B.1.17 -2 (Heat Exchanger Monitoring)
(Heat Exchanger Monitoring) The wear that is identified identified by this aging effect is wear (fretting)
(fretting) on the outside of the the tubes due due to contact between the tubes and the tube support plates. It It is not The staff noted noted that all AMR table entries identify expected that this will occur but is conservatively conservatively identified as an agingaging effect effect "Loss of Material Material - Wear" Wear" as the aging effect being being requiring management. The wear could be caused by vibration of the tube as a managed. Is this wear induced by flow through through result of high flows or excessive rel?ult clearance between excessive clearance between the tube and tube support and/or and/or over over the heat exchanger exchanger tubes? Does Does the the plate. Wear resulting from abrasive fluid at high velocity is not expected expected in in the heat wear result from abrasive abrasive fluid at high velocity or exchangers included in this program exchangers program due to the controlled controlled water water chemistry chemistry of the the from flow-induced flow-induced vibration of the tubes? process fluids on the shell and tube sides.
54 54 AMP B.1.17-3 (Heat AMP B.1.17-3 Exchanger Monitoring)
(Heat Exchanger Monitoring) All of the heat exchangers in in the existing existing eddy eddy current inspection inspection program are large large enough such that eddy current current inspection can be performed.
performed. Visual inspection of Under "Parameters Under "Parameters Monitored Monitored or or Inspected".
Inspected", an an ID of heat exchanger the 10 exchanger tubes in in the existing existing program is not routinely performed.
"enhancement" "enhancement" to to the the existing program is existing program to is to Some of the new new heat exchangers exchangers added by the enhancement enhancement are small enough specify visual specify visual inspection where non-destructive inspection where non-destructive such that eddy current inspection may may not be possible necessitating visual possible necessitating Tuesday, March 18, 2008 Page 14 of 48
Item Request Response examination, examination, such as eddy current testing, is not inspection.
inspection.
possible. In In the existing program, program, what is currently currently done if eddy current testing is not possible? possible?
55 AMP B.1.17-4 (Heat Exchanger Exchanger Monitoring) Monitoring) Depending on the size Depending size of the heat exchanger, exchanger, tube configuration, and tube size, a remote visual inspection of the tubes may be required if if eddy current examination of Describe the details details of the visual inspection inspection the tubes is impractical.
impractical. Remote visual inspection inspection may be performed performed by means of a techniques techniques to be employed. employed. Does this include include fiberscope inserted through the tubes, or on the tube exterior from the shell side. As remote visual inspection inspection of the inside inside of the the specified in the enhancement acceptance criteria attribute, appropriate enhancement for the acceptance appropriate tubes?
tubes? What What specific acceptance acceptance criteria are procedures will be revised to establish procedures acceptance criteria for heat exchangers establish acceptance exchangers applied applied to visual inspection? Compare this to the the visually inspected unacceptable signs of degradation.
inspected to include no unacceptable identified degradation. This is identified acceptance acceptance criteria applied to eddy eddy current testing. as commitment #10. #10. The eddy eddy current current tests have aa minimum acceptable acceptable tube wall thickness acceptance acceptance criterion, which is determined determined by engineering engineering evaluation on a heat exchanger-specific exchanger-specific basis.
56 AMP AMP B.1.17-5 (Heat Exchanger Exchanger Monitoring) Monitoring) This AMP manages the aging effect of loss of material due to wear wear for the tubes in in the heat exchangers exchangers listed under the enhancement enhancement for the scope of the program.
Do any of the heat heat exchangers exchangers included included inin the the The tubes in in the other heat exchangers exchangers currently in in this program program are eddy current scope of this AMP come come under the jurisdiction of tested to detect loss of material. exchangers are classified material. Some heat exchangers classified as lSI ISI Class Class ASME ASME Code Section III IIIand Section XI? If If yes, 1, 2, and 3 and 1, and are subject to the requirements of ASME Section XI inservice inservice identify the specific heat exchangers and discuss inspection repair / replacement inspection and repair! replacement requirements associated with the pressure requirements associated pressure how the Section Section Xl XI requirements for inspection inspection are are boundary. Repairs or modifications modifications to heat exchangers exchangers will comply with the design design satisfied by this AMP. code(s) of record (ASME Section III and!or and/or ASME Section VIII, VIII, as applicable).
applicable). TheThe heat exchanger exchanger monitoring monitoring program program does not implement implement any of these repair! repair/
replacement or inspection activities.
activities.
57 AMP B.1.18-1 (Inservice Inspection) Inspection) Entergy described (a) Entergy described the Inservice Inservice Inspection (AMP B.1.18) Program as a plant-specific specific program program rather than comparing to the corresponding corresponding NUREG-1 NUREG-1801 801 LRA AMP B.1.18, Program Program Description states: programs (XI.M1 and XI.S3) because because the NUREG-1801 NUREG-1801 programsprograms contain many The Inservice Inservice InspectionInspection (ISI) Program is an (lSI) Program ASME ASME Section Section XI Xl table and section numbers which change change with different different editions of existing program program that encompasses encompasses ASME ASME the code. Because Because of this, comparison with the NUREG-1801 programs generates theNUREG-1801 generatesSection XI, XI, Subsections Subsections IWA, IWA, IWB, IWB, IWC, IWC, IWD IWD and many exceptions exceptions and explanations explanations which detract detract from the objective of the the requirements at GALL IWF requirements GALL AMP XI.M1 imposes comparison. The CLB requires that IPEC follow the version of ASME ASME Section XI XI requirements for Subsections Subsections IWB, IWC, and IWD IWB, IWC, IWD referenced in 10CFR50.55(a) referenced 10CFR50.55(a) and approved approved for use at IPEC. As this is the case, the the for Class 1, 1, 2, and 33 pressure retaining retaining Inservice Inspection Program is presented as a plant-specific program so it can be Inservice be components and their integral integral attachments.
attachments. judged on its own merit merit without the distraction distraction of numerous explanations explanations of Subsection Subsection IWA IWA describes general requirements requirements exceptions due due to differing code code editions.
associated associated with Subsections IWB, IWC, and IWD. IWD.
GALL AMP XI.S3 covers Inservice inspection inspection of Since the Inservice Inspection Program is a plant-specific Inservice Inspection plant-specific program, comparison comparison of Class 1, 1, 2, 3 and MC component supports for for the 10 elements with NUREG-1801 NUREG-1801 program program XI.S3 is not appropriate.
appropriate. Therefore, in in ASME piping and components addressed addressed in in the program basis document document (IP-RPT-06-LRD02, (IP-RPT-06-LRD02, available available for on-site review) review) the the Section XI, XI, Subsection Subsection IWF. IWF. The staff notes that attributes of the program are compared to the ten elements of an aging aging the 10 elementelement evaluation for the Subsection Subsection IWF IWF management program for license renewal as described management described in NUREG-1800, NUREG-1800, Table Table A.1-A.1-inspection inspection is is not not explicitly explicitly addressed addressed in in LRA AMPAMP 1. Additional information clarifying clarifying specific attributes attributes of the IWF portion of the ISI lSI B.1.18.
8.1.18. program is provided provided below.
(a) Provide a detailed detailed 10 element evaluation of the the Inspection Inspection methods, frequencies and sampling methods -- The ISI sampling methods lSI Program Program manages manages Subsection Subsection IWF inspection for Class 1, 2, 3 and and loss of material material for ASME ASME Class MC and Class 1, 2, and 3 piping and component component MC component supports supports and discuss any supports, anchorages, and base plates by visual examination examination of components components using using exceptions exceptions or enhancements enhancements when when assessed NDE techniques, frequencies, and and sample sample sizes in accordance with 10 in accordance 10 CFR CFR against against the recommendations recommendations in GALL GALL AMPAMP 50.55(a).
50.55(a).
XI.S3, AASME Section XI, Subsection Subsection IWF.
Specifically, discuss the inspection methods, their their Class 1 piping supports supports - visual (VT-3) - 25% of class 1. 1.
frequencies, frequencies, sampling sampling methods methods for for each class class of of Class 2 piping supports supports - visual (VT-3) -15%
- 15% of class 2.
supports, acceptance acceptance criteria, and operating operating Class 3 piping Supports Supports - visual (VT-3) - 10% 10% of class 3.
experience findings and their corrective corrective measures.
measures.
For Class 1, 1, 2 and 3 piping supports, the total percentage percentage sample shall be be (b) The attributes attributes of AMP B.1.18 B.1. 18 and GALL AMP AMP comprised comprised of supports supports from each system where the individual sample sizes are Xl. M1 are XI. are mostly identical identical and and consistent, consistent, except except proportional proportional to the total number of nonexempt nonexempt supports of each each type and function function AMP B.1.18 also includes includes the GALL AMP XI.S3 XI.S3 within each system.
for supports. Explain why Entergy categorizes categorizes AMP AM P B. B.1.18 1.18 to be plant specific. Supports Other than Piping Supports (Class 1,2, 1, 2, && 3 and MC)MC) - visual (VT-3)-
(VT-3) -
100% of the supports. For multiple components 100% components other than piping, within a system system of similar design, function, function, and service, service, the supports of only one of the multiple multiple components are required to be examined.
Acceptance Acceptance Criteria - Acceptance Acceptance standards examination evaluations, standards for examination repair evaluations, repair procedures, inservice inservice test requirements, requirements, and replacements for ASME Class MC and and Class 1, 2, and 3 piping and component supports are in accordance accordance with 10 10 CFR 50.55(a). The following conditions are unacceptable:
<ru~, ;'~ -: .~,:;%,~,~~ ='r*,~::,:,~~~jl4\tJ.,*llik,,;.;~",*:'.~:~*Will~mmm::l~',~M,"
Tuesday, Tuesday, March March 18, 2008 Page 15 of 48
Item Request Request Response deformations or (i) deformations or structural structural degradations degradations of of fasteners, fasteners, springs, clamps, clamps, or or other other support support items; .
(ii)
(ii) missing, detached, detached, or loosened loosened support support items; (iii)
(iii) arc arc strikes, strikes, weld weld spatter, spatter, paint, paint, scoring, scoring, roughness, roughness, or or general general corrosion corrosion on close close tolerance tolerance machined machined or or sliding sliding surfaces; surfaces; (iv) improper improper hot hot or or cold cold positions positions of spring spring supports supports and constant constant load load supports; (v)
(v) misalignment misalignment of of supports; (vi)
(vi) improper improper clearances clearances of of guides guides and stops.
Identification Identification of of unacceptable unacceptable conditions conditions triggers triggers an expansion expansion of the inspection the inspection scope, scope, and reexamination reexamination of the the supports supports requiring requiring corrective corrective actions actions during during the the next next inspection inspection period in accordance accordance with the the code.
code. Repair and and replacement replacement criteria criteria and and procedures procedures are also in accordanceaccordance with the code.
Operating Operating Experience Experience - ISI lSI examinations examinations at IP2 and and IP3IP3 were conducted conducted during during 2004 2004 and 2005. 2005. Results Results foundfound to be be outside outside of acceptable acceptable limits were were either either repaired, evaluated evaluated for for acceptance acceptance as is, or replacement activities were or replacement were initiated.
initiated.
Identification Identification of degradation degradation and performance performance of corrective corrective action prior prior to loss loss ofof intended function intended function are are indications indications that that the program program is effective effective for managing aging for managing aging effects.
effects. A self-assessment self-assessment of of the ISI lSI program program was was completed completed in October October 2004. 2004.
Review of scopescope for 2R16 (2004) and and 3R13 (2005) verified that the proper proper inspection percentages percentages had been planned for both outages. A follow-up assessment assessment was was heldheld for IP2 IP2 inin March March 20062006 to ensure that all inspection inspection activities required required to to close out the third 10-year out the 10-year lSI ISI interval were scheduled for 2R17 (2006). Confirmation were scheduled Confirmation of compliance compliance to program requirements requirements provides provides assurance assurance that the program will remain effective effective for managing managing loss of of material material of components. QA QA surveillances surveillances in 2005 and 2006 revealed revealed no issues issues or findings that could could impact effectiveness of the impact effectiveness the program.
(b) See (b) See response response to (a).
58 AMP B.1.18-2 B.1.18-2 (Inservice Inspection)
(Inservice Inspection) The Inservice Inservice Inspection Program Program uses nondestructive examination (NDE) nondestructive examination (NDE) techniques techniques to managemanage reduction of fracture fracture toughness toughness for valve valve bodies and pump pump LRA LRA AMP B.1.18, B. 1.18, "Scope of Program" states: "The casing mademade of of cast cast austenitic stainless steel.
ISI lSI Program also managesmanages reduction reduction of fracture fracture toughness for valve bodies and 'pump casing casing Since Code Case N-481 has been been approved approved in Regulatory Regulatory Guide 1.147, itit is part part of made Of of cast austenitic austenitic stainless steel. Both IP2 IP2 the ASME code and and need not be mentionedmentioned separately. Therefore, sentences sentences and IP3 IP3 use ASME Code Case N 481 as referencing referencing code case N-481 in LRA AMPs B.1.18 and B.1.37 will be removed removed from from approved approved in Regulatory Guide 1.147 for managing managing the LRA.
the effects of loss loss of fracture toughness due to thermal aging embrittlement embrittlement of CASS pump pump Clarification Clarification to be incorporated incorporated into the LRA.
casing pressure retaining welds. ASME Code Code Case Case N N 481 has been incorporated incorporated in in later editions editions of the code and IP2 will not reference reference Code Case N 481 in in the 4th interval."
Explain why a discussion of this specific code code case case is included.
59 AMP B.1.18-3 B.1.18-3 (Inservice Inspection)
Inspection) Neither IP2 IP2 nor IP3IP3 has plant-specific plant-specific operating operating experience experience with degradation of the the Lubrite sliding supports used used inin the steam generator and reactor coolant pump pump LRA AMP B.1.18, "Detection of Aging Effects" sliding supports.
sliding supports.
states: "The lSIISI Program will be revised to provide provide periodic inspections inspections to confirm the absenceabsence of As discussed in in EPRI Report Report 1002950, Aging Effects for Structures and Structural aging effects for lubrite sliding supports used in in (Structural Tools)
Components (Structural Tools) Revision 1, 1, Lubrite material material resists deformation, has the steam generator and reactor coolant pump aa low coefficient coefficient of friction, friction, resists resists softening softening at at elevated elevated temperatures, temperatures, absorbs grit grit supports." What has been the plant specific and abrasive particles, is not susceptible to corrosion, withstands high radiation, and operating experience with the degradation degradation of the the requires no requires no maintenance.
maintenance. An extensive search of industry operating operating experience did lubrite plates? not identify any instances instances of Lubrite plate degradation or failure to perform its intended function. Consequently, there int~nded there are no known aging effects that would lead intended function.
to a loss of intended Nevertheless, as described in Nevertheless, in LRA AMP B.1.18, the the lSI ISI Program will confirm confirm by by visual inspection the the absence of aging effects for the Lubrite used in in the the steam steam generator and reactor coolant coolant pumppump sliding supports supports through the period of extended operation.
Clarification to be incorporated into Clarification into the LRA.
LRA.
Commitment ## 11. 11.
60 B.1.18-4 (Inservice AMP B.1.18-4 (Inservice Inspection) The lSI ISI program will will continue continue to be implemented implemented in in full compliance compliance with with thethe
- ..-:mmmmilll.m'='<'i,m"\w'!mm':<<~w.~~C;-~~""*""""""'**""""""""""""~~.!ttli:~~'i2s.:%{,hlC;i':!i<ti:g~;eMo/"%mW'$'At'*\'~~t\1:;,".i::.~~c:':.;:*;:t:.' ~~VAX*-,V':~*:-:;-'::r:~:'-~:':11lli-~..k.~..z Tuesday, Tuesday, March March 18, 2008 Page 16 of48 Page of 48
Item Request Reauest Response requirements requirements of of 10 10 CFR 50.55a SO.SSa in effect effect at at the the beginning beginning of each each new new 1010 year year LRA AMP LRA AMP B.1.18, B.1.18, "Detection "Detection of AgingAging Effects" inspection inspection interval.
interval.
states: "Both states: "Both IP2IP2 and and IP3 havehave adopted adopted risk risk informed informed inservice inservice inspection inspection (RI (RI ISI) lSI) as as anan Letters detailing detailing RI-ISI RI-ISI for for IP2 IP2 and and IP3 IP3 category category B-FB-F and and B-J B-J welds and NRC welds and NRC alternative current ASME alternative to current ASME Section Section XI XI inspection inspection acceptance letters acceptance letters were were provided provided to the the auditor auditor for review.
review.
requirements requirements for for Class 1,1, Category Category B FF and and B JJ welds welds pursuant to 10 10 CFR 50.55a(a)(3)(i).
SO.SSa(a)(3)(i). The RI Since use use of of RI-ISI RI-ISI at IP2 IP2 andand IP3 has been IP3 has been approved approved pursuant pursuant to 1010 CFR CFR ISI lSI was developed developed in in accordance accordance with with the the EPRI 50.55a(a)(3)(i), RI-ISI SO.SSa(a)(3)(i), mentioned separately.
RI-ISI need not be mentioned separately. Therefore, reference to RI-Therefore, reference RI-methodology methodology contained contained in EPRIEPRI TR TR 112657, 1126S7, Rev. ISI lSI will be be deleted deleted from LRA AMP AMP B.1.18.
B.1.18.
B A, "Revised "Revised Risk Risk Informed Informed Inservice Inservice Inspection Inspection Evaluation Evaluation Procedure."
Procedu*re." The The risk informed informed Clarification to be incorporated Clarification incorporated into into the the LRA.
inspection locations are inspection locations are identified identified as as Category Category R A."
During the license During renewal period, will the ISI license renewal lSI program program be implemented implemented in in full full compliance compliance with the requirements requirements of 10 10 CFR 50.55a SO.SSa in effect effeCt at thethe beginning beginning of of each each new new 10 10 year year inspection inspection interval?
interval?
61 AMP B.1.18-5 8.1.18-S (Inservice (Inservice Inspection)
Inspection) ISI lSI results are are recorded recorded every operating operating cycle cycle and and provided provided to the the NRC NRC after after each each refueling refueling outage via Owner's Owner's Activity Reports. These These reports reports include include scope scope of LRA AMP AMP B.1.18, "Monitoring and Trending" inspection inspection andand significant significant inspection results.
inspection results.
states:
states: "ISI "lSI results results are recorded recorded everyevery operating operating cycle cycle and provided to the NRC after after each refueling refueling The ISI lSI program program will continue continue to be implemented implemented in in full compliance compliance with the the outage outage via Owner's Activity Reports. Reports. These These requirements requirements of 10 10 CFR CFR 50.55a SO.SSa in in effect at the beginning beginning of each each new new 1010 year year reports include scopescope of inspection inspection and significant significant inspection inspection interval.
interval.
inspection results. They are prepared inspection prepared and submitted submitted in accordance accordance with NRC accepted accepted Since Since Code Code Case N-532-1 N-S32-1 has been approved in in Regulatory Regulatory Guide 1.147, 1.147, it is part ASME ASME Section Section XI Code Case N S32 532 1 as as of the ASME ASME codecode and needneed notnot be mentioned mentioned separately. Therefore, Therefore, the sentence approved approved by RG 1.147." referencing referencing code case N-532-1 N-S32-1 in in LRA AMP B.1.18 will be removed from the LRA.
During the license license renewal renewal period, period, will the the lSIISI Clarification Clarification to be be incorporated incorporated into the LRA.
program be be implemented implemented in full compliance compliance with with the requirements of 10 CFR SO.SSa the requirements 50.55a in effect effect at thethe beginning of each new 10 year inspection inspection interval?
interval?
62 AMP B.1.19-1 (Masonry Walls) IE Bulletin 80-11, 80-11, Masonry Wall Wall Design, addressed the potentialpotential for problems with with the structural adequacy of concrete structural adequacy concrete masonry masonry walls in in proximity proximity to or with The applicant has identified an enhancement The applicant enhancement to attachments to safety-related safety-related piping or equipment. There are no masonry masonry walls in the Scope of Program, Program, as follows: "Revise "Revise IP1 intake structures which meet the classification intake structures classification of IE Bulletin 80-11. Thus, no Bulletin 80-11. no applicable procedures to specify that the IP1 seismic qualification qualification basis in accordance accordance with IE Bulletin Bulletin 80-11 has been developed developed intake structure is included included in the program."
program." The The masonry components for masonry components of IP1 intake structure.
LR intended function of the IP1 intake structure structure relates to protection of Appendix R R equipment, in in IP1 intake intake structure houses components required for the alternate safe shutdown shutdown accordance with 10 CFR S4.4(a)(3).
accordance 54.4(a)(3). The intent of system, which is credited in the Appendix R safe shutdown shutdown analysis. Accordingly, the GALL Masonry Wall AMP (XI.SS) (XI.S5) is to ensure the structure has license license renewal intended intended function for 10 CFR 54.4(a)(3)
S4.4(a)(3) since itit that a previously documented seismic qualification previously documented qualification provides support for equipment credited for regulations associated with fire fire in accordance basis, in accordance with IE Bulletin 80-11, 80-11, protection (10CFR protection (10CFR S0.48).
50.48).
remains valid through implementation implementation of the the guidance provided provided in in IN IN 87-67. Has a documented The scope of the GALL Masonry Masonry Wall AMP (XI.SS) (XI.S5) states: "The scope includes all qualification basis, in seismic qualification in accordance accordance with IE IE masonry walls identified as performing intended intended functions in in accordance accordance with 10 Bulletin 80-11, 80-11, been developed developed for the masonry 54.4."
CFR S4.4."
components of the IP1 1P1 intake structure? IfIfso, provide the documentation provide documentation at the audit. If not, then Consistent with scope of GALL Masonry Masonry Wall AMP (XI.SS),(XI.S5), and as described in in this AMP cannot be credited to manage manage aging for license renewal application B.1.19, Indian Point Point Energy Center (lPEC)(IPEC) Masonry Masonry Wall the extended period of operation. Program is an existing program that Program that manages manages aging effects of all masonry masonry wallswalls identified as identified as performing intended functions in performing intended in accordance with 10 accordance with 10 CFR CFR S4.4.
54.4.
Included components Included components are 10 10 CFR CFR S0.48-required 50.48-required masonry masonry walls.
walls.
The IPEC Masonry Wall Program, Program, with enhancement, enhancement, assures the effects of aging are managed such that IP1 IP1 intake intake structure will continue to perform perform its intended function through the period of of extended operation.
operation.
63 AMP B.1.22-1 AMP B.1.22-1 (Bolted (Bolted Cable Connections) inspection is an alternative Visual inspection alternative technique technique to thermography thermography or measuring measuring connection resistance of bolted connections connection connections that are covered with heat heat shrink shrink tape, GALL AMP XI.E6 states that testing testing may include include sleeving, insulating boots, etc.
sleeving, etc. where where the only alterative to visualvisual inspection is thermography, contact resistance testing, and destructive examination. This is the destructive the same same philosophy applied to to bolted connections connections appropriate testing methods. In other appropriate InAMP AMP in metal-enclosed bus.
in B.1.22, under Detection of of Aging Effect element, you have stated that inspection methods may may AMP B.1.22 AMP B.1.22 is a plant specific specific program proposed instead of of a program program that is include thermography, contact resistance testing, consistent with GALL XI.E6. Element 4, "Detection "Detection of Aging Effects," can be revised revised Tuesday, March 18, 2008 Page 17 of 48
Item Request Response or other other appropriate methods methods including visual as follows to clarify this statement.
based on plant configuration configuration and industry guidance.
guidance. Explain Explain how how visual inspection can A representative representative sample of electrical electrical connections within the scope of license license detect detect loosening of bolted bolted cable cable connections.connections. renewal, and subject to aging management review will be inspected inspected or tested prior prior to the period of extended extended operation to verifyverify there there are no aging effects requiring requiring management during during the period of extended operation. The factors considered considered for sample selection will be application application (medium and low voltage), circuit circuit loading (high (high loading), and location location (high temperature, high humidity, vibration, etc.). The The technical basis for the sample selected selected will be documented.
documented. Inspection Inspection methods may may include thermography, contact resistance testing, testing, or other appropriate appropriate methods methods including visual based on plant configuration and and industry guidance.
guidance. Visual inspection should be used instead of destructive inspection destructive examination examination when methods when other methods cannot be used. The The one-time inspection or testingtesting provides provides additional additional confirmation to support support industry industry operating experience experience that shows that electrical electrical connections have have experienced a high degree of failures, and that existing installation not experienced installation and and maintenance practices maintenance practices are effective.
See audit item #563 #563 for further further clarification.
Clarification to be incorporated into Clarification into the LRA.
Commitment # 14.
Commitment 14.
64 AMP B.1.24-1 (Instrumention (Instrumention Circuits Circuits Test Review) (a)Although (a)Although not explicitly listed, the high range range radiation monitoring cables were included included in in AMP B.1.24. The aging aging management management reviewreview included neutron neutron GALL AMP XI.E2 XI.E2 states that this program applies applies monitoring monitoring circuits and high range radiation monitoring monitoring circuits. Reference Reference high-range-radiation and neutron flux to high-range-radiation flux Attachment Attachment 33 of the electrical AMR report. The The program description for AMP B.1.24 B.1.24 monitoring monitoring instrumentation instrumentation cables in addition to uses the phrase (i.e., (i.e., neutron flux monitoring monitoring instrumentation). Since Since this waswas other cables used in high voltage, low level signal meant to be an example, example, the term "e.g." would have been a more term "e.g." more appropriate choice choice application application that are sensitive sensitive to reduction reduction IR. IR. In than .."i.e.".
i.e ....
AMP B.1.24, you only mention mention about neutron monitoring monitoring system system cables. cables. (b)During the IPA, the only high instrument instrument voltage circuits with low signal values.that values.that were not subject to aging management management review review were were the incore detectors detectors (a) Explain why high range range monitoring monitoring cables cables are and area radiation monitors. The The nonsafety-related nonsafety-related incore incore detectors detectors and the area not included included in the AMP B.1.24. radiation monitors do not perform aa license renewal intended intended function per 10 CFR 54.4(a)(1), (2), or (3). Therefore, Therefore, the incore detectors detectors and the area radiation radiation (b)
(b) List other cables used in in high voltage, low level monitors are not included included inin the scope scope of the B.1.24 B.1.24 (XI.E2) aging aging management management signal application.
application. Explain why these cables were were program.
not included included in in the scope of AMP B.1.24.
A change will be made to LRA LRA Section B.1.24 for clarification. recommended clarification. The recommended change is as follows.
follows.
The Non-EQ Non-EQ Instrumentation Instrumentation Circuits Test Review Program is a new program program that assures the intended functions of sensitive, high-voltage,high-voltage, low-signal low-signal cables exposed to adverse adverse localized equipmentequipment environments environments caused caused by heat, radiation and moisture; (i.e., neutron neutron flux monitoring instrumentation instrumentation and high range radiationradiation monitors); can be maintained maintained consistent with the current licensing basis through the the period of extended operation.
operation. Most sensitive sensitive instrumentation instrumentation circuit cables and and connections are included connections included in in the instrumentation instrumentation loop calibration at the normal calibration frequency, which calibration which provides sufficient sufficient indication of the need for corrective corrective actions based based on acceptance acceptance criteria criteria related to instrumentation instrumentation loop performance.
The review review of calibration calibration results will be performed performed once every ten years, with the first review occurring before the period review occurring period of extended extended operation.
instrumentation circuit cables For sensitive instrumentation cables that are disconnected during instrument calibrations, calibrations, testing using a proven method deterioration for the method for detecting deterioration the insulation system (such as insulation insulation resistance tests or time domain reflectometry) reflectometry) will occur at least every ten years, with the first test occurring occurring before the period of extended operation. In extended In accordance accordance with the corrective corrective action program, program, an engineering evaluation engineering evaluation will be performed performed when test acceptance acceptance criteria are not met and corrective corrective actions, including modified modified inspection inspection frequency, will be implemented to ensure that he intended functions of the cables cables can be maintained consistent consistent with the current licensing basis through the period of extended extended operation.
operation. This program program will consider consider the technical information information and guidance guidance provided in in NUREG/CR-5643, NUREG/CR-5643, IEEE Std. P1205, SAND96-0344, and 109619.
Clarification to be incorporated into the LRA.
65 AMP AMP B.1.25-1 (Insulated Cables and Connections) This program program addresses cables and connections connections under under the premise that a large large portion of cables and connections are accessible. This program program sample consists of You have stated that a representative representative sample sample of all accessible accessible cables and connections connections in localized adverse adverse environments.
environments. If Ifan accessible accessible insulated insulated cables cables and and connections connections condition or situation is identified unacceptable condition identified for a cable or connection connection during this this within the scope scope of license license renewal will be visually visually visual inspection, inspection, the corrective action process will be used for resolution.' resolution. As part of
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Tuesday, March Tuesday, March 18, 2008 Page 18 of 48 Page 180'48
Item Request Response the corrective action process a determination will be made as to whether the same inspected. Describe the technical basis for the corrective action process a determination will be made as to whether the same sampling and action taken if a degradation degradation was condition or situation is is applicable to to other cables or connections.
found on aa representative representative sample. sample.
The program program description for B.1.25 B.1.25 will be revised as follows.
AA representative sample of accessible insulated insulated cables and and connections connections within the scope of license renewal renewal will be visually inspected for cable and connection jacket surface anomalies anomalies such as embrittlement, discoloration, cracking or surface discoloration, cracking contamination.
contamination. The program sample consists of all accessible cables cables and connections in in localized adverse environments.
Clarification to be incorporated Clarification incorporated into the the LRA.
66 B.1.26-1 (Oil Analysis)
AMP B.1.26-1 The evaluation evaluation report was provided provided during the on-site audit. Based Based on the the report results, oil analysis frequencies were evaluated with recommended recommended actions. The LRA references aa June 2006 evaluation evaluation of oil evaluation resulted in evaluation in changes to the frequencies of some some oil analyses. However, analysis practices among among Entergy Entergy Northeast sites. these changes did not affect components components in in the scope of license renewal renewal thatthat Provide documentation documentation describing this evaluation credited the Oil Analysis Program for managing managing the effects of aging.
(e.g., report) and describe how the evaluation (e.g., report) impacted impacted oil analysis practices practices at Indian Indian Point. Point.
67 AMP AMP B.1.26-2 (Oil Analysis) The results results of oil analyses are reviewed by the predictive maintenance maintenance group to determine determine ifif oil is is suitable for continued use until the next scheduled sampling sampling or or Describe the process for reviewing reviewing oil analysis test scheduled scheduled oil change. Oil analysis data sheets are provided provided by an offsite vendor with results and how results how these reviews reviews ensure ensure that that current and historical historical analysis results. The data is is reviewed reviewed to evaluate unusualunusual unusual trends are identified and and alert levels have trends. When degraded degraded conditions are indicated, the predictive predictive maintenance maintenance group group not been reached or exceeded. exceeded. will take appropriate actions to check the validity of the data and and issue aa condition report with recommended corrective report corrective actions.
68 68 AMP B.1.26-3B.1.26-3 (Oil Analysis) Analysis) enhancements identified The enhancements identified for the Oil Analysis Program Program are not necessary necessary to to achieve consistency with the program program described in in the GALL report.
report. AsAs indicated in in The LRA LRA states that the lubricating oil analysis LRA Section LRA Section 8.1.26, B.1.26, two of enhancements involve adding of the four enhancements adding nonsafety-related program isisconsistent program consistent with with the program program described described components to the program that are not not covered in inthe existing program. The in GALL, in GALL, but but alsoalso identifies identifies six elements elements as as remaining two enhancements remaining enhancements involve involve formalizing formalizing in in procedures procedures actions that that are requiring enhancement to achieve this being informally performedperformed under the existing program. program. As As indicated in in the LRA, the consistency. Provide a more consistency. more detailed detailed description description existing lubricating oil monitoring activities are essentially the same as those of past and present lubricating oil monitoring monitoring specified specified in in the GALL report. A A matrix sampled components matrix outlining sampled components and activities at the Indian Indian Point site and the schedule frequencies frequencies will be available available forfor review during the on-site during the audit. Additionally, on-site audit. Additionally, pastpast oiloil implementation of enhancements to this AMP.
for implementation analysis data sheets will also be available showing historic test test results.
Enhancements will be implemented Enhancements implemented prior prior to the period period of extended extended operation.
69 B.1 .26-4 (Oil Analysis)
AMP B.1.26-4 Analysis) As As stated in in LRA Section B.1.26 exception note 1, 1, fuel dilution testing is performed is performed in lieu of flash point testing for lubricating in lubricating oil systems systems potentially potentially exposed to to In its In its description description of of the the exception exception to NUREG NUREG 1801 hydrocarbons. While itit is hydrocarbons. is important important from an an industrial industrial safety perspective perspective to monitor monitor Element 3, Element Parameters Monitored 3, Parameters Monitored or Inspected, flash point, it is is not related managing the effects of related to managing of aging. Analyses Analyses of of filter the LRA the LRA states that flash point has little residue or residue or particle count, count, viscosity, viscosity, total acid/base acid/base (neutralization (neutralization number),
number), waterwater significance with respect to the effects of aging. aging. content, fuel dilution, and metals metals content provide sufficient information information to verify the the Because flash point identifies the presence of Because is suitable for continued oil is continued use. IPEG IPEC performs performs a fuel dilution test in in lieu of flash volatile and flammable volatile flammable materials, an abnormally abnormally point testing on emergency emergency diesel generators and IP3 Appendix R diesel generators R diesel generator generator low flash point can be indicative of fuel . lubricating oils. There could be two factors that affect the flash point of the oil; the contamination. Provide a technical justification for addition of fuel that would lower lower the flash pointpoint or the addition of water water that would this exception. raise the flash point.
raise point. The fuel dilution test The fuel test determines determines the percent percent byby volume of of fuel fuel and the water content content test determines determines the percentpercent by volume volume of water. By By determining the percent by volume of determining of both fuel and water, the analysis can determine the expected determine expected change in in flashpoint.
f1ashpoint. For oil systems not associated with internal internal combustion combustion engines, lubricating oil flash point change change isis unlikely.
70 70 AMP AMP B.1.27-1 B.1.27-1 (One-Time(One-Time Inspection) For Indian Point For Indian Point Energy Energy Center Center UnitUnit 2 (IP2),
(1P2), the facility operating (DPR-26) operating license (DPR-26) expires at midnight September 28, 2013. For 28,2013. For Indian Point Energy Energy Center Center Unit 33 GALL recommends recommends that the applicant should (1P3),
(IP3), thethe facility facility operating operating license (DPR-64)(DPR-64) expires at midnight December December 12, 12, schedule the inspection no earlier than ten years 2015. Since Since the the commitment commitment is is being made within being made within the the ten years prior to the period prior to prior to the the period period of of extended operation. operation. The LRA LRA of extended extended operation, operation, the statement statement that the inspection will be performed prior to to states that states that the the inspection inspection will will be be performed performed prior prior to to the period period of extended operation is is appropriate appropriate and need not be changed.
the period period of of extended extended operation. operation. The statement statement should be should be revised revised to to imply imply that that the inspection inspection will be performed performed with in in the 10 years period prior to to the period of extended operation.
71 71 AMP B.1.27-2 (One-Time (One-Time Inspection) Inspection) Consistent with NUREG-1801, NUREG-1 801, XI.M32 each inspection activity includes a
,~'~i:<*i"*:\:;: *'.:;'::"~S::.:f~::;m:;:'~"~":-~~)<;\~"~:l:r:'.~:t~'Th::.""'m'ir.t~~~~r::$".L)'::'~:'?:"l£. ,:'~,::,:,:~>:\:::~':': ::m:~~;:,:<,~?,;,~M1:WS.-~
Tuesday, March 18, Tuesday, 18, 20082008Pae1of4 Page 19 of48 Page ot48
Item Request Response representative sample of the material and environment representative environment population, and, where where The The LRALRA states representative sample states that the representative sample practical, focuses on the components components most susceptible susceptible to aging due to time in in size will be based based on Chapter 4 of EPRI document service and severity severity of operating conditions. Also, the program provides operating conditions. provides for for 107514, 107514, which outlinesoutlines a method to determinedetermine the the increasing increasing the inspection inspection sample size and locations locations ifif aging effects effects are detected.
detected.
number of inspections required required for 90%
confidence that 90% 90% of the population population does not EPRI EPRI Report 107514, Age Related Related Degradation Degradation Inspection Method and experience degradation.
experience degradation. Justify Justify how this sampling Demonstration, describes Demonstration, describes methods used to inspect for age related degradation degradation technique with 90% 90% confidence level level provides provides an an during the period extended operation. As stated period of extended sta\ed in this report, one one key feature feature of effective aging management effective management program with applying applying the 90% confidenceconfidence level is the assumptionassumption that none of the inspected adequate assurance adequate assurance that the applicable applicable items will contain contain significant significant aging aging effects. Consequently, Consequently, ififa single item in the the components will continue to perform their intended sample population population has an aging mechanism of interest, the sample size is increased increased functions through the period of extended extended operation. which will raise the confidence confidence level level to greater greater than 90%.
With a combination of proven proven statistical sampling, sampling, focus on susceptiblesusceptible locations, locations, and a mechanism for increasing increasing the sample size, the One-Time One-Time Inspection Inspection Program provides adequate provides adequate assurance assurance that the applicableapplicable components components will continue to perform perform their intended function through the period of extended extended operation.
72 AMP B.1.27-3 B.1.27-3 (One-Time (One-Time Inspection)
Inspection) Monitoring -- A representative B.1.9 Diesel Fuel Monitoring representative sample of susceptible susceptible components components of each material and environmentenvironment crediting the diesel fuel monitoring monitoring program for for What is the specific scope of AMP B.1.27 One One aging management management will be inspected using nondestructive using combinations of nondestructive Time Inspection that will be implementedimplemented to verify examinations examinations (including VT-1, VT-1, ultrasonic, and surface surface techniques) performed by by effectiveness of each of the following AMPs:
the effectiveness qualified qualified personnel personnel following procedures procedures that are consistentconsistent with Section Xl XI of ASME ASME B.1.9, B.1.9, B.1.26, B.1.39, and B.1.40? B.1.40? B&PV Code and 10CFR50, Appendix Appendix B to verify the absence absence of significant corrosion corrosion or fouling.
fouling.
representative sample of susceptible components B.1.26 Oil Analysis - A representative components of each material material and environment crediting the oil analysis analysis program program for aging managementmanagement will be inspected using combinations combinations of nondestructive nondestructive examinations examinations (including VT-1, ultrasonic, and surface techniques) performed performed by qualified qualified personnel following following procedures that are consistent with Section Section XI Xl of ASME B&PV Code and 10CFR50, 10CFR50, Appendix Appendix B to verify the absence absence of significant corrosion corrosion or fouling.
B.1.39, B.1.40 and B.1.41 B.1.41 Water Chemistry Programs Programs -
A representative sample sample of susceptible components of each material and susceptible components and environment environment crediting a water chemistry program for aging management management will be be combinations of nondestructive inspected using combinations nondestructive examinations examinations (including (including VT-1,VT -1, ultrasonic, and surfacesurface techniques) performed by qualified personnel following following procedures that are consistentconsistent with Section Section XI Xl of ASME B&PV B&PV Code and 1 OCFR50, 10CFR50, Appendix Appendix B to verify the absence significant cracking, absence of significant cracking, corrosion or fouling.
73 AMP B.1.28-1 (One-Time Small Bore Bore Piping) Inspections performed Inspections performed to date at IP2 and IP3 IP3 have not found cracking of ASME ASME Code Class 1 small-bore small-bore piping.
According According to GALL, AMP XI.M35, this program program is applicable only to plants that have have not experienced cracking of ASME Code Class 1 experienced small-bore piping resulting from stress corrosion corrosion or thermal and mechanical loading. Justify Justify that both IP2 and IP3 meet this criteria.
74 AMP B.1.28-2 AMP B.1.28-2 (One-Time (One-Time Small Small Bore Piping) (a) As stated in in LRA Section B.1.28, the One-Time Inspection - Small Bore Piping One-Time Inspection Piping program will be consistent with NUREG-1801 XI.M35. The program will include program include a In the Scope section of XI.M35, GALL GALL states that sample selected selected based on susceptibility, inspectability, dose considerations, considerations, the One-Time Inspection program for ASME Code Code operating operating experience, experience, and limiting locations locations of the total population population of ASME Code Code Class 1 small-bore small-bore piping includes locations locations that Class 1 small bore piping locations. EPRI Report 1000701, 1000701, "Interim Thermal are susceptible susceptible to cracking.
cracking. The GALL also states states Fatigue Fatigue Management Management Guideline (MRP-24)," (MRP-24)," JanuaryJanuary 2001,2001, or subsequent subsequent revisionsrevisions that guidelines for identifying piping susceptible to to of this industry guidance, guidance, will be followed for identifying susceptible locations for potential potential effects effects of thermal stratification or thermal stratification or inspection.
inspection.
turbulent penetration penetration are provided provided in EPRI Report (b) See response to (a).
1000701, "Interim 1000701, "Interim Thermal Thermal Fatigue Management Fatigue Management Guideline Guideline (MRP-24)," January January 2001.2001.
(a) Will this newnew program to be implemented implemented by Indian Point follow the guidelines guidelines of EPRI Report 1000701 for identifying 1000701 identifying the susceptible susceptible locations locations for inspection?
inspection?
(b) If If Indian Point One-Time One-Time Inspection Program will not utilize utilize the guidelines of the above EPRI Report, what criteria will be used for identification identification of susceptible locations?
locations? Also justify that this this mmm:mrX,~i:~;':\~~~n::::::":!I':%'~>r:l'~~":::;,lm::,,'~~,:,';';,~;:;~'<~lv.."':~:M&~~::::;:":i~;:Y, "Q"~~'m<@.1ml~:,~tr,m1:','::<:"*\%::C::,':, ,';:::'~~~<<;:.>:*t:':':l"~':<~~~'~imt.~':lZ';l~;3:_':-,' -:-,::~~
Tuesday, March Tuesday, March 18, 2008 Page Page 20 of of 48
Item Request Response criteria will be equivalent equivalent to the EPRI EPRI guidelines.
75 AMP B.1.29-1 (PSPM) As shown in LRA Section Section B.1.29, many of the Periodic Surveillance and Preventive Preventive Maintenance Program activities Maintenance activities include visual or other non-destructive non-destructive examinations examinations What What codes and and standards standards are used to implement implement of structures, structures, systems, and components. These examinations are These examinations performed in are performed in the Periodic Surveillance Surveillance and Preventive Preventive accordance with approved accordance approved procedures consistent with manufacturers' manufacturers' Maintenance Program?
Maintenance Program? What acceptance acceptance criteria criteria recommendations. The acceptance recommendations. acceptance criteria, which are specified specified in in the program are used during the implementation implementation of this this document (Attachment 2, IP-RPT-06-LRD07),
basis document IP-RPT-06-LRD07), and will be included in in plant plant program and where program where are the acceptance acceptance criteria criteria procedures.
defined?
defined?
76 76 AMP B.1.29-2 (PSPM) (PSPM) Reactor Reactor building crane structural steel girders used in load handling are inspected load handling inspected under the Periodic Surveillance under Surveillance and Preventive Preventive MaintenanceMaintenance (PSPM) Program The program program description for the Periodic Periodic identified in identified in Section B.1.29 of the application. application. This program program includes visual Surveillance Surveillance and preventive preventive Maintenance Maintenance program program inspections of the crane rails and inspections and girders consistent with XI.M23 to manage manage loss of implies that this AMP will be used to manage manage loss loss material. The acceptance acceptance criteria in in the PSPM PSPM Program Program are "No significant significant corrosion of material for carbon steel components components of the the or wear." The XI.M23 acceptance acceptance criteria states, "Any significant significant visual indication of cranes, crane crane rails, and girders. girders. GALL includes includes loss of material due to corrosion corrosion or wear is evaluated evaluated according to applicable applicable AMP XI.M23, Inspection of Heavy Load and and LightLight industry industry standards standards and good industry industry practice.", PSPM monitoring effectiveness effectiveness and and Load Handling Systems, to manage manage these these degrading trends are documented degrading documented in accordance accordance with 10CFR50 10CFR50 Appendix B. B.
components. Describe Describe if if the activities of the the Therefore Therefore the aging aging management management activities activities for crane rails and girders under the the Indian Point AMP B.1.29 are consistent with the the above above two programs programs are consistent with the attributes described for the program program in in recommendations recommendations of the GALL AMP XI.M23. NUREG-1801 X NUREG-1801 I.M23 during the period of extended operation.
XI.M23 operation.
Provide Provide aa justification justification for the activities that are not not*
consistent.
77 AMP B.1.29-3B.1.29-3 (PSPM) (PSPM) The XI.M38 XI.M38 program program consists of visual inspections inspections of the internal surfaces surfaces of steel piping, piping components, ducting, and and other components exposed to environments other components environments The program description description for the Periodic Periodic such as condensation condensation and indoor air that are not covered covered by other aging Surveillance Surveillance and preventive preventive Maintenance Maintenance program management programs.
management programs.
implies implies that this AMP will be used to manage manage loss loss The PSPM program performs performs internal visual inspections during maintenance maintenance of material material for internal surfaces surfaces of piping, valves, activities. These inspections inspections provide provide timely detection of degradation degradation by confirming confirming ducting ducting and other piping components. GALL the integrity integrity of the internal internal component surface. Visual inspections inspections are performed performed by by includes includes AMP XI.M38, XI.M38, Inspection of Internal Intemal personnel qualified in in accordance with site procedures. procedures. Inspection intervals are surfaces miscellaneous Piping and Ducting surfaces in miscellaneous dependent dependent on component component material material and environment. Acceptance Acceptance criteria criteria include no no Components, Components, to manage manage these components. significant significant loss of material or fouling. fouling. Unacceptable Unacceptable conditions conditions and degrading trends trends Describe if if the activities of the Indian Point AMP AMP are documented in accordance accordance with 11OCFR50 OCFR50 Appendix B.
B.1.29 are consistent with the recommendations B.1.29 recommendations Aging management management activities for intemal internal steel piping, piping components, and of the GALL AMP XI.M38. XI.M38. Provide Provide a justification justification ducting ducting includedincluded in in the Periodic Surveillance Surveillance and and Preventive Maintenance Maintenance program program for the activities activities that are not consistent. are consistent with the attributes described described for the program in NUREG-1801 NUREG-1 801 XI.M38.
78 AMP AMP B.1.29-4 (PSPM) The representative representative sample size size used for the Periodic Surveillance Surveillance and Preventive Preventive Maintenance (PSPM) Program is consistent with the sample size discussion for the Maintenance the In the "Evaluation" section section of the AMP, the LRA One-time Inspection Program per NUREG-1801, NUREG-1801, XI.M32. Periodic Periodic inspection states that the representativerepresentative sample size will be be activities include include a representative representative sample of the material and environment environment based on Chapter Chapter 4 of EPRI document 107514, EPRI document population, and, population, and, wherewhere practical, practical, focus on the components most susceptible to aging which which outlines outlines a method to determine determine the number due to time in in service and and severity severity of operatingoperating conditions.
conditions. The representative representative of inspections required required for 90% confidence confidence that that sample size provides 90% confidence confidence that 90% 90% of the population does does not 90% of the population does not experience experience experience degradation.
experience degradation.
degradation. Justify how this sampling sampling techniquetechnique with 90% confidence confidence level provides an effective effective EPRI ReportReport 107514, Age Related Degradation Degradation Inspection Inspection Method Method and management program aging management program with adequate Demonstration, Demonstration, describes describes methods methods used to inspect for age related degradation degradation assurance that the applicable assurance applicable components will during the period of extended extended operation. As stated in in this report, one key feature of continue to perform their intended functions functions applying the 90% confidence applying confidence level is the assumption that none of the inspected inspected through the period of extended extended operation. items will contain significant aging contain significant aging effects. Consequently, if a single item in the the sample population has an aging mechanism mechanism of interest, the sample sample size is increased which will raise the confidence confidence level to greater greater than 90%.
With a combination of proven proven statistical sampling, sampling, focus on susceptible susceptible locations, and a mechanism for increasing the sample size, the PSPM program program provides more more than adequate adequate assurance assurance that the applicable applicable components will continue to perform their intended function through the period of extended extended operation.
79 AMP B.1.29-5 B.1.29-5 (PSPM) The Periodic Surveillance Surveillance and Preventive Preventive Maintenance Program Program manages the aging aging effects effects of cracking, cracking, change change in in material properties, and fouling on external external surfaces.
The program description description for the Periodic Periodic Management of loss of material on external surfaces Management surfaces of some some select select carbon steel Surveillance and preventive preventive Maintenance Maintenance program surfaces surfaces is is also also managed managed by by the PSPM program.
the PSPM program.
implies that this AMP will be used to manage loss loss of material material for external surfaces surfaces of steel Aging management management activities for external external surface monitoring monitoring of steel piping, piping components. GALL includes AMP XI.M36, components included included in the Periodic Surveillance and Preventive Preventive Maintenance Maintenance External Surfaces Monitoring, Monitoring, to manage manage these these program are consistent consistent with the attributes attributes described for the program in in NUREG-NUREG-
~!'?::t0' Page 21 of 48
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Item Reauest Request Response components.
components. Describe Describe if the activitiesactivities of the the 1801 1801 XI.M36.
Indian Point AMP B.1.29 are consistent consistent with the the recommendations of the GALL recommendations GALL AMP XI.M36.
Provide a justification for the activities activities that are not consistent.
80 AMP B.1.29-6 (PSPM) Systems within the scope of the PSPM program are monitored monitored throughthrough system engineering activities per site procedures. Results from monitoring engineering monitoring activities are are Explain how how is the "Monitoring and Trending" evaluated against acceptance acceptance criteria and and trends are developed developed by comparing (element 5 of Evaluation Basis) accomplished accomplished in in current results to previous results to predict predict degradation degradation rates. These predictions predictions implementing Indian Point AMP B.1.29.
implementing are used to confirm that loss of component intended function will not occur prior to the next scheduled scheduled inspection.
inspection. Trend data from these activities is used to revise revise inspection frequencies frequencies per the site preventive maintenance processes.
preventive maintenance All degrading degrading trends will be documented documented per the IPEC Corrective Corrective Action Program in accordance with 10CFR50 10CFR50 Appendix B. B.
81 AMP B.1.30-1 (Reactor Head Closure Studs) Results of testing shown on available test reports for the actual actual reactor head closure closure stud and nut materialmaterial showed an average measured tensile strength value for each Discuss additional information information (e.g., results of heat number < 170ksi. 170ksi.
testing testing on the actual stud and nut material) material) to to substantiate that the maximum maximum tensile tensile strength of Documentation of available available test results were provided provided for on-site review.
the reactor closure studs and nuts is less than 170 170 ksi.
82 AMP B.1.30-2 B. 1.30-2 (Reactor Head Closure Studs) The following passage passage of NUREG-1801AMP NUREG-1801AMP XI.M3 XI.M3 program element "Detection of Aging Effects" appears to be incorrect incorrect because because ASME Section Section XI, Xl, Code Edition Code Edition LRA AMP B.1.30, "Program Description" states: including the 2002 and 2003 addenda 2001 including addenda allows surface or volumetric volumetric "The NUREG 1801 1801 program, program,Section XI.M3, examination when closure studs are removed.
examination removed.
Reactor Head Closure Studs Reactor Studs is based on ASME ASME Code Edition 2001 including including the 2002 and 2003 2003 NUREG-1801, NUREG-1801, Section Section XI.M3 states, "Components are examined examined and tested tested'as as Addenda.
Addenda. The IPEC ISI program is based on lSI program on specified in Table IWB-2500-1. Examination Table IWB-2500-1. Examination category B-G-1, for pressure-retaining pressure-retaining ASME ASME Code Edition 1989, 1989, no Addenda with bolting greater than 2 in. diameter in in reactor vessels specifies specifies volumetric volumetric inspection of reactor head head closure studs based based on on examination of studs in place, examination place, from the top of the nut to the bottom bottom of the flange flange 1998 Edition through the 2000 Addenda. The the 1998 The hole, and surface and volumetric examination examination of studs when removed."
1998 1998 Edition Edition through the 2000 Addenda allows allows surface or volumetric examination when closure surface closure It appears that the phrase phrase "surface and volumetric examination examination of studs when studs are removed which which is consistent consistent with the the removed" should should have been changed to "surface or volumetric examination of studs requirements of NUREG NUREG 1801, 1801,Section XI.M3." when removed" when the ASME code version cited in in NUREG-1801 NUREG-1801 was changed.
The staff notes that the GALL AMP XI.M3 XI.M3 program element "Detection of Aging Effects" requires both Since the IPEC program program is consistent consistent with Table IWB-2500-1 IWB-2500-1 examination examination category surface and volumetric examination of studs when surface B-G-1 in in ASME Code Edition 2001 including the 2002 and 2003 Addenda itit is removed. Provide an explanation explanation why this is not consistent consistent with N NUREG-1 URE G-180 801.1.
considered as an exception to the GALL program.
considered program.
83 AMP B.1.31-1 (Reactor (Reactor Vessel Head Penetration Head Penetration (a) At the last refueling outage outage (Spring, (Spring, 06), IP2 calculatedcalculated EDY corresponding to Inspection)
Inspection) the moderate moderate susceptibility category. At the last refueling outage outage (Spring, 07), IP3 calculated corresponding to the high susceptibility calculated EDY corresponding susceptibility category. IPEC will update update LRA lRA AMP B. 1.3 1, "Program Description" B.1.31, Description" states: the IP2 EDY calculations calculations prior to the next refueling outages outages as requiredrequired by the Order.
"This program was developed in in response response to NRC NRC Order Order EA 03 009. The ASME ASME Section XI, (b) A relaxation relaxation request was granted to perform perform a BMV examination examination of no less than Subsection Subsection IWB Inservice Inservice Inspection and Water Water percent of the RPV head surface rather 95 percent rather than 100 percent because a small area is percent because Chemistry Chemistry Control Programs are used in in partially obscured by a reflective metal insulation (RMI) (RMI) support support ring located conjunction conjunction with this program to manage manage crackingcracking downslope downslope from the outermost outermost RPV head head penetrations. (Ref. COR-04-0244, COR-04-0244, COR-of the reactor vessel vessel head penetrations. Detection 05-0530)'
05-0530) .
of cracking is of cracking is accomplished accomplished through through implementation implementation of aa combination of bare metal A relaxation request was granted granted wherein wherein the inspection inspection coverage NDE, NDE, using visual examination examination (extemal (external surface surface of head) and ultrasonic testing testing (UT)(UT) techniques, of head head penetration penetration nozzlesnozzles is limited by aa non visual examination examination (underside (underside of head) head) threaded threaded section that is for some penetrations penetrations less than the 1 inch below the lower lower techniques.
techniques. Procedures Procedures are developed to perform boundary limit. IPEC performs ultrasonic ultrasonic testing testing (UT) from the inside surface surface of reactor reactor vessel head bare metal inspections inspections and and each each RPV head penetration penetration nozzle from 2 inches above the J-groove weld weld andand calculations calculations of of the the susceptibility susceptibility rankingranking of of the the extending extending down the nozzle to at least the top of the threaded region or further down' down' plant." the threaded threaded region to the extent allowed by technology and geometry. (Ref. COR-06-00111, COR-06-00373) 06-00111, COR-06-00373)
(a) What are the susceptibility susceptibility ranks [or the the effective degradation degradation years years (EDY)]-for (EDY)) for both both IP2 IP2 (c) IPEC has fully implementedimplemented the requirementsrequirements of EA-03-009 EA-03-009 with approved approved and andlP3?IP3? relaxation requests. The aging effect managed is PWSCC, which typically initiates initiates in the penetration nozzle or in in the nozzle J-grooveJ-groove attachment attachment weld. Every two (b) Has Has Entergy Entergy requested relaxation relaxation of the the refueling outages for IP2 and every refueling outage for IP3, BMV examination examination of at requirements in requirements in the the revised revised Order Order EA EA 0303 009009 for for least 95% of the reactor head surface including those areas upslope and downslope downslope either IP IP unit? If If.yes, yes, discuss the technical technical bases of the insulation insulation and ventilation ventilation shroud support support ring is performed to identify identify and and
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Tuesday, Tuesday, March March 18, 2008 Page 22 of48 Page of 48
Item Request Response
Response
for the relaxation relaxation requests. document document evidence evidence of boric acid deposits deposits and head head surface surface degradation. A 360 degree visual degree inspection around each of the reactor head penetrations visual inspection penetrations is performed perfonmed (c) Discuss in detail detail the implementation implementation of NRC NRC to identify and document document evidence of boric acid deposits deposits at the annulus annulus between between the the Order EA 03 009 for both IP2 Order IP2 and IP3, with penetration and the vessel vessel head head.. Visual inspections of pressure pressure retaining retaining respect to detectiondetection of aging effects. components components above above the reactor vessel head are performed. performed.
Every two refuelingrefueling outages outages for IP2 and every every refuelingrefueling outage for IP3, examinations examinations (d) HowHow is this AMP coordinated coordinated with the Boric Boric consisting of eddy current current testing and ultrasonic test are performed performed on the wetted wetted Acid Acid Corrosion Prevention Prevention Program Program (AMP B.1.5)? B.1.5)7 surfaces on the 10 ID side of penetration nozzles.
As described in in outage inspection reports, no indications indications of reactor pressure pressure vessel upper head degradation or primary reactor coolant head degradation coolant boundary boundary leakage leakage at the reactor vessel head penetrations has been been discovered.
discovered.
(d) The Boric Acid Corrosion Corrosion Control Control Program Program complements the Reactor Reactor Vessel Head Penetration Penetration Inspection Program Program by performing a visual inspection inspection of the the reactor vessel head at locations specified by procedures locations specified procedures 2-PT-R156, "Boric Acid Acid Leakage and Corrosion Inspection" and 3-PT-114A, 3-PT-1 14A, "Reactor Vessel Vessel and Closure Head Boric Boric Acid Leakage Leakage and Corrosion Inspection". Inspection". Corporate Corporate procedure EN-DC-319, "Inspection and and Evaluation of Boric Acid Leaks" Leaks" provides general guidance guidance for for penetration inspections and other boric both head penetration boric acid leak detection. Inspection Inspection for boric acid corrosion is coordinated coordinated with reactor vessel disassembly and other inspections required by EA-03-009 as directed directed by implementing implementing procedures procedures and outage scheduling.
scheduling.
COR-04-0244, COR-05-0530, COR-06-001 COR-04-0244, COR-06-00111, 11, COR-06-00373 were provided.
84 AMP B.1.34-1 (Service Water Integrity) Integrity) The GL 89-13 program program includes safety-related safety-related components components that are cooled cooled by the the service water systems systems (heat exchangers) exchangers) as well as the safety-related components components Since this aging aging management program (AMP) that supply the cooling water for heat removal (i.e., pumps, piping, valves, etc.). The The may include non safety related components, components, such Service Water Service Water Integrity Program scope includes includes all GL 89-13 program components, components, as piping, piping, it typically has has aa broader scope scope than the the as well as, additional additional components in in the scope scope of license renewal that contain GL 89 8913 13 program. Describe the difference in in service water regardless of their safety classification. The service water safety classification. water systems at at scope between the Indian Point site GL 89-13 89-13 IPEC IPEC supply both safety-related safety-related and non safety-related loads. The nonsafety-related nonsafety-related nonsafety-related program and this (AMP) and, if if applicable, components and loads included components included in in the Service Water Integrity Integrity ProgramProgram consist of describe how the implementation implementation of GL 89-13 89-13 main turbine auxiliary auxiliary cooling loads such as turbine lube lube oil coolers, stator water recommendations was extended recommendations extended to bound coolers, seal oil coolers, and hydrogen coolers as well well as other loads such as as systems and components components within the scope scope of this this turbine hall closed cooling water heat 1heat exchangers exchangers In In addition, addition, the GL 89-13 89-13 and AMP. Service Water Service Water Integrity programs do not include include components that contain raw water water not supplied by the service water Water systems such as the circulating water and and traveling traveling screen screen wash water systems.
The types of components components and their materials included included in in the GL 89-13 program and the Service Water Water Integrity Program Program are the same. As such, the methodology methodology of periodic inspection and maintenance periodic inspection maintenance applies applies for both. GL 89-13 89-13 is not extended extended to to nonsafety-related nonsafety-related heat heat exchangers exchangers that are included included in in the Service Service Water Integrity Program. Periodic inspections are sufficient Periodic inspections sufficient to manage manage aging effects of the the nonsafety-related heat nonsafety-related exchangers since they do not have a license heat exchangers license renewal component component intended intended function of heat heat transfer. The Service Water Water Integrity Integrity Program includes activities, such as chemical treatment using biocides biocides and chlorine, which apply to the service water system as a whole. Periodic visual inspections apply inspections and inspections using non-destructivenon-destructive examination examination (NDE) (NDE) techniques techniques are used to to manage loss of material in in SW components components regardless regardless of safety classification. classification. The The GL 89-13 program includes inspections of some nonsafety-related includes inspections non safety-related components components in in service water the service water system, such that the inclusion of these additional additional componentscomponents in in the Service Service Water Integrity Integrity program is reasonable.
85 AMP B.1.36-1 (Stuctures Monitoring) Monitoring) The following structures and their structural a) The structural components are are inspected as part of existing structures monitoring the existing monitoring program (Ref. Aging Management Management Program From the applicant's description description of the B.1.36 B.1.36 Evaluation Report IP-RPT-06-LRD08, Evaluation IP-RPT-06-LRD08, section section 3.3).
AMP "Structures Monitoring" in LRA LRA Appendix B, B, the staff cannot identify the complete scope of the the
- auxiliary feedwater feedwater pump building building (IP2/3) program. Very program. Very significant significant enhancements to the the
- boric acid evaporator evaporator building (IP2) (IP2)
"Scope of Program" are identified. identified. However, there
- city water meter house house description of the scope of the existing is no description existing
- condensate storage tanks foundation (IP2) structures monitoring monitoring program, program, and there is no no containment building
- containment building (also known as vapor containment containment (IP2/3) (IP2/3) explanation why such major enhancements enhancements to the the
- control building (IP2/3) (IP2/3) program scope are needed for license renewal.
program
- electrical tunnel (IP2/3) (IP2/3)
The staffstaff reviewed reviewed Section 2.4 of the LRA, to to emergency diesel generator building (IP2/3)
- emergency (IP2/3) better understand the intended better intended functions of the the
- fan house (I(IP2/3) P2/3) structures that are being added to the scope.
- fuel storage building (IP2/3) (IP2/3)
While almost all of the added added structures structures serve a gas turbine
- gas turbine generator generator No. No .. 1,1, 22 and 3 enclosures enclosures license license renewalrenewal intendedintended functionfunction for 1.0 10 CFR
- gas turbine generator generator No.2 No. 2 and 3 fuel tank foundations foundations
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Tuesday, Tuesday, March March 18, 18, 20082008 Page 23 of48 Page of 48
Item Reauest Request Response
Response
(11) of these structures 54.4(a)(3), about half (11) structures also
- intake structure (also known as screenwell intake structure screenwell structure) (IP1/2/3) renewal intended functions for 10 serve license renewal serve
- power conversion equipment power conversion equipment building building (IP3) 54.4(a)(1) and/or 10 CFR 54.4(a)(1) 10 CFR 54.4(a)(2). In In
- primary auxiliary building (lP2/3) (IP2/3) accordance accordance with NRC guidance (RG 1.160) 1.160) and
- primary water storage tank foundation (IP2) primary water" industry guidance (NEI 93-01) industry guidance 93-01) these structures structures
- radiation radiation monitoring enclosure (IP2) (1P2) expected to be included in the current would be expected
- refueling storage tank foundation refueling water storage foundation (IP2) existing existing program. superheater building (IP1)
- superheater (IP1) transformer switchyard support structures
- transformer structures (IP3)
(IP3)
Describe the structures (a) Describe structures and structural transmission towers (SBO recovery
- transmission recovery path) and foundations (IP2/3) (1P2/3) components inspected as part of the existing components inspected
- turbine turbine building (IP1/2/3) and heater bays (IP2/3) (IP2/3) structures structures monitoring program.
- utility tunnel (IP1)
(IP1)
Explain why eleven (b) Explain eleven (11) structures listed in the (11) structures the b) enhancement have intended "Scope of Program" enhancement intended City Water Storage Tank Foundation functions for 10 CFR 54.4(a)(1) functions 54.4(a)(1) and/or 10 CFR The foundation supports the in-scope in-scope city water storage storage tank and meter house. The The 54.4(a)(2). tank is in-scope in-scope because provides a source because it provides source of water for the auxiliary feedwater system for both IP2 and IP3 and supplies emergency emergency water for safety injection, residual heat removal, and charging charging pumps.
The city The water storage city water tank foundation storage tank foundation has function for intended function has intended 10 CFR for 10 CFR 54.4(a)(2).
54.4(a)(2).
Condensate Storage Tank Foundation (IP3) condensate storage tank foundation supports the condensate The condensate condensate storage tank.
foundation has intended functions for 10 The foundation 54.4(a)(1) and (a)(2).
Containment Access Facility and Annex (IP3)
Containment (IP3) containment access facility and annex The containment annex is located adjacent to the primary containment access facility and annex is Class III building (PAB). The containment auxiliary building III except for the structural steel portion interfacing with the primary auxiliary portion interfacing auxiliary building building (PAB), which is seismic Class I.I. The structure has intended intended function for 10 CFR CFR 54.4(a)(2).
Discharge Canal The discharge discharge canal carries carries the safety-related safety-related service water system discharge to the the river. Three Three backup service water pumps, which service water which provide provide cooling water from the the discharge discharge canal in event that the service water intake structure is in the unlikely event damaged, are supported on a slab spanning the walls walls of the canal. The portion portion of discharge canal wall that is adjacent the discharge adjacent to the service water pipe chase is seismic seismic Class I and is part of the ultimate heat sink. The The structure has intended functions for 54.4(a)(1) and (a)(2).
Primary Water StorageStorage Tank Foundation Foundation (IP3)
The primary water storage tank foundation provides provides the main support for the the gallon primary water storage tank. The tank supplies demineralized water 165,000 gallon 165,000 for the primary water makeup system. The primary water storage tank foundation foundation is a Seismic Class II reinforced concrete spread footing supporting the primary water structure has intended functions for 10 CFR 54.4(a)(2).
storage tank. The structure 54.4(a)(2).
Refueling Water Storage Tank Refueling Tank Foundation (IP3) (IP3) refueling water storage The refueling foundation provides storage tank foundation provides the main support for the the 350,000 gallon refueling water storage tank. The tank supplies refueling water borated water to the supplies borated the canal, safety injection refueling canal, refueling injection pumps, the residualresidual heat removal pumps, and the the loss-of-coolant accident. The structure has containment spray pumps for the loss-of-coolant containment has intended functions intended 54.4(a)(1).
functions for 10 CFR 54.4(a)(1).
Service Water Pipe Chase (lP3)
Service (1P3)
The service water pipe chase provides protection of service service water service water lines that span discharge canal. The structure across the discharge structure provides protection protection of the service water valves and associated piping. piping. This structure has intended functions for 10 CFR 54.4 (a)(1) and (a)(2).
(a)(1) and (a)(2).
Service Service Water Valve Pit (IP3)
Service Service water valve pit for each intake structure structure is provided for protection protection of service service water components. This structure structure has has intended functions for 10 10 CFR 54.4 (a)(1) and 54.4 (a)(1)
(a)(2).
Superheater Stack Superheater (IP1)
Stack (IP1) superheater building The superheater building is is adjacent adjacent to but physically separated from physically separated from the the control control superheater stack is located on top of the Unit 1 superheater building. The superheater superheater building.
building.
The exterior walls are masonrymasonry or metal siding. siding. The superheater superheater building waswas originally classified as seismic originally seismic Class III, utilized by Unit 22 in Ill, but itit is utilized in a safety function function classified as seismic Class I.I. This structure has intended and is now classified intended functions for for 10 CFR 54.4(a)(1) 54.4(a)(1) and (a)(2).
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Tuesday, March Tuesday, March 18, 2008 Page Page 24 of 48
Item Request Response Waste Waste Holdup Tank Pit (IP2)
The waste waste holdup tank pit houses the waste holdup holdup tank, which serves as the the collection collection point for all liquid radwaste. This structure is conservatively credited credited for performing performing the following following intended functions for 10 CFR 54.4(a)(2).
Provide Provide functional functional support support to nonsafety-related nonsafety-related components whose failure could result in potential potential offsite offsite releases.
Waste Waste Holdup Tank Pit (IP3)
The waste waste holdup tank pit (WHTP) is two adjacent adjacent underground underground structures joined together together to form a single structure.structure. It is adjacent adjacent to the primary water storage tank and the radioactive radioactive machine shop. The structure houses waste waste holdup tanks No.
31, 32 and 33 each 31, each in their own separate. The structure has the following intended intended functions for 10 CFR 54.4(a)(2).
Provide functional functional support support to nonsafety-related nonsafety-related components whose failure could could result in in potential offsite releases releases 86 B.1.36-2 (Structures Monitoring)
AMP 8.1.36-2 Monitoring) (a) The structural structural commodities commodities inspected as part of the existing structures structures monitoring program include include structural steel (beam, columns, end connections),
The second enhancement to AMP B.1.36 second enhancement 8.1.36 under support steel steel (instruments racks, base plates, etc.), concrete surfaces, instrument surfaces, instrument "Scope of Program" indicates indicates that "procedures will racks . Individual racks. Individual inspection inspection checklists are provided provided in in the program procedures procedures for for be revised to clarify that in addition to structural each commodity.
steel and concrete", 13 commodities commodities "are (Ref. ENN-DC-150, Section 5.5 and Attachments Attachments 9.2 and 9.4) inspected for each structure, as applicable." The The staff notes that the specific specific commodities listed (b) While many many of the listed listed commodities commodities are routinely inspected as part of the the would be expected to be included included in the current current structures monitoring program (AMP B.1.36), 8.1.36), they are are not explicitly explicitly identified safety-related or program ififthey are safety-related existing program in the program procedures.
procedures. Thus, the purpose of the enhancements is to ensure important important to safety. The staff staff is unclear unclear what what these items (including anchorages) are identified explicitly (including their anchorages) in the program. For explicitly in commodities commodities are currently currently being inspected inspected in the the example, the existing SMP includes inspection of concrete damage damage due to vibrating existing program.
program ... equipment, which addresses equipment pads and foundation foundation identified identified in the the enhancement (Ref.
enhancement (Ref. ENN-DC-1 ENN-DC-150, 50, Section Section 5.7 [2] and Attachment 9.4).
(a)
(a) Describe the structural commodities inspected inspected as part part of the existing structures structures monitoring monitoring In LRA Section B.1.36.2 In 8.1.36.2 and in Commitment Commitment 25, add "(including their anchorages)"
program. paragraph discussing the enhancemnts in paragraph enhancemnts to SMP for IP2 and IP3.
(b)
(b) Explain why the 13 commodities commodities are identified identified Clarification to be incorporated incorporated into the LRA.
as an enhancement to the "Scope of Program."
an enhancement 87 AMP B. 1.36-3 (Structures Monitoring) 8.1.36-3 Monitoring) .' a) There is sufficient number number of analytical results to ensure that the ground water is being properly monitored. Large numbers groundwater wells located adjacent numbers of groundwater adjacent to An enhancement enhancement to AMP B.1.36 8.1.36 underunder "Detection structures have been the structures been sampled sampled and were analyzed for sulfate sulfate and chloride at a of Aging Effects" is to monitor groundwater for monitor groundwater contract contract laboratory, with pH having having been determined determined at the time time of sample aggressiveness aggressiveness to concrete. Sulfates, pH and collection.
collection. The data indicates that the ground water is non-aggressive non-aggressive (pH>5.5, (pH>5.5, chlorides chlorides will be monitored. Ground Ground water testing Chloride <500 ppm Chloride ppni and Sulfate <1500 ppm). Several Several samples samples taken along the the is to be conducted conducted at least every five (5) years, by facility waterfront and adjacent adjacent to the discharge canal were noted noted to have higher higher taking taking samples samples from aa well that is representative representative than normal levels of chloride. Given the location location of samples, these higher than of groundwater groundwater surrounding below-grade site normal levels are believed to be due nonnallevels due to the salinity salinity of the brackish brackish Hudson Hudson River structures structures water water at the Indian Point location location of the river. In In all cases pH results are >5.5 and and sulfate concentration concentration < 1500 Ground water 1500 mg/L. Ground water samples continue to be samples will continue be (a) Describe Describe past and present present groundwater groundwater obtained quarterly basis for one calendar year in obtained on a quarterly in order to fully characterize characterize monitoring activities at the Indian monitoring Indian Point site, these parameters parameters (Chloride, (Chloride, Sulfate, and pH) pH) for the groundwater groundwater at IPEC to including the sulfates, pH and chlorides readings including readings account for any seasonal variation.variation. The selected selected sample locations will provide provide obtained; andand the location(s) location(s) where test samples samples representative sample representative sample of the ground water in the vicinity vicinity of the structures. A review were/are taken relative relative to the safety-related safety-related and and of the several hundred ground water water pH values collected collected in in late 2005 to present present important-to-safety embedded important-to-safety embedded concrete reveal that the ground water had a pH of >5.5 in in all cases except except four. In In those four foundations.
foundations. cases pH was found to be <5.5 SUo SU. All four of these low pH samples samples were obtained from the same sample point pOint on the same day. To date all subsequentsubsequent samples samples taken (b) Explain the technical (b) technical basis for concluding that from this sample sample point were were found to have a pH >5.5 SUo SU.
testing a single well every five (5) years is sufficient safety-related and sufficient to ensure that safety-related There is sufficient number of monitoring monitoring wells being sampled at various locations locations to important-to-safety important-to-safety embedded concrete embedded concrete ensure monitoring monitoring the ground water. And, the results are being properly evaluated evaluated in in foundations foundations are not exposed to aggressive order to characterize characterize the ground water water across the site (in (in vicinity of the safety-related safety-related groundwater. . structures). The sample data data and well mapmap are available available on site for review.
b) At least least five (5) wells wells will be tested. A sample sample frequency of 5 years years in in aa limited number of wells (at least 5 wells) adjacent to safety structures and those falling number falling under 10 CFR 54.4 (a)(1) (a)(1) and 10 CFR 54.4 (a)(2) would be sufficient to confirm non- non-aggressive nature of the ground water. The large sample population for the initial characterization, the diverse locations from which the samples characterization, samples were obtained and the seasonality of sample sample collections contribute to our confidence collections contribute confidence in in the the understanding of the nature of the ground water. Additionally, we would not normally understanding normally
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Tuesday, Tuesday, March March 18, 2008 Page 25 of 48 Page
Item Request Response expect to see the ground water conditions change unless an extraordinary extraordinary event occurred such as a major withdrawals (such as significant pumping pumping out the ground ground water) or injections of water on the Site or in the vicinity of the Site. Finally, the three three structural inspections performed structural inspections performed in in five year intervals intervals showed nomajor no major,.change
.. change in in structural integrity from inspectioninspection to inspection.
incorporated into the LRA.
Information to be incorporated Information 88 B.1.36-4 (Structures Monitoring)
AMP B.1.36-4 Monitoring) structures at Indian (a) The water control structures Indian Point Energy Center (IPEC) (IPEC) which have an intended intended function for license renewal and are included (or will be included) included) in in the the In LRA Appendix B, Table B-2, the applicant applicant scope of AMP B. 1.36 (Structures Monitoring)
B.1.36 Monitoring) are intake intake structure (including intake intake indicates "This program indicates that "This program [GALL AMP XI.S7] XI.S7] is structure enclosure) and discharge canal. The discharge canal is not explicitly explicitly not credited for aging aging management. The The specified in the structures monitoring monitoring procedures. An enhancement enhancement identified for Structures Structures Monitoring Program manages manages the the AMP B.1.36 will explicitly specify discharge canal. (Ref. LRA section specify the discharge section 2.4.2 and effects of aging on the water control structures structures at B.1.36)
IPEC." GALL IPEC.". GALL AMPAMP XI.S7 offers this option, option, provided all the attributes of GALL AMP XI.S7 are provided (b) AMP B.1.36 (Structures Monitoring Monitoring Program) Program) is an existing existing program program that that incorporated incorporated in the applicant's StructuresStructures performs performs inspections in in accordance accordance with 10 CFR 50.65 (Maintenance (Maintenance Rule) as as Monitoring Monitoring Program. addressed addressed in Regulatory Regulatory Guide Guide 1.160 1.160 and NUMARC NUMARC 93-01. 93-01. Periodic inspections inspections are used to monitor the condition of water control structures used structures and structural components components (a) Identify Identify the specific water control structures control structures there is no loss of intended function. If to ensure there If established established criteria criteria as specified in that have an intended function for license renewal, intended function maintenance rule scoping documents are exceeded maintenance exceeded the affected affected system is is and are included in in the scope of AMP B.1.36. monitored in in accordance accordance with a 10 CFR 50.65 (a)(1) (a)(l) action plan.
(b) Describe the attributes (b) Describe attributes of AMP B.1.36 that The parameters parameters monitored or inspected inspected were selected based on information information pertain to aging management of water control aging management included in industry industry codes, standards standards and guidelines, and also consider industry industry and structures.
structures. plant-specific operating operating experience.
experience.
(c) Explain how these attributes attributes of AMP B.1.36 B.1.36 Inspections of steel and concrete Inspections concrete portion of accessible water water control structures structures are encompass the attributes of GALL encompass GALL AMP XI.S7, five-year intervals performed at five-year intervals and inspections of normally inaccessible inaccessible areas are without exception. performed using special tools or inspection inspection of adjacent adjacent areas when when possible. More More frequent inspections may be performed frequent inspections performed based on past inspection inspection results, industry experience, or exposure exposure to a significantsignificant event.
Inspection methods, inspection Inspection inspection schedule, and inspector qualifications qualifications ensure ensure that degradation will be detected aging degradation detected and quantified quantified before loss of intended intended functions.
Inspection methods, inspection Inspection inspection schedule, and inspector qualifications are based on on information provided in in industry codes, standards standards and guidelines, and also consider consider industry and plant-specific plant-specific operating experience. .
The acceptance criteria were selected to ensure that the need acceptance criteria need for correCtive corrective actionsactions is identified before loss of intended intended functions. Acceptance Acceptance criteria were established considering information provided provided in in industry codes, standards, and guidelines guidelines including including NE1 NE1 96-03, ACI 201.1 R-92, and and ACI 349R-85.349R-85. Industry and plant-specific plant-specific operating operating experience was also considered. IPEC applies requirements experience requirements of 10 CFR Part 50 Appendix B B to the Structures Monitoring Program Program through use of the IPEC corrective corrective action program.
(c)
( c) The Structures Monitoring Program Program (AMP B 1.36) is consistent consistent with the program described in described NUREG-1801,Section XI.S6, Structures in NUREG-1801, Structures Monitoring Program with enhancements enhancements listed in in LRA section section B.1.36. The SMP attributes attributes are consistent consistent with with
. the XI.S7 program attributes attributes that are applicable applicable to the in-scope in-scope IPEC water control structures.
structures.
- 1) Scope Scope - The scope of the GALL XI.S7 program applicable applicable to IPEC is the intake intake structure and structure and discharge discharge canal. There There are no earthen structures at IPEC in atlPEC scope in the scope of license license renewal. The intake structure structure is includedincluded in the scope scope of the Structures Structures Monitoring Program. The discharge discharge canal will be explicitly added added to the program program as as enhancement to AMP B.1.36. (Ref. LRA section 2.4.2 and B.1.36) an enhancement
- 2) Preventive actions - The GALL XI.S7 program includes no preventive actions.
2)
AMP B.1.36 B.1.36 is consistent with preventive preventive actions.
- 3) Parameters Monitored Monitored - The aging effect requiring requiring management management for concrete concrete structural components components of the intake structure structure is loss of material material which is consistent consistent with GALL Volume 2 item III.A6-7. II1.A6-7. The parametersparameters monitoredmonitored from the GALL GALL XI.S7 XI.S7 program applicable applicable to loss of material material are consistent with those monitored monitored by the the Structures Monitoring Program. Program. The guidance guidance for inspections inspections of concrete concrete in Section C.2 of RG 1.127 1.127 is consistent with the guidance guidance in ACI 349.3 used in in the Structures Structures Monitoring Program. Based on the above discussion, the parameters Monitoring parameters monitoredmonitored include loss of material, material, cracking, movement movement (settlements and deflections).
- t~~:G-":Z~~~~~£";'~~::-f":~~~'m*""""
Z-1m=M110==0ý111 IMMM_-ZIM ':'::tm~:m:<:x:mw.m::::mw~mrC;1;' :~v.~~::'-::::";:: ;::":":~~:~;;:::,;::'':"::::::~;:1;llmmmm,:w.m~rmw.:",,1:- ;*,y,t:~.illln:m:;.W::':",-:::::~:'::-;:-;:'~~~:""'::l..-.t.:,~~J~
Tuesday, Tuesday, March March 18, 2008 Page Page 26 of of48 48
Item Request Response Since there are no earthen earthen structures structures at IPEC in in scope of the license renewal, GALL XI.S7 attributes applicable applicable to earthen structures are not applicable for IPEC water water control control structures.
structures.
4)
- 4) Detection of Aging - GALL XI.S7 identifies identifies visual inspection inspection methods methods as the primary method method used to detect aging. The Structures Monitoring Monitoring similarly uses visual inspection methods methods as the primary method used to detect aging in concrete concrete structural components. GALL GALL XI.S7 identifies inspection inspection intervalsintervals of five years. The The Structures Monitoring Program identifies identifies similar similar inspection intervals of five years for for accessible areas and opportunistic inspections inspections for buried components. Guidance will be added added to the Structures Structures Monitoring Monitoring Program to inspect inaccessible inaccessible concrete concrete areas that are exposed by excavation excavation for any reason. reason.
Monitoring and Trending
- 5) Monitoring Trending - Monitoring Monitoring is by periodic inspection for both the GALL XI.S7 and Structures Monitoring Programs.
Acceptance Criteria - Acceptance
- 6) Acceptance Acceptance criteria in NUREG-1801, NUREG-1801, XI.S7 says plant-acceptance criteria based on Chapter specific acceptance Chapter 5 of ACI ACI 349.3R-96 are are acceptable.
Appropriate guidance Appropriate guidance is provided in in the Structures Monitoring Program to ensure corrective measuresmeasures are identified identified prior to loss of intended intended function. The guidance guidance in in Structures Monitoring the Structures Monitoring Program includes reference reference to ACI 349.3R-96. 349.3R-96. XI.S7 XI.S7 acceptance criteria acceptance criteria related to earthen earthen structures structures are not not applicable.
applicable.
corrective actions, confirmation 7-9) The corrective confirmation process and and administrative administrative control attributes of the Structures Structures Monitoring Monitoring Program and the GALL XI.S7 program are are consistent.
- 10) Operating Experience Experience - The operating experience experience relevant to the effectiveness effectiveness of the Structures Structures MonitoringMonitoring Program is presented presented in Appendix B of the application in Appendix application and is consistent with the operating operating experience experience described described in GALL XI.S7. XI.S7.
Therefore, the attributes of the NUREG-1801 NUREG-1801 XI.S7, Water Water Control Structures, aging aging management program pertaining to the intake intake structure are incorporated incorporated within the the AMP B.1.36 (Structures Monitoring Program).
The following is added added to commitmentcommitment 25: "Enhance the Structures Monitoring Monitoring Progrm for IP2 and IP3 to perform perform inspection of normally submerged concrete concrete portions of the intake structures at least once every 5 years.
Information to be incorporated Information incorporated into into the LRA.
89 89 AMP B.1.36-5 (Structures Monitoring) Monitoring) Enhancements to the Structures Enhancements Structures Monitoring Monitoring Program (AMP B.1.36) will be be implemented prior implemented prior to the period period of extended extended operation. operation.
What is Entergy's schedule schedule for implementing implementing the the See Commitment #25 #25 enhancements to AMP B.1.36?
enhancements B.1.36?
90 90 AMP B.1.39-1 (Water Chemistry-Auxiliary Chemistry-Auxiliary System) Recent Recent monthlymonthly tests of stator cooling water samples samples have been within specification. Monthly stator cooling specification. cooling water analysis analysis will continue continue per per thethe Describe past and present Describe present surveillance surveillance tests, requirements of procedure requirements procedure 0-CY-2510, "Closed Cooling Water Chemistry Chemistry sampling, sampling, and analysis analysis activities for managing managing the the SpeCifications and Specifications Frequencies" and Frequencies" effects of aging aging on components components within the scope scope of this AMP. The LRA credits credits both the Water Chemistry Chemistry Control Control - Auxiliary Systems and Periodic and Periodic Surveillance Surveillance and Preventative Preventative Maintenance Maintenance (PSPM) (PSPM) programs programs to manage loss of material for the NaOH tank. Since Since thickness measurements are are performed every five years under under the PSPM PSPM Program, Program, use of the water chemistry control- control - auxiliary systems systems is not required. Therefore, IP-RPT-06-LRD07 IP-RPT-06-LRD07 and the LRA will be revised to remove the Water Chemistry Control - Auxiliary Systems Systems Program as an aging management program for the NaOH NaOH tank.
Auxiliary Auxiliary steam steam supply supply is cross-connected cross-connected so that IP2 or IP3 can can support the steam requirements of either unit from the main main steam systems. Components in house in the house service service boiler systems subject to aging aging management management review are exposed to main steam during normal operation and are managed by the Water Chemistry Chemistry Control -
Primary and Secondary Secondary Program Program and not the Water Chemistry Chemistry Control - Auxiliary Systems Program as stated in the LRA. Therefore, IP-RPT-06-LRD07 IP-RPT-06-LRD07 and the LRA will be revised to remove the Water Water Chemistry Control - Auxiliary Systems Program as an agingaging management management program for the house service boiler systems. Water Water chemistry parameters for house house service boiler components components are maintained maintained per EPRI TR-1 02134, "Pressurized Water Reactor guideline TR-102134, Reactor Secondary Secondary Chemistry Guidelines". Recent Recent test of secondary secondary water chemistry parameters parameters have been within within specification or corrective actions have been performed performed to return parameters parameters to to acceptable levels per prescribed action action levels. Parameters Parameters are maintained per the the W~:;' .%;illml%"~:;~~~~~'t\:'~:;f,~'~"tt,:<'.'m<d,W,'t~~:~"" "" :",:' ~':::::;s:::..::~mm:mm:::mID:mmm:,:;:%tt.;".,;- ',", 11mmmwm.::%::::1:::l:~~<~.::r:.:.~~ ::",:::,:;:t\~,~-:::,:~~m.~;.:-mm<l)l1?i.'t:a~~(*~.;1t' ,:" ,
Tuesday, Tuesday, March March 18, 2008 Page 27 Page 27 of of48 48
Item Request Response
Response
requirements of Procedure 0-CY-2410, "Secondary Chemistry Specifications".
Recent chemistry data was available available for review.
Information to be .incorporated Information incorporated into the LRA.
91 AMP B.1.39-2 (Water Chemistry-Auxiliary Stator cooling water systems are high high purity systems in in which poor oxygen oxygen control Systems) can cause an increase increase in copper copper corrosion products. products. BasedBased on this experience, stator cooling water is monitored monthly for conductivity conductivity and copper. Refer to to Describe the procedures procedures used to perform Procedure 0-CY-2510, Closed Cooling Water Chemistry Specifications Specifications and surveillance activities activities and the basis for for Frequencies and Frequencies and 2-SOP-26.7, 2-S0P-26.7, Generator Generator Stator Cooling Water System for more more acceptance criteria and sample /1 test frequencies.
acceptance frequencies. information.
information.
The LRA credits both the Water Water Chemistry Control - Auxiliary Auxiliary Systems and Periodic Periodic Surveillance and Preventative Surveillance Preventative Maintenance Maintenance (PSPM) programs to manage (PSPM) programs manage loss of material for the NaOH NaOH tank. Since thickness thickness measurements measurements are performed every five years under the PSPM program, use of the Water Chemistry Control - Auxiliary Auxiliary Systems Program is not required. Therefore, IP-RPT-06-LRD07 IP-RPT-06-LRD07 and the LRA LRA will bebe revised to remove the Water Water Chemistry Control - Auxiliary Systems Program Program as an management program aging management program for the NaOH tank.
Auxiliary steam supply is cross-connected cross-connected so that IP2 IP2 or IP3 cancan support the steam requirements of either unit from the main steam systems. Components requirements Components in in the house house service boiler boiler systems subject to aging management management review are exposed exposed to main steam during normal normal operation and are more appropriately appropriately managed by the Water Chemistry Control Chemistry Control - Primary and Secondary Program Program and not the Water Water Chemistry Control - Auxiliary Systems Control- Systems Program as stated in in the LRA. Therefore, IP-RPT IP-RPT LRD07 LRD07 and the LRA will be revised to remove the Water Water Chemistry Control-Control -
Auxiliary Systems Program Program as an aging management management program program for the house service service boiler systems. Water chemistry chemistry parametersparameters for house service service boiler components are maintained maintained per EPRI guideline TR-1 02134, "Pressurized Water Reactor guideline TR-102134, Secondary Chemistry Secondary Guidelines". Parameters Chemistry Guidelines". Parameters are are maintained per the requirements of Procedure Procedure 0-CY-2410, "Secondary Chemistry Chemistry Specifications" available for review review during the audit.
Information !o to be incorporated incorporated into the LRA.
92 AMP B.1.40-1 B.1.40-1 (Water Chemistry-Closed Chemistry-Closed Cooling) A recent QA audit found that closed closed cooling water chemistry parameters parameters are maintained maintained within industry industry guidelines and aa recent routine inspection of components components The LRA takes an exception exception to the GALL in aa closed cooling water system found no in evidence of active corrosion.
no evidence recommendation recommendation for detection of aging effects through performance performance and functional testing. As a LRA section B.1.27, One-Time Inspection, Inspection, describes inspections inspections planned to verify result, this program credits preventive preventive measures measures effectiveness of the water chemistry control programs to ensure that significant effectiveness significant to manage manage the effects effects of aging. Provide' Provide objective degradation is not occurring degradation occurring and component component intended intended function is maintained maintained during evidence eVidence (e.g., plant specific operating the period period of extended operation. operation. The results of these inspections will provide provide experience) experience) which demonstrates demonstrates that the existing existing objective objective evidence to demonstrate demonstrate that the existing preventive measures will preventive measures preventive measures measures will adequately adequately manage manage the adequately adequately manage the effects of aging in the closed cooling cooling water system effects effects of aging in of aging in the the closed closed cooling cooling water water systemsystem components that are within the scope of license renewal.
components that are within the scope of license license renewal. Please see the response response to audit question 95 (AMP B.1.40-4) for additional information regarding regarding component inspections in closed cooling cooling water systems.
93 AMP B.1.40-2 (Water Chemistry-Closed Chemistry-Closed Cooling) Cooling) The IP2 CCW system Molybdate Molybdate is administratively administratively controlled within the 400-800 400-800 ppm range to ensure it remains within the 200-1000 ppm range recommended recommended in in the the The LRA LRA states that in in June June 2003: 2003; CCW corrosion EPRI Closed Cooling Water Guidelines (EPRI TR 1007820).
Water Guidelines 1007820). In accordance accordance with with inhibitor (molybdate (molybdate concentration) concentration) was found to EPRI TR-1007820, TR-1007820, site procedures procedures contain two action levels. 1) If If the Molybdate Molybdate be out of specification be specification and and that that corrective corrective actions actions level falls below below 200 ppm the system should be restored to above above 200 ppm within 90 90 were taken to restore the molybdate molybdate concentrationconcentration days. 2) If If the Molybdate Molybdate level falls below 160 ppm the system should be restored to to to specification. However, the LRA does not above 200 ppm within 30 days. If Ifthese these actions actions are not accomplished, accomplished, an indicate indicate ifif surveillance practices (e.g., sampling) sampling) engineering evaluation must be performed performed to determine the impact of the condition were also modified modified as a result of this occurrence. on the long-term long-term reliability of the system.
Provide aa description of past and present surveillance slJrveiliance activities and, if if applicable, applicable, provide provide aa On 3/21/03, 3/21/03,8113 a 113 ppm Molybdenum Molybdenum concentrationconcentration (which correlates correlates to an -188 -188 justification ififthe surveillance jUstification surveillance practices or ppm Molybdate Molybdate concentration) concentration) was observed. observed. Subsequently, Subsequently, on 4/15/2003, 4/15/2003, a 131 frequencies frequencies were not revised as a result of this concentration was observed. The low concentration ppm concentration occurred due to dilution concentration occurred dilution event. when water was added added to the system to compensate compensate for leaks and work activities.
Leaks were were repaired, Molybdate Molybdate was was added to the system to restore the the concentration to the normal concentration normal range, and the normal normal monthly samplesample frequency frequency was was temporarily increased temporarily increased (two samples samples were taken taken the next week) to verify that the the concentration remained concentration remained within the normal concentration on 4/22/0.3 normal range. The concentration 4/22/03 was 418 ppm 418 ppm and and the the concentration concentration on 4/23/03 was on 4/23/03 was 425 425 ppm, ppm, indicating indicating thatthat proper proper control control had been restored.
lmfM'$<\;:,~*~",:"':'~O:~S:::S::,,':§"'s&'M&8i'iimiMt&u:%:t~~~**~~'~t'-:k"::l'~~$r11tTh.':mlJ&"m?;'\l%'tm,~,'.:,1t~;~~~:~.: ~<l:::o:am""*:>:;:.-:*'*.'.~.-:~(!IT"-&u~.)"""-M~.w.::l':&t:mmmlt..,m.,~~:*':'~:~':::A-'~~'~~~T:0.,,%;:::~'~<,r~:,,;:ti1o.,-m~"':w.'~
Tuesday, March Tuesday, March 18, 2008 Page 28 of Page of 4848
Item Request Response A few weeks concentration was observed. While this later (5/14/2002), a 395 ppm concentration weeks later this value does not require action per the EPRI guidelines, itit is outside the administrative require action administrative control Molybdate was again added. Since control range, so Molybdate Since that time, monthly samples samples (June 20032003 to August 2007) have shown that the IP2 CCW Molybdate Molybdate concentration has remained above the action has remained level threshold and, except for one reading of 377 action level 377 ppm in in May 2006, hashas remained within the 400-800 ppm administrative administrative control range.
As sustained Molybdate concentrations below 160 ppm could initiate system degradation, EPRI TR 1007820 material degradation, procedures direct 1007820 and site procedures direct that an an engineering engineering evaluation be performed performed to determine the impact of the condition on the the long-term reliability of the system ififthe condition persists for more than 30 days days after the first sample below 160 160 ppm. Since the Molybdate concentration in Molybdate concentration in the IP2 CCW CCW system was returned to 418 ppm seven days after after the sample below 160 160 ppm and remained above the threshold since that time, evaluation has remained evaluation of the impact impact of thethe long-term reliability is not necessary condition on long-term increased sampling is not necessary and increased not warranted. Sample results since June 2003 warranted. 2003 have confirmed the adequacy adequacy of the the established sampling sampling frequency.
94 AMP B.1.40-3 (Water Chemistry-Closed Chemistry-Closed Cooling)Cooling) In addition to the QA audit of the plant chemistry In addition program in August 2003 that was chemistry program was mentioned in the LRA, similar audits in mentioned in June 2005 and September 2006 2006 support the the The LRA states: "Continuous program program conclusion that continuous program improvement provides assurance program improvement assurance that the Water improvement provides assurance that the program improvement provides program Control - Closed Cooling Water Program will remain effective Chemistry Control effective for effective for managing loss of material will remain effective managing loss of material of components.
of components." However, the LRA LRA only cites one one QA audit observation observation to support this conclusion. June 2005 audit concluded that the program is effective in The June in implementing implementing Provide additional information to support Provide additional this support this applicable regulations, industry standards and the quality industry standards assurance program quality assurance conclusion.
conclusion. manual. Strengths were noted noted in the areas of leadership, accountability, training, training, industry operating and review of industry operating experience.
September 2006 audit concluded that closed cooling water systems The September systems are treated controlled to industry guidelines.
and controlled Improvements were noted in the use of the guidelines. Improvements the process and strengths were noted condition reporting process noted in in the area of chemistry data trending.
95 AMP B. B.1.40-4 Chemistry-Closed Cooling) 1.40-4 (Water Chemistry-Closed Water Chemistry Control The Water Control - Closed Cooling Water Program is a preventive Water Program preventive program. EPRI Report TR-1007820TR-1007820 refers refers to inspections performed performed in conjunction The exception to GALL, Monitoring GALL, Element 5, Monitoring maintenance activities, which with maintenance which' are notnot specifically included as part of this specifically included this and Trending, inspections are Trending, states that visual inspections program.
program. However, componentscomponents cooled by closed cooling water systems are are technical justification for performed. Provide a technical not performed. for routinely inspected as part of an eddy current routinely inspected current inspection program. These heat inspection program.
not performing visual inspections recommended in inspections recommended exchangers exchangers receive a visual inspectioninspection in addition to eddy current testing that would GALL. detect detect aging aging effects effectiveness of the Water Chemistry Control-effects and confirm the effectiveness Control-Closed Cooling Program. Some of the heat exchangers Cooling Water Program. exchangers receiving visual inspections include:
IP2 and IP3 Closed Cooling Water
- IP2 Water 21/22CCHX and ACAHCC1/2 ACAHCC1/2 IP2 and IP3 Instrument Air Closed Cooling Water
- IP2 Water 21/22CWHX and SWM-CLC-31/32-HTX
- - IP2 and IP3 EDG Jacket Water Coolers 21/22/23EDJC Jacket Water EDG-31/32/33-EDG-21/22/23EDJC and EDG-31/32/33-EDG-JWHTX IP2 Conventional
- IP2 Conventional Closed Cooling 21/22THCCSHX
- SIP3 IP3 Turbine Closed Cooling SWT-CLC-31/32-HTX Turbine Hall Closed SWT-CLC-31/32-HTX e:
In In addition addition to these completed completed inspections, LRA Section B.1.27, One-Time One-Time Inspection, describes future inspections planned to verify effectiveness effectiveness of the water chemistry control programs to ensure that significant degradation degradation is not occurring occurring and component intended function is maintained during the period of extended include areas most susceptible to corrosion such as stagnant operation. This will include stagnant areas.
Clarification to be incorporated Clarification incorporated into the LRA LRA 96 AMP B.1.40-5 (Water Chemistry-Closed Chemistry-Closed Cooling) The IP Water Chemistry Control - Closed Cooling Water Program will be consistent Chemistry Control- consistent NUREG-1801. The program maintains with NUREG-1801. maintains system corrosion corrosion inhibitor inhibitor GALL, Element 2, preventive preventive actions, statesstates that concentrations within specified guidelines of EPRI Report concentrations TR-1007820, Rev. 1I to Report TR-1007820, system system corrosion inhibitor concentrations should minimize corrosion and SCC. EPRI TR-1007820 supersedes TR-1 TR-1 007820 supersedes 07396 TR-107396 maintained within limits specified in EPRI TR be maintained referenced in referenced in NUREG-1801.
107396. Since this element is not identified identified in the the exception, itit is assumed assumed that the IP program program is consistent with N NUREG 1801. Describe the basis U RE G 1801. basis
~~.X'~~'J:"::::~~~<'l':'..~.t:<t~.t~\::m<mm;:mt$,~!<:"~~m:~,_t.':::.:.~.~:.w*":";:;~1lm.~~':"-<-.d2.;.,~:"""""'~-x£t,"':~r~~::::::r<':.:2-'Y2~~*,',4'.~m<~*:7}"~2:::.':"'...a~":::';~~;?/$,,:m<,",,~~!~
Tuesday, March Tuesday, March 18, 2008 Page 29 of Page 0(4848
Item Request Response
Response
for specified corrosion inhibitor concentration limits.
limits.
97 AMP B.1.40-6 B.l.40-6 (Water Chemistry-Closed Chemistry-Closed Cooling) Cooling) The Water Water Chemistry Control Control - Closed Cooling Water Program is based on EPRI guidelines guidelines for closed cooling water TR-1 007820, 'Closed Cycle water issued as EPRI TR-l007820, Cycle For each program attribute having an exception exception to Cooling Water Chemistry,' Rev. 1, Water Chemistry,' 1, dated April 2004. This guideline guideline supersedes EPRI GALL, provide provide a detailed, detailed, line by line, comparison TR-107396, 'Closed Cycle Cooling Water Chemistry TR-l07396, Chemistry Guideline,'
Guideline,' Revision 0, issued of the criteria recommended recommended in GALL (e.g., EPRI November November 1997, referenced in NUREG-1801.
NUREG-1801. RevisionRevision 1 of the EPRI guideline guideline is TR 107396) 107396) against the criteria / industry industry standard significantly significantly more directive directive than Revision 0 and incorporates incorporates action levels with (e.g., EPRI TR1007820)
TR 1007820) that have been established thresholds for specific actions established actions required. Revision 1 specifically implemented. establishes recommended establishes recommended monitoring frequencies frequencies and clearly identifies expectedexpected control control parameter values.
The LRA indicates that Water Chemistry Control - Closed Closed Cooling WaterWater Program Program attributes 3, 4, 5, and 6 have an exception exception to GALL. In In all four cases, the exception exception is due to the fact that NUREG-1801 NUREG-1801 recommends the use of performance performance and functional testing to ensure acceptable function of the CCCW systems, while the ensure acceptable the IPEC Water Water Chemistry Control - Closed Cooling Water Program Program does not include include performance performance and and functional testing. The exception is the same regardless regardless which revision revision of the EPRI guideline is used because because neither revision revision of the EPRI EPRI guideline guideline recommends recommends that equipment performance and functional functional testing testing should should be part of a water chemistry chemistry program. Rather, the EPRI reports state (Section 5.7 in in EPRI report TR-107396 TR-l07396 and Section 8.4 in EPRI EPRI report 1007820) that performance report 1007820) performance monitoring monitoring is typically typically part of an engineering engineering program, program, which wouldwould not be part part of water chemistry.
Please see the response response to audit question question 95 (AMP B.1.40-4)
B.l.40-4) for additional component inspections information regarding component inspections in in closed cooling water systems.
98 B.1.41-1 (Water Chemistry-Primary AMP B.l.41-1 Chemistry-Primary & &
Secondary) . The Revision 4 changes to TR-105714 TR-1 05714 consider the most recent operating experience laboratory data. It reflects increased experience and laboratory increased emphasis on plant-specific plant-specific It is noted that Indian Point AMP B.l.41, It B.1.41, Water optimization optimization of primary primary water chemistry chemistry to address individual individual plant plant circumstances circumstances Chemistry ControlControl - Primary Primary and Secondary, Secondary, is and the impact impact of the Nuclear Nuclear Energy Institute Institute (NEI) generator initiative, (NEI) steam generator initiative, NEI based on the guidelines based guidelines provided provided in in EPRI TR- 97-06, which requires utilities to meet the intent of the EPRI guidelines. TR-1 05714, guidelines. TR-105714, 105714, 105714, Revision 5 and EPRI TR-l02134, TR-102134, Rev. 5 clearly distinguishes between between prescriptive non-prescriptive prescriptive requirements and non-prescriptive Revision 6. The corresponding corresponding GALL AMP XI.M2, guidance.
guidance.
Water Chemistry, Chemistry, is based on the guidelines guidelines provided in in Revision 3 of EPRI TR-105714 TR-105714 and Revision 4 of TR-102134 TR-102134 was issued in in November 1996 and provided increased provided an increased TR-102134. Provide details of the specific TR-l02134. specific. depth of detail detail regarding the corrosion mechanisms mechanisms affecting steam generatorsgenerators and and changes to these these documents documents after Revision 3. the balance of plant, and also provided additional additional guidance guidance on how to integrate integrate Include a justification as to how the adoption of the Include the these and and other concerns into the plant-specific other concems plant-specific optimization optimization process. Revision 5 later revisions impact the effectiveness effectiveness of the the regarding plant-specific provides additional details regarding plant-specific optimization optimization and clarifies which AMP to manage manage aging effects. . portions of the EPRI EPRI guidelines mandatory under guidelines are mandatory under NEI 97-06. Revision Revision 6 provided further details details regarding how how to best integrate these guidelines guidelines into a plant-specific chemistry chemistry program program while still ensuring ensuring compliance compliance with NEI 97-06 and NEI 03-08.
IPEC and other utilities provide input as well as review the recommendations recommendations and changes mademade to EPRI guidelines. Based on guideline guideline review against against the current current manufacturer recommendations, chemistry program, manufacturer recommendations, and associated station documents, changes are made made to chemistry controlling procedures procedures which are subject to the safety review process process (10 (10 CFR 50.59 process).
Consequently, the Water Chemistry Chemistry Control - Primary Primary and Secondary Secondary Program based based on current EPRI guidelines is made more effective effective at managing managing aging effects aging effects through proactive proactive implementation implementation of later revisions of the EPRI guidelines.
99 AMP B.l.41-2 B.1.41-2 (Water Chemistry-Primary Chemistry-Primary & & Consistent with EPRI TR-l TR-105714, 05714, Rev. 55 recommendations, recommendations, IP3 currently monitors monitors Secondary)
Secondary) . RWST sulfates monthly monthly with a limit of < 150 ppb. IP2 IP2 has not incorporated this this recommendation recommendation and an enhancement enhancement is required.
required. Thus, the enhancement enhancement does does The LRA Section B.l.41 B.1.41 lists an enhancement enhancement to not apply to IP3.
Attribute Attribute 3, 3, Parameters Parameters Monitored Monitored or or Inspected Inspected and Attribute Attribute 6, Acceptance Acceptance Criteria, which requires revision revision of appropriate IP2 procedures procedures to test sulfates monthly in in the RWST with a limit of <
150 ppb. Why is this enhancement enhancement only applicable applicable to IP2 and does not apply apply to IP3?
100 AMP B.l.41-3 B.1.41-3 (Water Chemistry-Primary Chemistry-Primary & & a) While chemistry requirements requirements are currently included in the IP2 Technical Secondary)
Secondary) Requirements Manual, Requirements Manual, the QA audit in in August 2003 was performed performed during the the improved technical specification improved specification project and updating the TRM for both units. At the the The The LRA Section B.l.41, LRA Section B.1.41, under Operating under Operating time of the audit, the IP2 TRM was not updated chemistry requirements.
updated with chemistry requirements.
Experience, states thai Experience, that aa QA QA auditaudit of the the primary primary
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Tuesday, March Tuesday, March 18, 2008 Page30 Page 30 of of 48 48
Item Request Response and secondary secondary plant chemistry chemistry program program was was department are performed b) QA audits of the chemistry department performed every 2 years. An conducted conducted in in August 2003 and this audit noted additional audit was performed performed in 20062006 to adjust the two year cycle to even number that monitoring and processing processing requirements for years for scheduling purposes. Both 2005 2005 and 2006 audit reports were provided provided primary secondary water chemistry complied primary and secondary during the audit.
with both IP2 and IP3 technical specifications, technical specifications, implementing procedures, implementing procedures, and the IP3 Technical Requirements Manual (TRM).
Requirements (a) Why is there no statement statement about compliance with IP2 Technical Requirements Manual?
Requirements Manual?
(b) The specific QA audit described described above was in in August August 2003. How frequently frequently are these QA audits performed?
performed?
103 103 Please provide 2006 Fire Water System Flow Test.
Please 2006 Fire Water System provided.
System Flow Test provided.
104 104 Provide Approval Package for SAO-703 rev 25.
Provide Approval Approval package package per EN-DC-128 EN-DC-128 provided for SAO-703, SAO-703, rev 25.
105 Are the IP3 foam tanks requiredrequired for compliance compliance CLARIFICATION RESPONSE provided in LR #410 (NL-08-014)
PLEASE SEE CLARIFICATION (NL-08-014) with 10 10 CFR 50.48. Why is the enhancement enhancement fo for*r foam tank inspection only applicable to IP3? The foam tanks for IP2 and IP3 are required required to comply with the requirements of 10 CFR 50.48. The Fire Water System Program will be enhanced enhanced to inspect inspect both IP2 IP2 and IP3 foam tanks.
Clarification to be incorporated incorporated into the LRA.
106 106 The enhancement enhancement for element 4 of the Fire Fire The Fire Water System Program enhancement enhancement to Element 4 will be revised revised to more Protection Program that appliesapplies to sprinkler sprinkler headheaid clearly reflect requirements of NFPA as follows.
reflect the requirements requirements per NFPA 25 states the nozzles nozzles aare re inspected.
inspected. NFPA requires requires the nozzle to be test testeded Replace the beginning of the first sentence which states "A sample Replace sample of sprinkler sprinkler or replaced. Inspections Inspections do not meet the Code heads required heads required for 10 CFR 50.48 50.48 will be inspected inspected using guidance guidance of NFPA NFPA..."
... " with with requirements. heads required for 10 "Sprinkler heads 10 CFR 50.48 will be replaced replaced or a sample tested using guidance guidance of NFPA...".
NFPA ... ".
Clarification to be incorporated incorporated into the LRA.
107 B.1.1: The The gas turbine turbine fuel storage ta anks were tanks This repair of pitting in the tank bottom was made in accordance with API Standard made in repaired following following the discovery of pitting pi tting in AI pril April 653 second edition, December 1999 1999 "Tank Inspection, Inspection, Repair, Alteration, Alteration, and 2002 using a weld weld overlay. What wa s the What was the Reconstruction".
Reconstruction". This is a nonsafety-related nonsafety-related tank. The GT 2/3 fuel oil storagestorage tank regulatory basis for this repair (e.g., Code regulatory Code repair, rep.air, has a repetitive repetitive task for an internal intemal inspection, inspection, and UT cleaning cleaning that is scheduled scheduled on approved code case, relief request) and and how willwill it a 1010 year year frequency frequency as described in the Above Ground Ground Steel Tanks Program.
on?
be handled extendeid operati(
handled for the period of extended operation?
108 B.1.2: Does IP2 and IP3 have bolting expert have a bolting expert as EPRI TR-104213, TR-104213, Bolted Joint Joint Maintenance Maintenance & & Applications Guide, recommends recommends recommended in the EPRI documents?
recommended documen ts? providing providing an on-site on-site bolting coordinator who has the technical ability and authority to bolting coordinator to focus on both programmatic programmatic issues and day-to-day day-to-day resolution of problems. IPEC IPEC Maintenance provides Maintenance provides the functions of the bolting coordinator coordinator consistent with the the guidance TR-104213.
guidance of EPRI TR-104213.
109 109 B.1.5:
B.1.5: Have Have you observed boric acid acid leakage from Both IP2 and IP3 have experienced experienced periodic Conoseal leakage during periodic Conosealleakage during the past few few Conoseal flanges?
flanges? cycles of operation.
operation. The most recent leaks occurred occurred at penetration #95 during the the current IP2 fuel cycle while the most recent leak at IP3 was detected detected during the the Spring 07 Spring 07 refueling refueling outage.
outage. As aa result of of these leaks, both IP2 IP2 and IP3 have IP3 have modification to the Conoseal implemented a modification Conoseal flanges to minimize minimize the probability probability of future leakage.
leakage. All of the recent recent leaks (with the exception of the current leak at penetration #95) penetration #95) have been eliminated and the affectedaffected areas of the reactor vessel head have been cleaned and and examined examined for signs of material degradation. None of material degradation.
these leaks have resulted in in any detectable detectable degradation of either either (IP2 and IP3) reactor vessel vessel head.
110 B.1.6: Do you have any buried tanks in scope scope for The following tanks are are buried and in in scope for license renewal and included included in the the license renewal? If If so, please identify them. Buried Piping and Tanks Inspection Program.
iP2 or IP3 had to replace Has IP2 replace any buried piping or IP2 Fuel Oil Storage Tanks (21/22/23 FOST) had to replace replace or repair repair any sections sections of buried buried GT1 Fuel Oil Storage NorthNorth and South Storage Tanks Tanks pipe? IP2 Security Diesel Fuel Tank IP3 Appendix IP3 Appendix R R Fuel Fuel Oil Storage Tank Oil Storage (EDG-33-FO-STNK)
Tank (EDG-33-FO-STNK)
IP3 Security Propane Fuel Fuel Tanks (2 of them)
Tuesday, March 18, 2008 Page 31 of 48
Item Request Response IP3 Fuel Oil Storage Storage tanks (EDG-31/32/33-FO-STNK)
(EDG-31/32/33-FO-STNK)
A review of site condition condition reports back to 2000 revealed revealed that there have been been two underground underground piping leaks that occurred occurred on the auxiliary auxiliary steam supply cross connect connect line between between Unit Unit 2 and and Unit 3. The first leak occurred in in 2002 and CR-IP3-2002- CR-IP3-2002-04267 was written for this leak. The leak was repaired via the work control process. process.
The second leak occurred in in April 2007 and and is documenteddocumented in in CR-IP3-2007-01852.
This line has been excavated and replaced. The cause of the failure was was determined to be advanced determined advanced corrosion corrosion of the pipe due to moisture intrusion. This This was caused by the pipe coating coating breaking breaking down and insulation insulation that was not sufficient sufficient for the task. After After replacement, the pipe was reinsulated using a special special high high temperature application moisture resistant material, temperature material, that was designed to prevent this type of corrosion in the future. This piping is nonsafety-related nonsafety-related and not in the the scope scope of license renewal. Copies of the condition reports were provided. No other other buried piping repair or replacement replacement was identified identified during review of operating operating experience.
111 Provide Fire Protection Protection System Impairment Impairment Provided the fire protection protection system impairment summary summary as of 6-1 6-10-07.0-07.
Summary. J 123 AMP B.1.23 (Non-EO (Non-EQ Inaccessible Medium- Medium- The Indian Indian Point service water cables are safety-related, safety-related, but are 480 VAC. As As Voltage Cable) stated in in the SandiaSandia report 96-0344, DOE Cable AMG, water water treeing treeing is a degradation phenomenon phenomenon that has been documented for medium-voltage medium-voltage electrical Why are cables for service water pump motors not not cable with certain extruded extruded polyethylenepolyethylene insulations and EPR insulations. Water included in the B.1.23 AMP? AMP? treeing has historically been more prevalent prevalent in higher voltage voltage cables; proportionately proportionately few occurrences occurrences have been noted for cables operated operated below 15 15 kV. This is likely likely due to the comparatively comparatively high high electric field density density and voltage gradient required for significant treeing to occur. However, water treeing in in medium-voltage medium-voltage cable cable operated below 15 15 kV has been documented. documented. The formation and growth growth of trees trees varies directly with operating operating voltage; treeing treeing is much less severe severe in in 4-kV cables cables than those operated operated at 13 or 33 kV. Due to the low dielectric stress, water trees do do not occur occur in in low-voltage cables. cables. Jackets and semiconducting semiconducting shields may substantially reduce reduce the ingress ingress of moisture and ion migration, thereby thereby reducing reducing the the rate of tree formation and propagation. propagation. New materials materials using ion scavengers scavengers may be be effective at further reducing reducing water tree growth. The DOE AMG typically defines defines medium voltage as 4 kV to 13.8 kV, but conservatively conservatively defines the lower value as 2 kV. NUREG-1801 NUREG-1801 and the license license renewal electrical handbook uses the lower value value of 2 kV.
The longer aa medium medium voltage cable is energized, the greater greater the likelihood likelihood that that moisture will affect the service life of the cable. Degradation Degradation of insulation materials materials due to "water treeing" is aa potential aging mechanism for underground underground medium voltage cables that are energized energized greater than 25% of the time and subject subject to moisture. Cables in in underground underground duct banks or conduits conduits are considered considered underground cables subject to moisture for the Indian Point IPA.
underground ]PA.
All of the Indian Indian Point safety-related safety-related power cables are 480 VAC, so there are are no no medium medium voltage circuits circuits that are safety-related. safety-related. The 480 VAC cables cables are not subject to water treeing; treeing; therefore, there are no aging aging effects effects requiring management management by the the Non-EQ Non-EO Inaccessible Inaccessible Medium-Voltage Medium-Voltage Cable AMP (B.1.23). The cables cables included in in the B.1.23 AMP are in scope scope for 10 10 CFR 54.4(a)(3) 54.4(a)(3) 124 124 AMP B.1.20 (Metal-Enclosed Bus Inspection) Inspection) As indicated in in LRA Section Section B.1.20, the "Metal-Enclosed "Metal-Enclosed Bus Inspection Program" is consistent consistent The LRA program program description description only discusses discusses with the inspection inspection methods described in NUREG-1801. NUREG-1801. The program description description in in visual inspections, but the enhancements enhancements to the the LRA Section B.1.20 will be clarified to describe the alternate tests and inspections inspections existing plant program discuss eXisting discuss visually inspecting discussed discussed in in NUREG-1801, NUREG-1801, Section Section XI.E4. Visual inspections inspections will continue to be be bolted connections every 5 years, or every 10 used for bolted bolted connections connections as appropriate.
years if using thermography. In In site document document for for the AMP evaluation, evaluation, items 3(b), 4(b), and 6(b) The The site AMP evaluation report will also also be clarified as discussed discussed for LRA B.1.20.
discuss only using visual inspections. The existing The program The program site procedure procedure for the 480 VAC bus uses micro- description, description, and Items Items 4(b), and 6(b) will be modified to address the inspection inspection ohm checks. methods besides besides visual visual that are discussed discussed in in NUREG-1801, NUREG-1801, Section Section XI,E4. XI.E4. Item 3(b) does not require require Why is only visual inspection discussed? Why are inspection discussed? aa change, since this item is consistent with NUREG-1801. NUREG-1801. The The inspection methods methods the other methods methods in in GALL XI,E4 XI.E4 not discussed?
discussed? used in the existing site site Provide additional Provide additional discussion discussion for for the the otherother procedures will be reflected in in the site AMP evaluation report.
inspection methods addressed inspection addressed in in GALL, or or provide the basis for not including provide including the other other LRA Section B.1.20, Metal Enclosed Enclosed Bus Inspection, Inspection, Program Description, second second methods. paragraph, and the enhancements enhancements are revised revised as follows.
~"'*::r~:;'&'~:Am:r::,&:~;m~,~~~~~~,~:~.',~'ll<' ,~':~~*,.:(Kt' , , w >'>,~~1/",~, " ,,,,i,:.,~,,,,,,~ "' "~,~:r~B~:,~'),u,~:':\~~:t~~~:ill.~tl~~~'X~~'l~t\r.&mMm:~*:i~m;::::o~;M";;.':'::r:':;;..t:'--:;~~~:::;;~~~':',l ;<lll~ll%:%~ill'::2.:~'A0<<<<Wh:':'O':~~~::**.'- " "\{;':;-::."1it*:;:';ilim Tuesday, Tuesday, March March 18, 18, 2008 Page 32 of 48 Page 48
Item Request Response Program Description Program Description Inspections of the metal Inspections metal enclosed bus (MEB) (MEB) include include the bus and bus connections, the bus enclosure enclosure assemblies, assemblies, and the bus insulation insulation and insulators.
insulators. A sample of the accessible bolted connections connections will be inspected inspected for loose connections.'
connections. The bus bus enclosure assemblies assemblies will be inspected inspected for loss of material and elastomer elastomer degradation. This program will be used used instead Monitoring instead of the Structures Monitoring Program for external surfaces of the bus enclosure assemblies.
Program assemblies. The internal portions of the MEB will be inspected for foreign debris, excessive dust buildup, and evidence of moisture intrusion. The bus insulation insulation or insulators are inspected inspected for degradation leading to reduced insulation resistance degradation resistance (IR). The bus insulation will be be inspected for signs of embrittlement, cracking, inspected cracking, melting, swelling, swelling, or discoloration, which may indicate overheating or aging degradation. The internal bus supports or indicate overheating or insulators will be inspected insulators inspected for structural structural integrity integrity and signs of cracks and corrosion.
These inspections include include visual inspections, as well as quantitative measurements, measurements, such as thermography or connection resistance resistance measurements, as required.
Enhancements Enhancements Attributes Affected: 3. Parameters Parameters Monitored or Inspected; Inspected; 4. Detection Detection of Aging Aging Effects; Effects; 6. Acceptance Acceptance Criteria Criteria appropriate procedures Revise appropriate procedures to visually inspect inspect the external external surface of MEB MEB enclosure assemblies for loss of material at least once every 10 years. The first enclosure assemblies inspection inspection will occur prior to the period period of extended operation and the acceptance extended operation acceptance criterion criterion will will be be no significant significant loss of of material.
material.
Attributes Affected: 4. Detection Detection of Aging Effects Effects Revise appropriate procedures to inspect bolted appropriate procedures bolted connections connections at least least once every five every five years if only performed visually or at least once years quantitative every ten years using quantitative once every measurements such as thermography or contact resistance resistance measurements.
measurements. The The first inspection inspection will occur occur prior to the period of extended operation. operation.
LRA Sections A.2.1.19 and A.3.1.19, Metal Enclosed Bus Inspection Program, second paragraph, is revised revised as follows.
Inspections of the metal enclosed bus (MEB)
Inspections (MEB) include the bus and bus connections, the bus the bus enclosure enclosure assemblies, assemblies, and and thethe bus bus insulation insulation and and insulators.
insulators. A A sample sample of of the accessible bolted bolted connections will be inspected inspected for loose loose connections.
connections. The bus bus assemblies will be inspected enclosure assemblies inspected for loss of material material and elastomer degradation. This program program will be used instead of the Structures Monitoring Structures Monitoring Program for Program for external surfaces of external surfaces of the busbus enclosure enclosure assemblies. The The internal portions of the MEB will be inspected for foreign debris, excessive excessive dust buildup, and evidence of moisturemoisture intrusion. The bus insulation or insulators insulators are inspected for degradation leading degradation leading to reduced insulation to reduced insulation resistance resistance (IR). These inspections (IR). These inspections include visual inspections, inspections, as well as quantitative measurements, such as quantitative measurements, as thermography or connection resistance measurements, connection resistance measurements, as required.
LRA Sections A.2.1.19 A.2.1.19 and A.3.1.19, Metal Enclosed Enclosed Bus Inspection Inspection Program, third paragraph, second bullet is revised as follows.
paragraph, Revise appropriate procedures Revise appropriate procedures to to inspect inspect boltedbolted connections connections at at least least once once every every five five years ifif only performed performed visually or at least once every ten years using quantitative quantitative measurements measurements such as thermography thermography or contact contact resistance measurements.
measurements.
Clarification Clarification to be incorporated incorporated into the LRA.
125 125 AMP B.1.20 (Metal-Enclosed (Metal-Enclosed Bus Inspection) Inspection) The site operating experience experience review review report report listed operating operating experience obtained from the condition report system. The issue at IP2 in in 2006 2006 was found during the the The site document for the AMP operating operating performance of the non-safety related related 6.9 kV Bus 4 PM. Degradation Degradation was found on experience experience discusses discusses items found in in the bus IP3 the load side of the heater heater drain pump motor motor cables. The The damage to the cable cable 480 V Switchgear. Provide Provide additional additional details details for jacket/insulation was due to vibration of a support plate, and the cable degradation jackeUinsulation degradation this incident and explain why this incident was not was repaired.
repaired. The degradation degradation was minimal, and the function of this cable was was not not detrimental to the System function. affected.
affected. This CR was associated associated with 6.9 kV switchgear, which is not associated with the metal enclosed bus. This OE CE is an example example of a design issue or a maintenance issue.
maintenance The issue at The issue at IP3 IP3 inin 2003 2003 waswas foundfound during during the the performance performance of the the safety-related safety-related 480480 V Bus 5A PM. A switchgear separation separation barrier plate was found lying loose in the loose in the back of the switchgear switchgear cabinet. Also, a piece of cable approximately 10 inches cable approximately inches long was found lying in the bottom bottom of the switchgear cabinet. These were maintenance maintenance issues and the actions were were to remove the section of cable, and attach attach the plate plate based on the design configuration. configuration.
~'W~~~,~ ~~~"'.~\'*.::::;.:(~~~':1;yJt;f;~Y.~,t' . . .,,;:::,,:~, Hl~~,:,>,~.t:::>?}~<~,'::s,r~tm~mt ..::,;'1;,@g%ms,;m.n~~xr::;~:<:,X'i:,~a,;,;;~",'t.-:::-:w.,:tZ:"':~':::,f::; -:TI~~ZW~~::'~:~:.,~::~\::::::"'T,;:b.
Tuesday, March Tuesday, March 18, 2008 Page 33 of 48 Page
Item Request Response 126 Please Please provide copies of recent self assessments Provided Provided copies copies of QA-08-2005-IP-1, QA-08-2005-IP-1, "IPEG "IPEC Unit 3 Engineering Engineering Programs Audit,"
of the Inservice Inspection Program. 5/5/2005; LO-WPOLO-2004-00051, 5/5/2005; LO-WPOLO-2004-00051, "lSI "ISI Snapshot Assessment Assessment for IPEG," IPEC,"
110/19/2004; LO-WPOLO-2005-00046, "IS1 0/19/2004; and LO-WPOLO-2005-00046, "lSI Snapshot Snapshot Assessment for IP2,"
04/28/2005. .
127 127 B.1.9:
8.1.9: In In section 4.5 of LRD07 LR007 under under program The program description description provides a general general description description of what the program program will do do description description itit states that thickness measurements after all enhancements enhancements are implemented. implemented. This is in in accordance accordance with NE195-10 NEI 95-10 of storage tank bottom surfaces verify degradation degradation Appendix D D for application application format and NUREG-1800 NUREG-1800 Table 3.3-2 which provides provides is not occurring. This This implies that measurements measurements guidance guidance for what a program description should include. Enhancements and are are being currently currently being performed. performed. Does this exceptions exceptions are not discussed discussed in this section section of the document document but are presented presented in in need to be revised to say after enhancements are after enhancements each each of the elements elements that have the exceptions and enhancements.
completed?
completed?
128 128 B.1.9: In In section 4.5 of LRD07 LRD07 section section B.2.a Procedure 0-GY-1810 0-CY-1810 covers the monitoring monitoring of all diesel diesel fuel oil on site and has a GALL GALL says periodic draining draining of water collected collected at specification specification of "none "none detectable" for the tank bottom sample. When water has been the bottom bottom of tanks minimizes minimizes amount of water. detected, detected, it has been removed in the past by direction of a supervisor. The sampler How is this addressed in in 8.1.9?
B.1.9? What procedures itself has been utilized in in the past to remove water water while obtaining aa sample.
perform this draining or water water removal at IIPEC? PEG? Chemistry procedure procedure 0-CY-3340 0-CY-3340 OPERATION OPERATION OF THE GORMAN-RUPP GORMAN-RUPP TANKLEENOR TANKLEENOR could be utilized if larger larger amounts of water water were encountered. O-CY- 0-CY-1810 will be enhanced to include include directiondirection to remove remove water from the tank bottom if detected. In addition the revision detected. revision will direct direct thesamplethe sample be taken near the tank bottom for water detection.
Information to be incorporated Information incorporated into the LRA.
129 129 B.1.9: In In section section 4.5 of LRD07 section section B.2.a 8.2.a in the Attachments Attachments 2 and 44 provide the location of the sample points for fuel oil storage section that discusses sampling sampling of the fuel oil components. ItIt includes includes the sample locations for the following fuel oil storage storage tanks tanks tanks near the bottom to determine determine water content but does not specifically specifically state the samples samples are to be taken taken on the bottom of the the itit refers to procedureprocedure 0-GY-1500 0-CY-1 500 attachment 4. tanks: (
This procedure procedure does not appear to discuss discuss sampling near the bottom of the tanks. Why is this IP2 EDG EDG Day tanks (21/22/23), IP2 IP2 Fire protection protection diesel fuel tank, GT1 Fuel Oil procedure a reference reference and ifif so should itit discuss South and North tanks, GT2&3 GT2&3 Fuel Oil Tank, IP3 EDG fuel oil day tanks tanks sampling location? (31/32/33), IP3 Fire Pump Fuel oil tank tank,, IP2 Underground Emergency Diesel Fuel Underground Emergency Oil Tanks and the IP3 Appendix Appendix R Fuel Oil Day tank.
Attachment 1 of procedure procedure O-GY 0-CY-1810 -1810 includes includes a requirement for a bottom sample sample of the IP2 IP2 and IP3 EDG bulk fuel oil storage tanks (21/22/23/31/32/33) (21/22/23/31/32/33) and the GT1, GT1, 2, andand 3 storage tanks since procedure 0-CY-1500 0-GY-1500 lists a composite composite sample sample and not a specific specific sampling point. ItIt doesn't however specify that the remaining remaining tanks tanks sampling is to be taken near the bottom of the tank. Appropriate Appropriate procedures procedures will be be revised to specify sampling tanks in this program near the bottom bottom of the tank.
This requires an ehancement to the Diesel Fuel Monitoring Monitoring program B.1.9.
Information Information to be incorporated incorporated into the LRA LRA 130 B.1.9:
8.1.9: In section 4.5 of LRD07 section B.3.a GALL As stated in in the last three sentences sentences of B.3.b of section 4.5 of IP-RPT-06-LRD-07, IP-RPT-06-LRD-07, says ASTM D1796 and D2709 D2709 are used used for ASTM standardsstandards D1796 D 1796 and D2709 are standards standards for the determination determination of water determination determination of water and sediment. IPEC IPEG only and sediment for different viscosities of fuel oil. ASTM standard D1796 is the the uses ASTM D1796 01796 and not 02709. D2709. Why is this this appropriate appropriate standard for the ASTM-2D fuel oil used at IPEG. IPEC. ASTM standard D2709 D2709 acceptable?
acceptable? (water and sediment sediment by centrifuge centrifuge for lower lower viscosities) is not applicable applicable for the fuel oil used used at IPEC.
131 131 B.1.9: In In section 4.5 of LRD07 LRD07 section section B.6.a GALL ItIt is acceptable acceptable to not use ASTM D6217 because because use of ASTM D2276 is a more says ASTM D 6217 and modified D2276 are conservative conservative method method to measure the same parameter. ASTM D6217 is a laboratory used. IPEG IPEC only uses ASTM D2276 and not method for middle distillate fuel particulate particulate distillation. distillation. This methodmethod uses a smaller D6217. Why is this acceptable? acceptable? volume volume of sample passing passing over the filter membrane. membrane. As referenced referenced in ASTM D6217, "Test Method
'Test Method D5452 and its predecessor Test Method D2276 were developed Method 02276 developed for aviation aviation fuels and used 1 I gal or 55 LL of fuel sample. Using Using 1 gal of a middle distillate distillate fuel, which can contain greater particulate levels, often required excessive time greater particulate time to complete the filtration. The The D6217 test method used about a quarter of the volume volume used in the D2276 method." Both of the methods methods use the same filter size of .8 microns. The difference in in filtering aa larger volume volume for a longer time using the ASTM D-2276 method is actually more conservative.
0-2276 conservative.
LRA Section B.1.9, B.1.9, second second paragraphparagraph of exception exception to Element Element 6 will be revised as as follows.
determination of particulates, For determination particulates, NUREG-1 NUREG-1801 801 recommends use of modified modified ASTM Standards D2276 D2276 Method Method A and D6217. Determination of particulates is according according to ASTM Standard Standard D2276.
LRA Section B.1.9, B.1.9, exception exception note note 4, will be revised as follows.
Determination of particulates Determination particulates is according to ASTM Standard Standard D2276 which conducts conducts
">.~~~ ~":/'.:',,{".<i::"'J~I\*i:~* ,~,'~:~'~,r;~~i'i:::'t,~ "h",' * " *;;';~~:YtB:;:"m:,m~ll~,*,"';:"'~,,,,' . ",' *"L'i;~::::~mm:>.~::m~mm~N~:-kw:-:;:0:~;.,s;';.."'t.N:ffitt.{;{::;l)~~~.J.. '~" m::::~l; T~~r.::~:\-:;, l"~mW~~l~w~mm~,~ l~~,>%t'$.\*:"\~;i*1';%Uf-m:mm:it ~~\:y,"~',,&,,'1>n,':,,;:::,~:::\~:q::::i\
Tuesday, March Tuesday, March 18, 2008 Page Page 34 34 of of48 48
Item Request Response
Response
particulate analysis using a 0.8 micron micron filter, rather rather than the 3.0 micron filter specified inin NUREG-1801.
NUREG-1801. Use of a filter with a smaller pore size results in aa larger sample of particulates particulates since since smaller particles particles are retained.
retained. Thus, use of a 0.8 0.8 conservative than use of the 3.0 micron filter specified in micron filter is more conservative in NUREG-1801. ASTM 06217 NUREG-1801. D6217 applies applies to middle middle distillate fuel using a smaller volume volume of sample sample passing passing over the 0.8 micronmicron filter. Since Since ASTM ASTM D2276 determines 02276 determines particulates with aa larger larger volume passing through the filter for a longer longer time than the the D6217 method, use of D2276 06217 02276 only is more conservative.
conservative.
Clarification to be incorporated incorporated into the LRA.
132 B.1.9: Procedure Procedure 2-CY-1 560 for IP2 hhas 2-CY-1560 as asas There There is not an IP3 procedure directing directing when to add biocide biocide to the IP3 fuel oil tanks.
section 4.5 that has a step to add che micals to the chemicals the Prior to integration of the units, the procedure procedure already already existed at Unit 2. Procedure Procedure fuel oil storage storage tanks ififdetermined determined ne cessary by necessary integration focused on the type of chemicals integration chemicals to be added; added; it did not explicitly Chemistry. There appear to be a similar There does not appear similar evaluate the method or timing of the chemical chemical addition.
step in any IP3 procedure but there is a procedure procedure An enhancement enhancement will be added added to combine the direction from 3-CY-2615 and 2-CY-3-CY-2615 for adding chemicals chemicals to fui el oil tanks.
fuel 1560 1560 into aa O-CY 0-CY series procedure for the addition of chemicals including including biocide on on Does this exist inin an IP3 procedure and IP3 procedure annd ififnot why both units when the presence of biological activity is confirmed.confirmed.
difference?
the difference?
Information Information to be incorporated into the LRA.
133 B.1.20: (Metal (Metal Enclosed Bus) The aging management management program evaluation evaluation report for the "Metal Enclosed Enclosed BusBus Inspection Inspection Program, which is described in LRA Section Section B.1.20, B.1.20, does not require require "re-The site document document for the AMP evaluation evaluaation torquing" connections. The plant staff acknowledged that the practice of "re-staff acknowledged references a site procedure references procedure for performing perfon "ming torquing" connections connections is not a good practice, and was not intended to be performed. performed.
480VAC metal enclosed enclosed bus inspectio inspections.ns. One One of "Re-torquing" connections connections is not recommended recommended in in EPRI documents for phase bus bus the steps discusses discusses "re-torquing" coni nections.
connections. maintenance and bolted connection maintenance.
maintenance maintenance. The plant will process process a change change Why is re-torquing re-torquing acceptable?
acceptable? to the site procedure procedure to remove remove the reference to "re-torquing" connections.
148 Service Service Water Water Integrity At the time SEP-SW-001 was being developed, a corporate being developed, corporate procedure (EN-DC-1 (EN-OC-184) 84)
Inspector EN-DC -184 referred Inspector requested a copy of EN-OC-184 was also being drafted to apply to all 10 10 Entergy plants. EN-OC-184 EN-DC-184 would have have SEP-SW-001 in to in SEP-SW-001 1.1 in section 1.1 included included all the requirements requirements that SEP-SW-001 SEP-SW-001 presently presently provides. However, However, some some plants had issues with the corporate corporate procedure, procedure, and it it has not yet been finalized or approved. It should be noted that the corporatecorporate procedure drafted at the time SEP-procedure drafted SW-001 was originally SW-001 originally issued would not have added any additional additional requirements to the IPEC SW program, program, such that SEP-SW-001 SEP-SW-001 was and is being being correctly correctly and and effectively implemented effectively implemented at this time.
Procedure Procedure SEP-SW-001 SEP-SW-001 states that the site procedure aligns with the corporate corporate procedure EN-DC-184. This is an incorrect procedure EN-OC-184. statement since there is no corporate incorrect statement corporate procedure procedure for service water programs. Since Since there is no impact on the site program from this discrepancy, this error will be corrected corrected during the next procedure procedure review and revision.
A copy of rev. 1 to SEP-SW-001 SEP-SW-001 and the IPEC IPEC response letters to Generic Letter 89-13 were provided to the inspector.
149 149 Impairment summary for fire protection systems (6- The utility tunnel HP fire header is presently presently isolated as the result of discovery discovery of 10-2007) indicates indicates that the "Utility tunnel HP fire fire piping section(s) that have degraded below minimum allowable have degraded allowable wall thickness. The The header has less than minimum wall thickness and loop segmentation segmentation capabilities capabilities of the HP fire water loop enableenable the required fire fire header isolation". What is the.relationship the~relationship to the the protection water supplies to safety-related safety-related and safe-shutdown safe-shutdown related plant areas to HP fire water system and the root cause? (See be maintained, maintained, despite the isolation of the utility tunnel header.
enhancement enhancement regarding regarding wall thickness thickness evaluations) (See B.1.14 Operation Operation Experience Experience degradation of carbon steel piping within the utility tunnel (city water The degradation water and firefire section RE: No evidence of loss) protection headers) was determined determined to be caused by chronic in-leakage in-leakage of ground water into the tunnel, causing external external corrosion of the city water and fire protection piping.
Engineering evaluations have been Engineering been developed developed and work orders planned to address address the cause by sealing sealing the leaking penetrations/openings into leaking penetrations/openings into the utility tunnel, thereby minimizing further minimizing further water intrusion intrusion and contact with piping surfaces.
surfaces.
In addition, In addition, the city water piping will be encapsulated encapsulated with a proprietary proprietary piping wrap and coating restoration system that will restore the structural hydraulic integrity structural and hydraulic of the city water water piping, piping, and provide an exterior exterior surface surface that will be resistant to to corrosion.
corrosion.
A similar modification modification is being evaluated for restoration restoration andand protection protection of the Fire Protection piping Protection piping in the utility tunnel. The sealing of the utility tunnel wall and ceiling penetrations as described penetrations described above will eliminate the water intrusion and source of the the exterior corrosion.
corrosion. The installation of the modification modification to seal the utility tunnel wall Tuesday, March 18, 2008 Page 35 of 48
Item Request Response penetrations is scheduled and ceiling penetrations scheduled for completion during 2007.
The Fire Water System Program manages manages aging effects for components exposed to treated water (fire water) on internal surfaces. The external surface surface of fire water components is managedmanaged by the External Surfaces Monitoring program. Since the Monitoring program. the loss of material material described described inin this operating operating experience experience was on the extemal external surface surface and caused by water experience is not water intrusion, this operating experience not applicable applicable for thethe Fire Water Water System Program.
150 exception to NUREG-1801 The exception NUREG-1801 for B.1.13 B.1.13 The current current functional functional testing frequencies of the IP2 IP2 cable spreading spreading room HalonHalon regarding the frequency frequency of functional testing of. of, system and and the IP3 cable spreading spreading room, IP3 480V switchgear switchgear room and IP3 IP3 Halon (IP2) 6-months to 18 (IP2) and C02 (IP3) from 6-months Diesel Generator Building Building C02 systems is as follows:
and 24 months respectively respectively does not provide the the station/system station/system specific specific operating operating history. What is . IP2 cable spreading spreading room Halon system - once per 18 months months engineering basis and justification for these the engineering specific systems? IP3 cable spreading spreading room, IP3 480V switchgearswitchgear room and IP3 Diesel generator generator building building C02 systems systems - once once per 24 months with the exercising of fire dampers dampers which form the boundary boundary of the protected protected enclosures enclosures at once per 12 months.
A review of past performed performed functional testing testing of these systems hashas indicated no no adverse degradation that requires adverse indications of material degradation requires adjustment of the testing frequencies. (ref. PT-EM PT-EM19,19, 3-PT-2Y004 3-PT-2Y004 and 3-PT-2Y005). The condition condition reporting reporting database similarly reviewed database was similarly reviewed and revealed revealed no adverse indications of material adverse indications degradation.
degradation.
The original original licensing licensing basis basis for for the functional testing testing frequency frequency ofof C02 and Halon Halon 151 What is the original licensing basis for the the The the functional C02 and functional testing frequency of C02 and Halon systems at IP2 IP2 and IP3 are as follows:
systems at IP2 and IP3?IP3?
IP2 IP2 The cable spreading spreading room Halon system was was installed as part of the plant plant modifications to improve the fire protection program program resulting from reviews against BTP APCSB 9.5-1, 9.5-1, Appendix A. Limiting conditions conditions for operation operation and surveillance surveillance requirement were subsequently subsequently developed developed for this system and approved approved by the NRC NRC under Amendment Amendment 64 to the FOL (ref. (ref. SER dated October 31, 1980). The functional October 31, test frequency frequency was once once per 18 months. This frequency frequency is currently currently maintained maintained in in the the administrative procedure SAO-703.
administrative procedure SAO-703.
IP3 IP3 The cable spreading spreading room, 480V switchgear room and Diesel generator building C02 systems were installed installed as part of the plant modifications modifications to improve the fire fire protection program resulting from reviews reviews against against BTP APCSB 9.5-1,9.5-1, Appendix Appendix A.
Limiting conditions surveillance requirement were conditions for operation and surveillance were subsequently subsequently developed for these systems and approved developed approved by the NRC under'Amendment NRC under' Amendment 45 to the the FOL (ref. SER dated dated November 18, 18, 1982). The functional test frequency was once once per 18 months.
A change change to the functional functional testing frequency for these systems was subsequently testing frequency subsequently proposed proposed and approved by the NRC under Amendment 146 to the FOL (ref. SER under Amendment dated April 20, 1994) 1994) to accommodate operation within a 24 month operating operating cycle.
The functional functional test frequency was changed to once per 24 months with with the the exercising exercising of fire dampers which form the boundary of the protected protected enclosures enclosures at at once per 12 months. These frequenciesfrequencies are currently currently maintained in in the IP3 TRM (Ref.
(R.ef. TRO 3.7.A.7 3.7.A.7 152 What is the justification justification for excluding firewater excluding the firewater The fire water jockey/maintenance jockey/maintenance pumps support standby operation operation of the fire fire jockey/ maintenance maintenance pumps from the scope scope of the the water system and are conservatively included in the scope of license renewal and HP fire water systems (B.1.14)?
(B.1.14)? subject subject to aging management management review. The Fire Water System Program manages manages component component aging effects. However, the jockey/maintenance jockey/maintenance pumps are not required required These are not identified in in : for operation operation of the fire water system to comply with 10 10 CFR 50.48 and Appendix Appendix R.
SAO-703, SAO-703, rev25 (IP2) A.1 Therefore, Therefore, prescribed testingtesting per SAO-703, SAO-703, TRM and AP-64.1 AP-64.1 is not required.
Section Section 3.7.A.1.7 and 3.7.A.1.8 3.7.A.1.8 of the IP3 TRM AP-64.1 Rev. 22 Appendix R R SSCs 153 153 A "cross-connect" of the HP fire water system IP2 and IP3 maintain independent independent fire protection systems systems and the "cross connect" is exists between between Units 1, 1, 2, and 33 individual fire fire not considered considered for compliance with IP2 or IP3 fire protection protection requirements.
requirements.
water supply supply systems. Has creditcredit been taken for the use of this capability per the CLB? (B.1.14)
Tuesday, March 18, 2008 Page36 0'48 Page of 48
Item Request Response 154 154 B1.11 (External Surfaces B.1.11 Surfaces Monitoring)
Monitoring) Attachment Attachment 9.1 includes a line item of paint paint and preservation preservation which which would would Under attribute attribute "Parameters "Parameters Monitored Monitored and encompass coating degradation degradation and corrosion/material corrosion/rnaterial wastage wastage since since ififthe paint is Inspected", examples of parameters parameters inspected are intact and the equipment equipment properly preserved coating degradation degradation and provided and a reference reference is made made to the systerns systems corrosion/material wastage corrosion/material wastage would not be present. Attachment 9.1 also includes aa walkdown walkdown procedureprocedure attachment attachment 9.1. 9.1. The The beginning that the guidelines statement at the beginning guidelines are not all inclusive. This is also guidelines guidelines in the attachment attachment do not appear to documented documented in in attachment attachment 9.2 which is aa checklist that identifies paint and cover cover attributes of coating degradaton and preservation as potential potential items of concern. As stated in section 1.0 EN-DC-178 a 1.0 of EN-DC-178 corrosion/material wastage. Clarify ifif these corrosion/material system walkdown walkdown is aa detailed look at system material condition system material condition which would include include attributes are reviewed during system walkdowns. the attributes attributes of coating degradation corrosion/material wastage regardless of itit degradation and corrosion/material It is noted that the enhancernent It enhancement will revise revise identified as an inspection item.
being specifically identified documents to require periodic inspection guidance documents inspection of systems systems in in scope and subjet to an AMR. Will the revision include inclusion of these attributes? attributes?
155 B.1.11 (External B.1.11 Surfaces Monitoring)
(External Surfaces Monitoring) The use use of the condition of external external surfaces to provide an indication indication of the condition condition Under the attribute Under attribute "Detection of Aging Effects" a surfaces is acceptable of internal surfaces acceptable when the external environment environment is outdoor outdoor airair list of components and environments environments is given given for because the external environment because environment is much much more aggressive. Therefore, Therefore, ifif visual visual those AMMs where visual inspection of the the inspections of the external surface inspections surface are are not experiencing experiencing loss of material, the internal external surfaces surfaces is credited credited for internal surfaces. surface is assured to be in good conditioncondition due to the milder internal environment.
In two cases, the internal environment In environment is given as given as indoor air, but the external environment environment is given given as air-indoor air-indoor or air-outdoor. Explain why why this is acceptable?
acceptable?
156 B-1.15 (FAC):
B.1.15 (FAC): The program program description description provided Indian Indian Point utilizes Revision Revision 3 of NSAC 202L.202l. As indicated in in NSAC 202L, for AMP B.1.15 in the LRA states that the program Revision Revision 3, the new revision revision of EPRI incorporates lessons learned and EPRI guidelines incorporates and is based on the guiddelins guiddelins of EPRI NSAC-202L- NSAC-202L- improvements improvements to detection, detection, modeling, modeling, and mitigation technologies technologies that became became R2. The review of Indian Point Procedure EN-DC- EN-DC- available available since since Revision 22 was published.
published. The updated recommendations recommendations refine refine 315, rev. 0 Flow Accelerated Accelerated Corrosion Program and enhance enhance those of previous revisions without contradicting contradicting existing existing plant FAC provided provided during the site audit, references references "latest" "latest" programs.
programs. An exception exception to GALL was not taken since implementing implementing the elements of revison of this document which is revision 3. Revision guidelines did not create program Revision 3 guidelines program deviations from the guidelines in in Since the guidelines guidelines provided in in two revisions of Revision Revision 2 and the requirements specified in GALL are being met with Revision 3 of specified in NSAC-202L NSAC-202L are different, different, address address which hrevison hrevison NSAC-202L.
NSAC-202L. A review of the FAC program affected by Revision program elements affected Revision 3 of the document document is applicableapplicable to Indian Indian Point FAC changes is provided provided as follows showing showing the changes had minimal impact on the the Program.
Program. If If Indian Point utilizes Rev. 3 of the the program.
program.
NSAC NSAC document, document, the LRA should list this as an exception exception and include a justification for the use of Element (1), Scope of Program - The differences differences of Section 4.2, Identifying Identifying the later revision to establish consistency with establish consistency Susceptible Susceptible Systems, between Revision 2 and Revision 3 are mostly editorial. The The GALL Report. guidance guidance of prioritizing prioritizing the system for evaluation evaluation in Section 4.2.3 of Revision 2 is addressed addressed in Section Section 4.9 of Revision Revision 3. Section Section 4.4, Selecting and Scheduling Components Components for Inspection, Inspection, of Revision 2 was re-organized re-organized in in Revision 3. Sample Sample modeled lines selection for modeled non-modeled lines of Revision 2 was enlianced lines and non-modeled enhanced with clarification and more more clarification more details in Revision 3. Guidance for using plant experience and industry industry experience in selecting inspection locations was added in selecting inspection Revision 3. The basis for sample expansion was clarified clarified in in Revision Revision 3. Instead of dividing into selection selection of initial inspection and follow-up inspections inspections in Revision 2, the guidance guidance in in Revision 3 is provided provided for a given outage including including thethe recommendations for locations of re-inspection. This is more compatible with the recommendations the schedule of the implementation implementation of FAC program during outages.
Element (4), Detection of Aging Effects Element Effects - Clarification Clarification of the inspection inspection techniques techniques of UT and RT was added in in Section Section 4.5.1 of Revision 3. There are no changes of the the guidance for UT grid. Appendix guidance Appendix B B was added added inin Revision 33 to provide provide guidance for for inspection of vessels and tanks. This is beyond the level of detail provided in inspection Revision Revision 22 and in in the GALL GALL report. The guidance for inspection inspection of small-bore small-bore piping in Appendix A of Revision Revision 22 and of Revision Revision 3 are essentially essentially identical. The identical. The guidance for inspection inspection of valves, orifices, and equipment nozzles was enhanced in in Section 4.5.2 4.5.2 of Revision Revision 3. Also, Section Section 4.5.4 was added for use use of RT to inspect large-bore piping, Section large-bore Section 4.5.5 was added for inspection of turbine cross-around cross-around piping, and Section Section 4.5.6 was added for inspection inspection of valves valves Clarification to be incorporated Clarification incorporated into the LRA.
157 Fire Barriers Barriers accessible fire barrier All accessible barrier penetration seals are visually inspected at least once every seven operating cycles (approximately (approximately 15% per 24 months operating operating cycle). During During What is the current frequency frequency of inspection inspection for fire fire inspection interval, each inspection interval, at least 10% of each type of seal is inspected.
inspected.
barrier penetrations penetrations and what is the % sample to be inspected?
inspected?
158 Fire Barriers Barriers The failure mode mode cited in in Generic Letter 2006-03 shrinkage 2006-03 specifically the potential shrinkage of the outer covering, exposing the interior surfaces or layers to the fire, relate to the the
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Tuesday, March 18, 20i08 2008 Page 37 of 48
Item Request Response Fire separation barrier inspections (2-PI-QO01 inspections (2-PI-0001 performance and performance and response response of aa Hemyc fire barrier wrap under fire conditions which Rev. 8) acceptance acceptance criteria does not include a were installed installed in in accordance accordance with vendor requirements. These requirements were requirements were specific failure mode of HEMYC HEMYC fire barrier wrap similarly used during the installation installation of the Hemyc fire barrier wrap at IP2 and and IP3.
identified in GL 2006-03. Specifically Specifically the potential 5 hrinkage of the outer layer fabric (Refrasil) that shrinkage Periodic Periodic test 2-PI-QO01 2-PI-0001 ensures through a visual inspection inspection that the material c(ould expose the interior layors could Kawool . Is this layors of Kawool. condition condition of the wrap wrap is satisfactory (i.e., the wrap is not missing, punctured punctured or torn, guidance (GL 2006-03) guidance 2006-03) incorporated into into the the wrap is* is not oil soaked or shows evidence of other chemical contamination contamination and arrier inspection bbarrier inspection program program and specifically specifically where?
where? that it is properly properly banded as required), thereby thereby consistent consistent with the initial pre-fire pre-fire condition.
condition.
159 159 B 1.1.23 B.1.23 LRA Section B.1.23 and the site AMP evaluation evaluation document document state this program program is a ) Item 3(b) of the site AMP evaluation document a) document consistent NUREG-1801, XI.E3 without exceptions or enhancements.
consistent with NUREG-1801, enhancements.
re eferences an EPRI document instead of listing references listing xamples of types of tests that could be performed eexamples a) a) The AMPAMP evaluation evaluation document for the Non-EQ Non-EO Inaccessible Medium-Voltage Inaccessible Medium-Voltage imilar to those provided similar provided in GALL. Provide Provide Cable, Item 3(b) will be clarified to provide provide examples examples of tests.
in nformation so a determination information determination can be made for C onsistency of the EPRI document consistency document and the GALL Current xample programs.
eexample "The specific type of test performed "The performed will be determined determined prior to the initial test. The The test will be aa proven test for detecting detecting deterioration deterioration of the insulation insulation system due to BI) Item 4(b) of the site AMP evaluation B) evaluation document document wetting as described described in in EPRI TR-103834-P1-2 TR-1 03834-P1-2 or other testing that is state-of-the-art state-of-the-art tates that an engineering states engineering evaluation evaluation will be at the time the test is performed."
erfomed to determine perfomed determine the proper frequencyfrequency for n ianhole inspection.
manhole inspection. Provide information for how Proposed tI his will use OE to justify the frequency.
this The specific type of test performed performed will be determined determined prior to the initial test, and is to be a proven proven test for detecting detecting deterioration deterioration of the insulation system due due to wetting, such as power power factor, partial discharge, polarization index, discharge, or polarization index, as described described in EPRI TR-103834-P1 -2, or other testing TR-103834-P1-2, testing that is state-of-the-art state-of-the-art at the time the test is performed.
b) The AMP evaluation document for the Non-EO Non-EQ Inaccessible Inaccessible Medium-Voltage Medium-Voltage Cable, Item 4(b) will be modifiedmodified to clarify the use of site OE for the frequency of manhole inspections.
inspections.
Current Inspections will be based Inspections based on actual plant experience experience with water water accumulation accumulation in in manholes and the frequency of inspection manholes inspection will be adjusted adjusted based on the results of an engineering evaluation, engineering evaluation, but an inspection will occur at least once every two years, with the first inspection inspection for license renewal renewal occurring occurring prior to the period of extended operation.
Proposed Inspections Inspections will be based based on actual plant experience experience with water water accumulation in in manholes. Based on water accumulation discovered manholes. discovered during inspections, inspections, the the frequency of inspection inspection will be adjusted basedbased on the results of corrective action action evaluations. The inspections will occur at least once every two years, with process evaluations.
the first inspection inspection for license renewal occurring prior prior to the period period of extended extended operation operation 160 B.1.10 B.1.10 In January 2006, during an EQ In enhancement project itit was discovered EO program enhancement discovered that an IP3 EO EQ file did not identify or address qualifications qualifications of pigtail extension cables. A During During the discussion of the EO EQ program with the the CR waswas initiated initiated to capture capture EOEQ documentation documentation deficiency, deficiency, which was not an Indian Indian Point owner, the process incorporating process of incorporating environmental environmental qualification qualification deficiency. The EO EQ program enhancement project program enhancement project was was OE into the programprogram was was discussed.
discussed. Other than. initiated to correct correct this type of historical discrepancy.
discrepancy. The The applicable test reports reports the information information provided provided in the site OE report, is were obtained, and were evaluated. evaluated. The applicable applicable test reports met 1P3's met IP3's there any additional additional OE associated associated with environmental parameter requirements, so these cables were considered qualified. qualified.
effectiveness effectiveness of the EQ EO program.
program. Therefore, Therefore, there was no operational concern. An extent of condition condition review review was not not because of the EO required because EQ program program enhancement project.
In July 2004, itit was identified In identified that the EQ EO program replacements for AOV program replacements components and and the AOV program replacements could be redundant. Some of the program replacements the AOV components are EQ, but not all. ItIt was identified are EO, identified there was an inconsistency inconsistency in in the philosophy philosophy for these repetitive tasks. Also, there there was an inconsistency on which tasks were routed routed for EQ EO program program review. To address address the extent of condition, corrective actions were to review the AOV replacement replacement scope to ensure EQ ensure all EO components that will be replaced under the AOV AOV program repetitive tasks are documented.
To ensure that Indian Point EQ Program stays current with the industry and Point EO and that the the industry operating experience (OE) is addressed,addressed, participation participation inin several industry based working and assessment groups is maintained. maintained. The industry industry groups are comprised of utility operators operators worldwide, worldwide, but the majority majority are in the US and Canada.
Many topics and and issues relating to equipment currently being equipment qualification are currently being
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Tuesday, Tuesday, March March 18, 2008 Page 38 of 48 Page
Item Reauest Request Response pursued by these these groups. Specific Specific issues issues include include the NRC's EO EQ Task Action Action Plan Plan (active interaction with the NRC staff, NEI and the Group), Cost-Saving Measures Measures related to EO file/documentation management, EQ activities (e.g., revised source term, file/documentation management, staffing), SOV SOV qualification qualification (generally and with respect to specific specific designs (extended Group-sponsored testing)), cable qualification (e.g., aging, qualified life valves (NS-2 Group-sponsored submergence, and similarity), issues arising from ongoing NRC inspections, inspections, qualification of High Range Radiation Monitors, issues arising from ongoing NRC Team and Special inspections, qualification Routine, Team qualification of specific specific equipment types equipment types penetrations, transmitters, etc.) as identified (splices, penetrations, identified by the Group, and integration integration of equipment equipment qualification qualification considerations into licenselicense renewal. Participation Participation inin these these organizations also provides a source reference documents, source of regulatory and reference documents, engineering analyses, and materials data from many information, engineering component information, manufacturers and utilities.
different manufacturers 161 B.1.13 B.1.13 The RCP oil collection collection system flame arrestors are subject subject to aging aging management management The RCP lube oil tanks collection system includes includes review with aging effects managed by the Fire Protection Protection Program.
Program. The flame flame passive flame arrestor(s) to prevent flashback.
a passive arrestors are included in component type "piping" in in the component in Table 3.3.2-12-IP2 3.3.2-12-1P2 and The RCP lube oil collection collection system is inspected inspected 3.3.2-12-1P3.
3.3.2-12-IP3.
every 24 months and every 31 days for inventory.
(SAO-703 Rev. 25) (IP2/ 2-PT-R201)2-PT-R201)
Is this component included in in the scope scope of the fire fire protection program (AMR) due to credit provided protection program to FP SSC's? (10 (10 CFR 54.4(a)(3))
54.4(a)(3)) & & 10 10 CFR 50.48) 165 165 B.1.26 Oil Analysis B.1.26 Analysis Oil analysis frequencies frequencies for IP2 and IP3 equipment equipment are based on Entergy templates templates Provide Provide a technical technical basis for the oil sampling with technical basis justifications. Procedure EN-DC-335, justifications. Procedure EN-DC-335, "PM Bases Template",
Template", is frequency. based based on EPRI PM bases documents documents TR-1 06857 volumes TR-106857 volumes 1 thru 39 and TR-103147. EachEach template template contains sections describing describing failure location and cause, progression of defration to fail, fault discovery, and task objective. From information progression information in these sections, frequencies are selected in selected for the components managed by the Oil components managed Analysis Program Program to mitigate mitigate failure.
A copy of the template bases for medium voltage motors, low low voltage motors, and horizontal pumps and procedure procedure EN-DC-335 were provided during the audit.
Clarification to be incorporated incorporated into the LRA.
166 166 B.1.26 Oil Analysis Analysis The Oil Analysis Program Program is designed to function as a screening tool to help identify NUREG-1801 Acceptance Criteria for XI.M39 NUREG-1801 XI.M39 conditions or trends. The adverse lube oil conditions screening process is supplemented The screening supplemented with with particulate concentration states that water and particulate concentration is detailed analysis in industry standards such as ISO 4406, ASTM in accordance with industry determined determined in accordance accordance with industry D445, ASTM D4951 and ASTM D96. Water, particle concentration concentration and viscosity standards. What industry standards form the What industry the acceptance criteria are based industry standards supplemented based on industry supplemented by basis for acceptance criteria at IP2 and IP3? IP3? manufacturers' recommendations.
manufacturers' recommendations.
Clarification to be incorporated Clarification incorporated into the LRA.
167 Diesel Fuel Monitoring Monitoring Response provided in Response in the revised response to question 31. 31.
Provide frequency at which biological biological activity and/or particulate contamination concentrations contamination concentrations are monitored for each each fuel oil storage tank in scope of license license renewal. Include basis for each frequency. If If an industry industry standard standard is referenced referenced in in your response, provide a copy of that standard.
(electronic version preferred if (electronic available) if available) 168 Diesel fuel Monitoring Monitoring Copy of publication provided provided Provide ASTM Special Technical Provide Technical Publication 1005 1005 referenced referenced in in response response to Q Q 34.
(Electronic perferred if (Electronic version perferred available.)
if available.)
169 169 Monitoring Diesel Fuel Monitoring Provided copy of 1985 version of standard.
standard.
Provide ASTM D975.
(Electronic version preffered ifif available.)
170 Analysis Oil Analysis Oil analysis frequencies equipment at IPEC are based on Entergy Templates, frequencies for equipment What What is the technical bases for the oil analysis analysis which have technical bases have technical bases justifications justifications inin the the templates.
templates. Procedure EN-DC-335, Procedure EN-DC-335, frequencies frequencies at IPEC. "PM Bases Template", references references EPRI EPRI PM bases TR-1 06857 Volume 1 thru 39 TR-106857 and EPRI guide determining PM guide for determining PM task intervals intervals TR-1 03147 in developing TR-103147 developing this this procedure. Each procedure. Each template template has has aa failure failure location location andand cause, cause, progression progression ofof m::w!Z~:.'i:<:,:"*::::m}"%::":::~t:::::'-',,::,::::rr::'~~~'8:~~~7:<~::::r:*-:,,~~,::;'~.':: '-::':;:::;:;:::;:-:-:%<:rr.:::::~~~,:~<.l<--~,,,'.~:'.:"~~:':~;:;:::.~;;l:.~~~~~~%'iiM~~
Tuesday, March March 18, 2008 Page39 of 48 Tuesday, Page 39 of 48
Item Request Response defraction to fail, fault discovery defraction discovery and arid task objective. Each component type uses Each component these subjects to conclude to a frequency frequency to mitigate failure.
A printout of the template template bases for medium voltage motors, low voltage motors and and horizontal horizontal pumps were providedprovided to the inspector, along along with procedure procedure EN-DC-335.
Clarification Clarification to be incorporated incorporated into into the LRA.
a 'S S ~ laVMS 171 Please Please include a statement statement about inspection The One-Time Inspection Inspection program description description in in LRA Sections A.2.1.26, A.3.1.26 A.3.1.26 techniques utilized to the description techniques description of the One- B.1.27 will be clarified by addition and B.1.27 addition of the following statement. "The inspections inspections Time Inspection Program in LRA Section B.1.27. will be nondestructive nondestructive examinations (including visual, ultrasonic, or surface surface techniques)."
Clarification Clarification to be incorporated incorporated into the LRA.
172 In the list of One-Time In One-Time Inspection Inspection Program For several several one-time inspection activities, activities, the term "components" "components" was used to activities, listed listed in in the program description description inin describe describe piping, piping elements, and other components within the system that are Section B.1.27 of the LRA, some activities Section activities do not of the material and environment environment to be inspected.
specify specify the types of components components to be inspected.
inspected.
Please include the types of components to be be For these one-time inspection activities, the application application will be clarified replacing clarified by replacing inspected under these activities. "components" with "tanks, "components" with "tanks, pump pump casings, casings, piping, piping elements piping, piping elements and components" as appropriate.
Clarification to be incorporated incorporated into the LRA.
173 Please confirm confirm in in the commitment list and LRA The commitment list and LRA Appendix A will be clarified clarified to state that new programs programs Appendix Appendix A that new programs be programs will be will be be implemented consistent with the corresponding
.implemented implemented consistent with the corresponding implemented corresponding program described described in in NUREG-NUREG-ten elements described in in NUREG-1801.
NUREG-1801. 1801.
1801. The new Additionally, Additionally, the commitment commitment must must contain programs are are Buried Piping and Tanks Inspection, Inspection, Non-EQ Inaccessible Medium-Non-EQ Inaccessible Medium-sufficient details on key elements to enable the the Voltage Cable, staff to make a determination determination that the new AMP, Non-EQ Instrumentation Instrumentation Circuits Test Review, Non-EQ Insulated Cables Cables and when implemented implemented as described, described, will be able to to Connections, One-manage the aging manage aging effects. Further, the the Time Inspection, One-Time One-Time Inspection - Small Bore Piping, Selective Selective Leaching, Leaching, commitment shall provide commitment provide an approximate approximate Thermal Aging Aging schedule indicating when when each of the new Embrittlement Embrittlement of Cast Austenitic Stainless Stainless Steel Steel (CASS), and Thermal Aging and programs will be available available for review by the staff. Neutron Neutron Irradiation Embrittlement Embritllement of Cast Austenitic Stainless Stainless Steel Steel (CASS).
Clarification to be incorporated into the LRA.
Clarification Commitment## 3, Commitment 15, 16, 17, 19, 20, 23, 26, and 27.
3,15,16,17,19,20,23,26, Commitments incorporate Commitments incorporate by reference reference sufficient sufficient details on key elements to enable enable the staff to make make a determination determination that the new new AMP, when implemented as described, described, will be able to manage manage the aging effects.
effects. Commitments Commitments includeinclude references references to sections sections of Appendix B of the LRA LRA that provide provide sufficient sufficient detail. The The schedule schedule for implementing implementing new programs will be determined determined basedbased on availability ofof fleet-wide resources implementation commitment dates resources and implementation dates for various sites across across the fleet. Programs Programs will be available available for review prior to the period of extended operation.
operation.
The program basis documents documents will be updated updated to provide additional details on the the scope for each new program. Also, a list of components components managedmanaged by the new programs will be available available for on-site review.
174 174 The program description description providedprovided for AMP B.1.28 The NUREG-1801 NUREG-1801 ProgramProgram Description for Program XI.M35 indicates that a One-in the LRA states in states that the One-Time Inspection -
One-Time Inspection- Time Inspection Inspection OfOf ASME ASME CodeCode Class Class 11 Small-Bore Small-Bore Piping Piping is needed needed because because the the Small Bore Piping Piping Program Program is a new program ASME ASME code does not include a volumetric examination examination of piping "less "less than or equal applicable to small bore ASME Code Class 1 applicable to NPS NPS 4" to detect detect cracking resulting from thermal and mechanical mechanical loading or piping less less than 4 inches nominal pipe size (NPS (NPS intergranular stress corrosion.
intergranular corrosion. However, according according to ASME Code, a volumetric volumetric 4"), which includes includes pipe, fittings, and branch examination is already required for piping equal equal to NPS 4".
connections. The LRA also states that the Indian Indian Point's new program program will be~consistent be'consistent with with NUREG-1801 Item Also, NUREG-1801 Item IV.C2-1 IV.C2-1 is the only PWR line item which applies the One-NUREG-1801 Program XI.M35, One-Time NUREG-1801 One-Time Time Inspection Time Inspection ofof ASME Code Class 1 Small Bore Piping Program Code Class Program (XI.M35). This This Inspection of ASME Code Class. 1 Small-Bore Inspection Small-Bore line item is for Class 1 piping "less than NPS 4".
Piping. However, NUREG-1801, NUREG-1801,Section XI.M35, states that the program program is applicable to small-bore small-bore Therefore, Entergy Entergy concludes that it it is not the intent of GALL for Program Program XI.M35 XI.M35 to ASME Code Class 1 piping and systems less than include NPS include NPS 4" pipe. Therefore, the IPEC One-Time One-Time Inspection Inspection -- Small Piping Small Bore Piping or equal to 4 4 inches nominal nominal pipe size (i.e.,
(i.e., sizes sizes Program includes includes only small bore Class 1 piping << NPS 4", 4", which which is consistent with up to and including 4 inch size). IfIf Indian Indian Point GALL.
intends to exclude exclude 4" size from AMP B.1.28, this this should be treated treated as an exception exception to GALL GALL and a
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Item Request Reauest Response justification justification included included in the the LRA LRA to to establish consistency with consistency with the GALL report.
report.
175 175 Commitment letter Commitment letter NL-07039 NL-07039 for oil oil analysis analysis states states LRA Sections A.2.1.25 LRA Sections A.2.1.25 forfor IP2, A.3.1.25 A.3.1.25 for IP3, B.1.26 will be IP3, and B.1.26 be revised revised to to agree agree the the oil analysis analysis program program will will be be enhanced enhanced to to with with Commitment Commitment 18 18 listed listed in in commitment commitment letter NL-07039. The letter NL-07039. The last last two two formalize trending formalize trending of preliminary oil screen of preliminary screen results results enhancements enhancements listed listed in Section A.2.1.25 and Section A.2.1.25 and the the last last two two enhancements enhancements listed listed in as as well well as data provided from independent data provided independent Section Section A.3.1.25 A.3.1.25 will will be revised to read be revised read as follows. "Formalize "Formalize preliminary preliminary oil laboratories.
laboratories. The FSAR Supplement The FSAR Supplement A.2.1.25 A.2.1.25 for screening screening for for water water and and particulates particulates and laboratory analyses including laboratory analyses including defined defined oil oil analysis states that appropriate analysis states appropriate procedures procedures will acceptance acceptance criteria for all components included in components included in the scope of this program. The the scope The formalize trending.
revised to formalize be revised program will specify corrective actions in corrective actions in the the event event acceptance acceptance criteria are not met.
The The commitment commitment letterletter and and the FSAR FSAR Supplement Supplement Formalize trending Formalize preliminary oil screening trending of preliminary screening results results as well provided from well as data provided from should state state the same answer. independent laboratories."
independent Clarification to be Clarification incorporated into the LRA.
be incorporated 176 In the list of of Periodic Periodic Surveillance Surveillance and and Preventive Preventive For several several Periodic Periodic Surveillance Preventive Maintenance Surveillance and Preventive Maintenance Program Program activities, activities, Maintenance Program Maintenance Program activities, activities, some some activities activities the the term term "components" was used to describe piping, piping elements, describe piping, elements, and and other other do not not specify specify the types of of components components to be be components within within the system system that areare to be inspected.
inspected. For For these these Periodic Periodic inspected. Please clarify the types inspected. Please types of of components components Surveillance Surveillance and Preventive Maintenance and Preventive Maintenance Program activities, the application Program activities, application willwill be be to be inspected inspected in these activities.
activities. clarified clarified by "components" with by replacing "components" with "piping, piping piping elements elements and and components."
Also, some activities do not indicate whether the not indicate the The LRA clarified to show that the internal LRA will be clarified internal surfaces of piping, piping piping, piping internal internal or external surfaces surfaces are to be inspected.
inspected. elements, and components components are inspected inspected by the Periodic Periodic Surveillance Surveillance and Please Please clarify.
clarify. Preventive Preventive Maintenance Program for the following Maintenance Program following items items shown shown in in the program program description of Section B.1.29.
description Recirculation pump Recirculation pump cooler housing Station air containment penetration piping penetration piping Portable blowers and flexible trunks stored for emergency Portable emergency ventilation ventilation use use EDG exhaust gas piping EDG piping EDG EDG air intake and aftercooler EDG starting air EDG air EDG EDG cooling water makeup makeup IIP2 P2 fuel oil cooler cooler IP3 Appendix R radiator, aftercooler, aftercooler, starting air, and crankcasecrankcase exhaust exhaust feedwater Auxiliary feedwater Control room HVAC Control HVAC IP2 Nonsafety-related Nonsafety-related affecting affecting safety-related safety-related River water service system Waste Waste disposal disposal system Water treatment plant Water plant Nonsafety-related affecting safety-related IP3 Nonsafety-related safety-related Chlorination system Circulating water system EDG system Floor drain system Gaseous waste disposal system Instrument air system Instrument Liquid waste disposal system Nuclear equipment equipment drain system River water system Station air system Secondary plant Secondary plant sampling system incorporated into the LRA.
Clarification to be incorporated 277 277 (M37) Flux B.1.16 (M37) Flux Thimble Tube Inspection:
Inspection: IP-DSE-01-058, Review of R11 Reports IP-DSE-01-058, R1 1 RPV Thimble Tube Eddy Current Inspection Inspection Provide referenced documents Provide the referenced IP-RPT-06-001824, Fourth Eddy Results, and IP-RPT-06-001824, Eddy Current Inspection Inspection of the IncoreIncore IP-DSE-01-058 5-222: IP-DSE-01-058 Thimble Tubes, were provided to the staff for onsite review.
IP-RPT-06-001824 5-224: IP-RPT-06-001824 278 278 B.1.18 (M B.1.18 (MII ++ 53): Is there one document document which The lSI ISI programs for IP2 IP2 and IP3 are controlled by Entergy common administrative administrative controls like activities critical in in this AMP? procedure ENN-DC-120. Additionally, IPEC IPEC Section XI Xl repairs, replacements, and modifications are controlled by modifications by station administrative procedureprocedure IP-SMM-DC-907.
IP-SMM-DC-907.
Both documents were were provided to to the staff for onsite review
"'",""'_~V-;":-"I""'%::""'lMjjIj@im 279 B.1.30:
B.1.30: RG 1.65, RG 1.65, dated October 1973, identified material material and and inspection inspection requirements requirements for
- 1. Check document which addreses the
- 1. the reactor vessel head studs. GALL identifies the RG 1.65 preventive measures the RG measures of (1) (1) penetrative measures penetrative measures recommended in RG 1.65 avoiding the use of metal-plated stud avoiding stud bolting bolting to prevent prevent degradation degradation due to to corrosion March 18, Tuesday, March 18, 2008 2008 Page 41 of 48 Tuesday, Page 41 of48
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- 2. Review summarizing results from Review documents summarizing from or hydrogen embrittlement, embrittiement, and (2) to use manganese manganese phosphate or other other past inspections.
inspections. acceptable surface treatments and stable lubricants.
IPEC utilizes aa plasma bonding technique, not the metal plating process described described in RG 1.65, on the studs. The plasma. plasmabonding bonding processprocess provides corrosion lubrication for the studs which satisfy the preventive measures protection and lubrication measures of RG RG 1.65. The plasma plasma bonding process process was evaluated evaluated by engineeringengineering request (ER-IP2-04-11531, ER-IP3-04-11231) to ensure acceptability.
04-11531, ER-IP3-04-11231) acceptability.
Material specification Material fabrication aspects of RG 1.65 Items 1 and 2 are specification and fabrication addressed in procurement activities for the purchase in procurement purchase of replacement replacement studs. PO 4500515914 specifies ASME SA540, GR 24, Class 3 bolts consistent number 4500515914 number consistent with the ASME ASME specification specification in in RG 1.65.
examined in accordance All studs are examined accordance with ASME Code requirements requirements during each 10 10 year year lSI interval such that sampling considerations are addressed.
ISI interval addressed. Recent ISI lSI reactor head stud inspection inspection results indicateindicate that the ISI lSI Program is adequately managing reactor head stud aging effects. .
These activities activities meet the intent of RG 1.65 1.65 with respect to procurement,procurement, manufacturing, inspection, and manufacturing, inspection, and corrosion corrosion resistance.
Copies of replacement replacement stud purchase documentation were provided to the NRC for purchase documentation for onsite review.
280 B.1.31 (MIIA)
B.1.31 Penetration Inspection (M IIA) RVH Penetration Provided letters for onsite review Referenced documents 5-143 - NL-05-001 Referenced documents NL-05-001 5-144 -- -- N NL-05-044 L-05-044 283 IfIfduring the inspection, the flaw or indication As described described in One-Time Inspection - Small Bore Piping Program in the LRA, the One-Time Program will exceeds acceptance criteria proved in Section exceeds the acceptance Section implemented consistent with the program described be implemented NUREG-1801 Section described in NUREG-1801 XI, XI, IWB-3400, does Indian Indian Point evaluate the the XlM35. acceptance criteria section for that program states, "If XI.M35. The acceptance "If flaws oror condition accordance with Section XI condition in accordance Xl paragraph paragraph indications indications exceed acceptance criteria of ASME Code,Section XI, Paragraph exceed the acceptance IWB-3131 and performperform extra examination examination per IWB-3400, they will be evaluated evaluated in accordance with ASME Code,Section XI, in accordance XI,Section XI IWB-2430? Describe the process Section IWB-3131, and additional Paragraph IWB-3131, examinations are performed in accordance additional examinations accordance followed by IP to address such condition and with ASME Code,Section XI, Xl, Paragraph IWB-2430."IWB-2430." The process is as described described in which IP procedure includes includes these requirements.
requirements. ASME Section Section XI. Xl. Upon its implementation, activities of the One-Time Inspection Inspection -
Small Bore Piping ProgramProgram will be included in in the lSI ISI program program plan.
358 IP2/1P3 Experience Related to Aging IP2/IP3 Operating Experience Aging Structures at IPEC are formally inspected on aa periodic basis as part of the site's site's Degradation of Containment Containment Structure, Other Maintenance Rule implementation of the Maintenance implementation Program as defined in 10CFR50.65.
Rule Program 10CFR50.65. The The Structures, Structures, andand Structural Components inspections are performed personnel in performed by personnel in the Civil Engineering department per Engineering department Entergy procedure ENN-DC-150. Items addressed procedure ENN-DC-150. addressed in the inspection inspection program Based on review of the Condition Report include, but are not limited concrete and steel components, coatings, masonry limited to, concrete summaries listed listed in IP-RPT-06-LRD05, IP-RPT-06-LRD05, Revision Revision walls, supports and attachments. All degradation degradation found during the inspections is 1, Table 3.1.3 "Operating Experience Applicable Applicable documented in in a'report as required ENN-DC-150 to allow for future trending.
required by ENN-DC-150 trending.
to Structures Structures andand Structural Structural Components",
Components", the the Documentation includesincludes photographs, tabularized descriptions degradation, descriptions of degradation, identified a number of apparently project team identified apparently completion of checklists evaluation of existing degradation.
checklists and evaluation degradation. Observed significant conditions of aging degradation of degradation from current inspections degradation inspections is compared compared to degradationdegradation from previous previous structures that are NOT
. structures NOT identified identified in the LRA, LRA, thethe inspections to determine determine if degradation has progressed. Any degradation ifthe degradation degradation that is PBDs for the StructuresA MPS, or the Structures Structures require repair is documented deemed to require documented in the Condition Condition Reporting Process Process and AERM.
AERM. initiated for the repairs.
Work Orders initiated The following Condition Condition Report Report summaries, In addition to the formal inspection process, In process, structures structures at IPEC are inspected inspected on an excerpted identify the types of excerpted from the table, identify ongoing basis by system engineers, operations and maintenance maintenance personnel during personnel during structural degradation of concern:
structural aging degradation tours of the facility. Any conditions adverse to quality discovered their routine tours discovered during these routine inspections are documented in the Condition Reporting System and Condition Reporting and (I)Water (I) Control Structures Water Control Structures Deqradation: dispositioned. Specific dispositioned. responses for the CR's listed above Specific responses above are discussed discussed below.
CR-IP2-2002-04224 CR-IP2-2002-04224 CR-IP2-2002-04224 CR-IP2-2002-04224 a) This CR identifies area in in the Unit 1 screen screen well ceiling where concrete concrete has has 200204224 200204224 - Industrial Safety performed a walk become become loose (spalled) causing rebar rebar to be exposed and 'develop develop'surface
'surface rust. ThisThis down down in in the Unit 1 Screen well House 5' and has been identified since baselinebaseline Structures Monitoring Program (SMP) in Structures Monitoring in 1996.
found: Loose and spalling concrete concrete inin overhead overhead an initial construction issue as a result of insufficient concrete This is an allowing concrete cover allowing south east side. No evidence evidence of concrete concrete on floor, the bar to exfoliate, expand expand and pop the concrete cover.
able to see rusted rebar's in in ceiling.
ceiling. & c) Ceiling was inspected by Civil engineering bb & engineering on 4/23/02. ItIt does not represent any immediate structural safety concern. The steel reinforcing rods are the load load CR-IP2-2002-05637 CR-IP2-2002-05637 carrying components in the bottom carrying bottom part of the concrete slab. The concrete concrete cover that has spa spalled contribute to the overall strength lied did not contribute strength of the slab. Its Its main 200205637 - During the Service Service Water ISI, it was Water lSI, was function is to protect re-bar. The re-bar is exposed protect the re-bar. exposed and has has surface rust but identified that the ceiling and support structure for support structure significant reduction of cross sectional area and therefore there is no significant therefore no effect on on
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Tuesday, March Tuesday, March 18, 2008 Page 42 of Page 0'4848
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the Service Service Water Pump Pit is severely degraded. the strength strength of the slab. No reduction reduction in load carrying capacitycapacity has occurred.
Large chunks of cement cement werewere found on the plasticplastic d, e & & f) The condition condition of loose concrete concrete was stabilized stabilized and work work order has been floor grating. initiated to make the repair. The condition is being monitored monitored until repairs are are complete.
CR-IP3-2002-02170 CR-IP3-2002-02170 g & h) No augmented
& h) augmented or special inspection planned for the PEO. Unit 1 screenwell inspection is planned house will continue continue to be inspected inspected and monitored under under Structures Structures Monitoring Monitoring The I-beam The I-beam steel work along both sides of the the Program during Program during PEO.
PEO.
discharge canal at the discharge discharge canal bridgebridge is deteriorated, rusted through deteriorated, through in in many large areas, CR-IP2-2002-05637 CR-IP2-2002-0S637 and bent. CR-IP2-2002-04224 (discussed previously), this CR identifies area in a) Same as CR-IP2-2002-04224 in the screen well ceiling where concrete concrete has become become loose (spalled)
(spa lied) causing rebar to CR-IP3-2002-02836 CR-IP3-2002-02836 be exposed exposed and develop surface rust. This has been been identified since baseline baseline Structures Monitoring Structures Monitoring Program (SMP) in in 1996. This is an initial construction issue as as During replacement replacement of the 31 Discharge Discharge Canal Oil a result of insufficient concrete concrete cover allowing the bar to exfoliate, exfoliate, expand and pop pop Boom, the south rail beam beam as found severely severely the concrete cover.
corroded approximately corroded approximately 8" 8" below the water line at b& & c) Civil design engineering conducted design engineering conducted an assessment assessment of the structural adequacy low tide, causing the oil boom slider to disengage disengage of the reinforced reinforced concrete concrete slab of the Service Service Water Pump Pit area Water Pump area of the UnitUnit No.
No.2 2 from the track. Intake Structure and established that the slab is operable Intake Structure operable and capable capable of performing intended function.
its intended CR-IP3-2004-03242 CR-IP3-2004-03242 d, e && f) f) The condition was corrected corrected under Engineering Engineering Request Request response ER-04 051. The exposed rebars were cleaned OS1. cleaned and sealed sealed with cementitious epoxy. The The While conducting conducting a Plant Plant Tour, I discovered discovered a hole hole damaged steel supports were were repaired repaired or replaced.
replaced.
approximately approximately 6x2" at the south end of the Unit 2 The condition condition is being monitored.
monitored.
discharge discharge canal directly opposite opposite the Unit 3 g& & h) No augmented augmented or special inspection is planned planned for the PEO. The unit 2 intake intake Polisher Polisher building. This hole was apparently structure will continue structure continue to be inspected and monitored under Structures Monitoring Structures Monitoring caused caused by the erosion erosion of the cement near the near the Program Program during during PEO.
grating.
grating.
CR-IP3-2002-02170 CR-IP3-2002-02170 CR-IP3-2005-03993 CR-IP3-200S-03993 a) This CR identifies deteriorated deteriorated carbon steel steel I-beam on discharge discharge canal bridge. No previous previous history history was found.
During a walkdown walkdown of the Unit 3 Intake Structure Intake Structure b & c) Design engineering engineering performed performed a walked down down of discharge discharge canal canal from gatesgates with the Ultimate Ultimate Heat Heat Sink NRC Inspector, two two to SW backup pumps. It It was determined determined that the there was not any condition condition that is pieces of spa spalled lied concrete (approximately 1" 1" degraded degraded to the extent implied in in the CR. The steel under the south bridge has an an diameter diameter x 1/2" thick) and same rust / scale were were area area of failed coating coating witch has some surface surface rust and bent coating but is does does not found on top of the mat-covered mat-covered grating grating on the S' 5' effect effect structural structural integrity of the structure.
structure.
elevation. d, d, e && f) Based on insignificance of coating degradation degradation and surface rust, no repairs were determined determined necessary. The condition of these beams is monitored under structures monitoring monitoring program. A recent inspectioninspection (ref. IP-RPT-07-00034, IP-RPT-07-00034, "Inspection of Unit 3 North and south bridges over discharge discharge canal") confirmed these beams are in good are in good condition.
g&& h) h) No augmented augmented or special inspection inspection during during PEO. The discharge canal structure will continue continue to be inspected inspected and monitored monitored under Structures Monitoring under Structures Monitoring Program during PEO.
CR-IP3-2002-02836 CR-IP3-2002-02836 a) This CR identifies identifies severely south rail of the discharge discharge canal oil boom. previous boom. No previous history found.
b&& c) The degraded degraded condition of the south rail caused caused the oil boom slider to disengage from the track. Equipment Equipment is degraded degraded and did not function as designed at very very low tide.
& f) d, e & f) Work order order was initiated.
initiated. The damaged beam was repaired and the oil The damaged boom was restored. The rail is currently currently inin good condition.
g&& h) No augmented augmented or special inspection inspection during PEO. The discharge discharge canal structure will continue continue to be inspected and monitoredmonitored under Structures Monitoring under Structures Monitoring Program during PEO.
CR-IP3-2004-03242 CR-IP3-2004-03242 a) This CR documents documents a hole approximately 6x2" at the south end of the Unit 2 hole approximately discharge canal directly discharge directly opposite the Unit 3 polisher building. This hole was was apparently apparently caused by erosion erosion of the cement on grade concrete concrete (walkway) around the grating in area of discharge discharge canal. No previous history was found.
b & c) The spalled spa lied concrete in the discharge canal does not adversely adversely affect the the required required function of the discharge discharge canalcanal to direct direct discharge discharge flow to the Hudson River, away away from the Service Water pumps pumps intake. At the southern southem end of the Unit 2 Discharge Canal Discharge Canal directly directly opposite opposite thethe Unit Unit 33 Polisher Polisher Building Building aa concrete spall, concrete spall, delaminations delaminations of the concrete exist. Other portions of concrete concrete in in the area of the the discharge discharge canal show degradation caused by chemical attack, as shown in in the the attached pictures. The attached pictures. The Corrective Corrective Action Action requires requires an an assessment assessment as as to to the the reason for the spalls and delaminations, delaminations, with chemical attack (salt) (salt) being considered considered the the most likely most likely reason, an an assessment assessment of of the depth into the concrete depth into concrete of the damaged damaged concrete matrix, 'and and the selection selection of the best method to fix the spalls and delaminations, delaminations, including the selection of a concrete concrete epoxy, or protective coating, coating, t'"1mt".t:::::"',,,:>.~~.¥L'4.,P::,.E:~.,*, ..~~'~m'*"v'~ ;~,':;l"~~~\~;:'::i:~~":"".<<'w.-.,"-;'::'>>;:;:;z':';:",,,,~,,{.m.l',~,;;;;>;.A<'!lI!>'_~~~.z~>::::,::,l."";:j>~~~~~~&Lt~L.t~._:}'t"~",,,,:;;~~~#.i\.to.~,,'S:o::a.~O<i Tuesday, March Tuesday, March 18, 2008 Page 43 of 48 Page
Item Request Response with enhanced enhanced chemical resistance. For For the hole described described in in CA 001 to CR-IP3- CR-IP3-2004-03242, 2004-03242, a cut-out of the concrete and dowell installation should should be considered.
Work OrderOrder IP3-04-20717 IP3-04-20717 was initiated initiated to make make the repairs.
d, e & insignificant effect of this condition on discharge
& f) Due to insignificant discharge canal, no repairs repairs have yet been made. The condition is being monitored until repairs are made.
g& & h)h) No augmented augmented or special inspection inspection is planned for the PEO. The discharge discharge canal structure will continue to be inspected and monitored under Structures Structures Monitoring Program during PEO.
CR-IP3-2005-03993 CR-IP3-2005-03993 a) This This CR identifies identifies that during a walkdown walkdown of the Unit Unit 33 Intake Structure with the the Ultimate Heat Heat Sink NRC NRC Inspector, two pieces of spalled concrete (approximately spalled concrete (approximately 1" 1" diameter x 1/2" thick) and same rust / scale scale were found on top of the mat-covered mat-covered grating on the 5' elevation. elevation. The deteriorated deteriorated concrete concrete condition in this area was was previously identified Maintenance Rule walkdowns (Ref. IP-RPT-03-00090).
identified during Maintenance IP-RPT-03-00090).
b & c) The Ultimate Ultimate Heat Sink/Service Water Water SSC was evaluated evaluated with respect to the the following : FME in service following: service water water bay - Due Due to presence presence of FME FME mat on grate, there is no chance spalled spa lied pieces of concrete can enter enter the suction bells of the SW pumps.
Structural integrity of bay - There is no indication of structural failure. Spalled Structural Spalled pieces pieces of concrete are small and do not represent structural failure. No operability issues issues with ultimate heat sink or service service water water SSC. Not Not reportable reportable per ENN-Ll-108.
d, e & f) f) Work orders IP3-05-21329 IP3-05-21330 have 1P3-05-21329 and IP3-05-21330 have beenbeen initiated to make make any necessary repairs. No repairs have have been determined determined necessary necessary at this time. The The structure is being monitored as part of routine inspections inspections under StructuresStructures Monitoring Monitoring Program.
g& & h) No augmented augmented or special inspection inspection during during PEO. The intake structure structure will continue to be inspected continue inspected and monitored under Structures Monitoring monitored under Monitoring Program Program during during PEO.
No other significant existing conditions of structural aging were were identified.
identified.
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359 Operating Experience IP2/IP3 Operating Experience Related to Aging Aging The reactor cavity at Unit 2 has a history of leaking during refueling outages when Degradation of Containment Containment Structure, Other the cavity is filled with water. Several Several attempts have been been made over the last Structures, and Structural Components Components several outages several outages to mitigatemitigate this condition with limited success. Observations Observations made made during filling and draining draining the cavity cavity during the previous outage indicate that the area area Based on review of the Condition Condition Report of the cavity where the leak occurs is in in the upper Observations also indicate upper half. Observations summaries summaries listed listed in IP-RPT-06-LRD05, IP-RPT-06-LRD05, Revision that water that gets behind the stainless steel steel liner when the cavity is filled has a low low 1, Table 3.1.3 "Operating Experience Applicable Applicable resistance flow path to the 46' elevation in in containment. This is indicated indicated by the the to Structures Structures and Structural Structural Components",
Components", the the relatively free free flow of water observed to start and stop abruptly abruptly once once certain certain water project team identified identified a number of apparently elevations were achieved. It It was observed that a previous repair patch had pulled significant conditions of aging aging degradation degradation of away from the liner liner plate, leaving a gap for water to infiltrate. Repairs Repairs will be made made structures that are NOT identified identified in the LRA, the the to this failed patch area area to sealseal itit prior to filling the cavity during the upcoming upcoming PBDs for the StructuresA StructuresA MPS, MPS, or the Structures Structures outage. In In addition, a strippable strippable coating coating will be applied to other suspect areas areas of the the AERM.
AERM. liner during this outage to mitigate the leakage leakage while the thecavity cavity is full of water.
Based on review of industry experience, minimal minimal time of concrete exposure exposure to the the The following Condition Report summaries, borated water, and and testing testing performed performed on concrete samples samples taken taken from the Unit 2 excerpted from the table, identify identify the types of Spent Fuel Pool walls after after discovery of a liner leak, Engineering Engineering has concluded concluded that structural aging degradation of concern:
aging degradation the reactor cavity concrete structure's cavity concrete structure's capability to perform its design basis function function has notnot been compromised compromised as a result of this issue.
(11)IP2 (II) IP2 Reactor Reactor Cavity Leakaqe:
Cavity Leakaqe: An action plan is being developed for a permanent fix to this issue. Two technologies are being investigated technologies investigated for the permanent permanent solution.
solution. The locations and CR-IP2-2002-10610 CR-IP2-2002-1 061 0 extent of permanent permanent repair will be based on the effectiveness effectiveness of the temporary temporary repairs beingbeing mademade during during this upcoming upcoming outage. ItIt is also anticipated anticipated that concrete concrete CR IP2 2002-10052 2002-10052 concerning concerning reactor cavity core samples will be taken from the cavity walls in in subsequent outages outages for leakage leakage did not address address the following issues: 1) analysis. Specific responses responses to the ConditionCondition Reports Reports listed above are discussed Evaluate/investigate Evaluate/investigate the structural structural long term term below.
effects of the boric acid acid on the concrete concrete and carbon carbon steel rebar within the concrete. CR-IP2-2002-10610 CR-IP2-2002-1 061 0 a) This CR requests evaluation evaluation of long term effect of boric acid on concrete concrete and CR-IP2-2003-00682 CR-IP2-2003-00682 rebar due to discovery discovery of a borated water leak leak from the cavity liner during refueling. refueling.
Reactor cavity has had a history history of leakage during refueling activities when the the The Unit Two Refueling Refueling Cavity Liner has refueling canal is filled (Ref. (Ref. CR-IP2-2004-05180).
experienced cracks on numerous occasions. The The SOER 02-4 investigative team has discovered 02-4 investigative discovered that that B& & c) Utilizing industryindustry experience, results results of Florida Power Power & & Light testing of the cracks cracks have been repaired repaired several times. Yet, reinforced concrete exposed to borated borated water, core samples taken of fuel pool wall cracks continue cracks continue to appear.
to appear. for leak that went unnoticed for 18 18 months, IPEC concluded that the leak leak has no no significant effect on the concrete or rebar. The evaluation evaluation included included the considerationconsideration CR-IP2-2003-00959 CR-IP2-2003-00959 that the boric acid leakage leakage is limited to the duration of the cavity flooding flooding and therefore, the duration duration of of the overall overall exposure exposure of of the concrete concrete to to boric acid acid is THIS IS A SOER 02-4 RESPONSE ISSUE ISSUE significantly shorter significantly shorter than than that that employed employed in the tests, in the tests, i.e., weeks weeks or months months versus versus IP-2 has a long-termlong-term degradation degradation issue with years. As such, itit is concluded concluded that the effect of the boric acid leaks is limited in leakage from the Refueling leakage Refueling Cavity Liner. The liner liner terms of both extent and depth of penetration penetration in in the concrete. Thus, the effect effect of this this
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Tuesday, March Tuesday, March 18, 2008 Page 44 of Page of48 48
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has experienced cracks on numerous has experienced numerous occasions.
occasions. event event (borated (borated waterwater leak) was determined determined to be minimal on concrete concrete and and The cracks have been repaired several times, but but reinforcing steel.
the cracks cracks continue to appear. D, e & & f)f) No repairs or replacement replacement of concrete have have been determineddetermined necessary.
Action to stop or minimize reactor cavity liner leakage leakage during refueling refueling outagesoutages is CR-IP2-2004-05180 CR-IP2-2004-05180 discussed discussed in CR-IP2-2004-05180.
g& & h) No augmented or special inspection planned for the PEO. PE~. The rector cavity The IP2 Reactor Reactor Cavity has a history of serious serious concrete, concrete, and intemal internal structure structure to containment containment structure, will continue continue to be be leakage through through the stainless steel liner when when the the inspected and monitored monitored under under Structures Monitoring Monitoring Program during during PEO.* PEO..
cavity is filled during refuel outages. The The cavity liner is made from stainless steel plates plug plug CR-IP2-2003-00682 CR-IP2-2003-00682 welded welded to structuralstructural steel and seam welded a) This CR identifiesidentifies IP2 refueling cavity cavity leakage leakage through the stainless steel liner liner together. when the cavity is filled during during refueling refueling outages.
outages. The cavity cavity is filled during refueling refueling activities and other times itit remains dry. The source source of the leak was a pinhole pinhole leak leak in in a weld area, and was successfully successfully repaired. repaired. The identified cause of the pinhole was was workmanship during original poor workmanship original welding of the liner plate which had gone gone undetected.
BB& & c) Refueling Refueling cavity is filled only during refueling outages. No immediate immediate corrective action or operability documented in the CR.
operability is documented D, e & f) f) Utilizing industry experience, results of Florida Power & Light testing of reinforced concrete exposed to borated water, and core samples samples taken of fuel pool pool wall for leak that went unnoticed unnoticed for 18 months, IPEC concluded that the leak has no no significant effect on the concrete or rebar. As for the liner, the repaired repaired area (discussed in item a above) and other other suspect suspect weld areas of the liner liner plate have have inspected (visual and UT) and tested (vacuum test) with satisfactory been inspected satisfactory results.
Other welds were were found to be of good quality and and free of defect.
G& & h) No augmented augmented or special inspection planned for the PE~. PEO. The effects effects of aging on the refueling cavity liner plate will continue continue to be managed managed under under WaterWater Chemistry Control- Control - PrimaryPrimary And Secondary Secondary Program during the PE~. PEO.
CR-IP2-2003-00959 CR-IP2-2003-00959 a) This CR identifiesidentifies IP2 refueling cavity leakage through through the stainless stainless steel liner liner when the cavity is filled during refueling refueling outages. The cavity is filled during refueling refueling activities and other times it remains dry. The source of the leak was a pinhole pinhole leak in in a weld area, and and was successfully successfully repaired. repaired. The cause of the pinhole pinhole was poor workmanship during original welding of the liner liner plate which which had gone gone undetected.
b& & c) Refueling Refueling cavitycavity is filled only during refueling refueling outages. No No immediate immediate corrective action or operability is documented corrective documented in the CR.
d, e & & f)f) Utilizing Utilizing industry experience, experience, results of Florida Power & & Light testing testing of of reinforced concrete reinforced concrete exposed exposed to borated water, core samples taken taken of fuel pool wall for leak that went unnoticed unnoticed for 18 months, IPEC concluded concluded that the leak leak has no no significant effect on the concrete concrete or rebar. As for the liner, the repaired repaired area area (discussed in in item a above) above) and other suspect suspect weld areas of the liner plate have have been inspected inspected (visual and UT) and tested tested (vacuum test) with satisfactory satisfactory results.
Other welds were found to be of good quality and free of defect.
g& & h) No augmented augmented or special inspection inspection during PE~. PEO. The effects effects of aging on the the refueling refueling cavitycavity liner plate will continue to be managed managed under under Water Chemistry Control - Primary Primary And Secondary Secondary Program Program during the PE~. PEO.
CR-IP2-2004-05180 CR-IP2-2004-05180 a) This CR identifies IP2 reactor cavity leakage leakage through the stainless steel liner when the cavity cavity is filled during refueling outages. The cavity is filled during the the refueling activities and at other times remains dry. The cavity is known to have have leaked since early 1990's. Engineering evaluation evaluation of the leakage determined determined that the liner liner seam, plug and structural structural attachment attachment welds on the west wall were were the most likely sources sources of the leakage. The cavity goes through fuel handling operation during during refueling outages. Damage Damage to the liner liner is determined determined to have occurred occurred during during previous refueling outages due to poor poor cleanliness and maintenance maintenance control. control. This This includes use includes use of of improper improper material material and and tools tools (wire (wire brush contaminated contaminated with carbon steel and containing chloride coming coming in contact contact with stainless steel. And, damage damage (cut) into the liner plate plate when removing (cutting out) temporary attachments to the temporary attachments the liner.
b & c) Since all loose pieces were removed removed from the wall, the probability for debris to to foul equipment foul equipment in in the the VC is minimal.
minimal. Based Based on on the response response to CA-1 CA-1 and since the and since the repair has been made to the wall, the system is operable. Approximately Approximately one half of a four foot section within a fifteen foot long long patch was loose from the liner wall. wall. ItIt took several attempts with a scraper scraper to pry it free from the wall. During normal operation or aa Design Basis Accident Accident this patch patch would have remained in in place. Even Even if itit had fallen, if fallen, any piecespieces would would have remained remained in the upper upper cavity along along the West wall and would wall would not have affected affected any operating equipment or blocked water flow to the sump. Therefore;Therefore; there there was no operabilityoperability concern.
concern.
Evaluation of effect of leak on concrete is addressed Evaluation addressed by CR-IP2-2002-10610.
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Tuesday, March Tuesday, March 18, 2008 2008 Page Page 45 of of 48
Item Reauest Request Response d, e & & f) Liner Liner has has gone through numerous inspections inspections and tests. Attempts Attempts have have been been made to repair repair and stop the leak. Repair attempts attempts have not completely stopped stopped the leak which which occurs only while the cavity is filled during refueling outages outages (at all other times, the cavity is dry). dry). Leak rate has lessened due to the repair attempts.
attempts. Efforts Efforts continue continue to stop leak through application of various permanent through the application permanent and temporary temporary repairs.
g & & h) h) No augmented augmented or special inspection inspection during PEO. The rector cavity concrete, and internal structure to containment containment structure, will continue to be inspected inspected and and monitored monitored under the Structures Structures Monitoring Monitoring Program Program during during PEO.
No other significant existing conditions other Significant conditions of structural structural aging aging were identified.
360 IP2/IP3 Operating IP211P3 Operating Experience Experience Related to Aging During excavation excavation work in in the Unit 2 Fuel Storage Storage Building Building in support of Dry Cask Degradation of Containment Degradation Containment Structure, Other Storage, a hairline crack was discovered discovered in in the spent fuel pool south wall that that Structures, and Structural Structural Components Components appeared damp. Samples taken from this wetted crack indicated indicated that the fluidfluid radioactive isotopes contained radioactive isotopes consistent with fuel pool water. A collection collection box was was Based on review of the ConditionCondition Report installed on the south wall over over the wetted crack area to collect and monitor any summaries summaries listed in in IP-RPT-06-LRD05, IP-RPT-06-LRD05, Revision Revision leakage emanating through leakage through this cracked area. EngineeringEngineering evaluations evaluations havehave 1, Table 3.1.3 "Operating Experience 1, Experience Applicable Applicable determined that the discovered wetted crack and associated determined leakage has no associated leakage no to Structures and Structural Components", the the detrimental effects on the structural capability of the south spent fuel pool wall.
detrimental project project team identified a number of apparently Subsequently, accessible accessible areas areas of the spent fuel pool liner were inspected for significant conditions of significant conditions aging degradation of aging degradation of of degradation that could degradation could result in in leakage. Inspections included use of robotic Inspections included robotic structures that are structures that are NOT NOT identified identified inin the LRA, the the cameras, general visual and vacuum box testing. Vacuum box testing was was used on on PBDs for the StucturesA MPS, or the Structures Structures areas of the liner that were suspect suspect based on the general general visual and robotic camera camera AERM.
AERM. inspections. None of the suspect suspect areas in in the spent fuel pool area failed the vacuum box test, indicating indicating that none none of the indications found were actually actually leaking. This is The following Condition Condition Report Report summaries, also substantiated substantiated by the fact that tests performed performed on the isotopesisotopes from the wetted excerpted excerpted from the table, identify the types of crack in the wall showed showed the isotopes to be older older that those currently in the fuel structural degradation of concern:
structural aging degradation pool. These indicationsindications were coated as aa precautionary precautionary repair. In In addition, addition, thethe spent fuel pool transfer canal liner was also inspected inspected using the same techniquestechniques as as (111)
(III) IP2 Spent Fuel Pool CracklLeak CracklLeak Paths: those used in in the spent fuel pool with the addition of UT where applicable. The The inspections inspections discovered discovered several indications and one weld defect in in the transfer transfer canal CR-IP2-2005-03557 CR-IP2-2005-03557 liner. The weld defect failed the vacuum box test. All of the defects defects and indications indications repaired. These indications were repaired. indications were all the result of original construction construction poor This CR initiated initiated by CA&A CA&A to copycopy a manual manual CR, CR, workmanship issues.
workmanship which which is attached attached to the suggested suggested action section section As a consequence consequence of the originally discovereddiscovered wetted crack in in the spent spent fuel pool below with the original paper operability review. A paper operability south wall, aa Geotechnical Geotechnical Firm was contracted to study the groundwater groundwater flow hairline crack several feet in length length was found at patterns onsite and recommend locations for the installation of groundwater groundwater approximately approximately 60 60 foot level of UnitUnit 2 spent spent fuel fuel monitoring monitoring wells. Several dozen dozen monitoring wells were installed installed throughout the site pool. to monitor the groundwater groundwater for any contamination. Specifics any contamination. Specifics of the CR's listed above above are discusseddiscussed below CR-IP2-2005-04433 CR-I P2-2005-04433 CR-IP2-2005-03557 CR-IP2-2005-03557 A remote visual examination of the Spent Fuel a) a) This CR identifies aa hairline crack crack on IP2 spent fuel pool (SFP) south concrete concrete Pool liner identified identified three potential leak paths paths wall. No history of this condition was identified. identified.
located on the South West West vertical corner weld weld between approximately 17' between 1T and 20' from the top of B&
B & c) The hairline non-propagating non-propagating crack crack was inspected by supervisor of civil-the pool. structural engineering.
engineering. Hairline Hairline crack is typical typical of type which develops during which develops during concrete forming/curing and and will not lead to significant breach. Seepage Seepage is evident of either pinhole leak in in a weld seem of the stainless stainless steel pool interior interior liner, or seepage that entered entered the crack during excavation of adjacent/aboveadjacent/above containment containment soil. The condition was determined determined to be non-threatening non-threatening to structural integrity of the structural integrity the SFP structure.
D, e & & f) Concrete Concrete crack has been temporarilytemporarily covered covered with a stainless stainless steel collection box and the drain is routed to the primary primary auxiliary auxiliary building (PAB)
(PAB) for monitoring. Utilizing industry experience, Florida Power &
periodic monitoring. & Light testing of reinforced concrete exposed exposed to borated water, core samples taken of fuel pool wall for leak leak that went unnoticed unnoticed for 18 monthsmonths to conclude that the leak has no no significant effect on the concrete significant concrete or rebar. The source source of leak was determined to be be from pinhole leak in in the spent fuel pool liner (evaluation of liner plate leak is provided provided in CR-IP2-2005-04433).
G& & h) No augmented augmented or specialspecial inspection during PEO. The SFP concrete concrete structure structure will continue to be monitored monitored fro aging effect under structures monitoring program under structures program during PEO.
CR-IP2-2005-04433 CR-IP2-2005-04433 a) This CR identifies leakage paths on IP2 spent fuel pool (SFP) stainless identifies 3 potential leakage stainless steel liner plate welds. The three and three additional indications indications were vacuum box .
tested with no indicationindication of thru wall leakage. In In addition these 6 locations locations werewere coated coated as preventive measure. Historically, a pinhole leak was found early 90's and nm~.~ri.J::mmmmm::s<~':tm'ffi't"~tl'lo\~ill~~,~~,,~t~'&i:'i&!m~!m!m!m!m='>W.,<<<it:<';.,~~~::"{'f' '::'~~__ ,,>*_J:'id~"~"""""='*,OO.~~~~-:(.;-:::::-:':':::*> *r.:::':~~1::.:~rr'i~~~/;a,):hl<<~~m?m~~;;:>!"t.<:m~
Tuesday, March Tuesday, March 18, 2008 Page46 of 48 Page
Item Request Response
Response
repaired successfully. The cause of pinhole was determined determined to be a poor workmanship workmanship during re-rack re-rack modification.
modification. Specifically, during welding and removal (cutting) activities activities of temporary attachment to the liner plate.
temporary attachment B& & c) Level in the SFP is in in accordance accordance with ITS requirements. Leakage Leakage rate is such such that the pool could be filled in in aa timely fashion if if needed needed to prevent exceeding prevent exceeding specification. No operability operability concern concern exists.
D, e & & f) The repaired repaired area area and other suspect weld areas of the liner plate have have inspected (remote) and tested (vacuum box) with satisfactory been inspected satisfactory results. No other other leaks are identified.
identified.
g & h) No augmented augmented or special inspection during during PEO. The SFP liner will continuecontinue to be managed managed for aging effects under water chemistry control - primary and and secondary, and and Monitoring of spent fuel pool level per Tech Spec. during PEO.
No other significant existing conditions of structural structural aging were identified.
361 IP2/IP3 IP211P3 Operating Related to Aging Operating Experience Related CR-IP2-2004-01347 CR-IP2-2004-01347 Degradation Degradation of Containment Containment Structure, Other Structures, Structures, and Structural Structural Components Components The VC concrete structure is routinely inspected inspected and evaluated evaluated in in accordance with the requirements of the ASME ASME IWL program and the acceptance acceptance criteria criteria developed Based on review of the Condition Report in report IP-RPT-08-00016.
IP-RPT-08-00016. Several inspectionsinspections under under this program have been summaries summaries listed in IP-RPT-06-LRD05, Revision conducted to date and all degradation conducted degradation found has been been documented documented and evaluated.
1, Table 3.1.3 "Operating Experience 1, Experience Applicable Applicable Photographs of all degraded Photographs degraded areas are taken during inspection and compared during each inspection to Structures Structures and Structural Components", the the to those from previous inspections inspections to determine determine whether the degradation degradation is project project team identified a number number of apparently progressing. Enhancements to the documentationdocumentation of degradation degradation are being significant significant conditions of aging degradation degradation of implemented to allow for better implemented better trending trending of these areas. These These enhancements enhancements structures structures that are NOT identified identified in in the LRA, thethe include, but are not limited to, obtaining obtaining critical dimensional dimensional data of degradation degradation PBDs for the StructuresA StructuresA MPS, or the Structures Structures where possible, use of scaling technologies photographs taken and use of technologies for photographs AERM. consistent vantage points for the visual inspections.
inspections. To date, none of the the documented degradation documented degradation is ongoing ongoing based based on comparison of data from previous previous The following following Condition Condition Report Report summaries, summaries, inspections and the identified inspections degradation poses no threat to the ability of the VC identified degradation VC excerpted excerpted from the table, identify the types of concrete concrete structure to perform perform its design design basis function. Details regarding specific regarding the specific structural structural aging degradation degradation of concern: conditions for this CR are provided below.
conditions (IV) IP2 Containment Dome Concrete (IV) Concrete Spalling:
Spalling: a) This CR identifies identifies area area on IP2 containment concrete has spalled containment where concrete spa lied exposing reinforcing reinforcing steel showing showing rust. This condition was noted during the 2000 2000 IWL CR-IP2-2004-01347 CR-IP2-2004-01347 inspection.
inspection. The 2005 IWL inspection inspection found little or no change change of the condition observed in 2000.
The south side of the Containment dome dome in in the the b & c) The findings following the inspection inspection.by by design engineering engineering werewere evaluated evaluated alley between between the Fan building and VC about about 2525 against information regarding against the information regarding margins contained contained inin the Raytheon Raytheon report. The The feet up is spalling in about about 6-7 places. The rebar is evaluation evaluation concluded that the locations locations of the exposed reinforcement, including including thethe exposed to the elements elements and is showing signs of areas areas covered by this Condition Report, are such that even considering considering further loss further loss openings into the concrete rust. The openings concrete are are about 12 of material material due dueto to corrosion over over an extended extended period, there is sufficient margin margin inin the the
. 14 14 inches. design to assure structural integrity of the Concrete Containment under all postulated loads and load combinations. On this basis, the noted noted deficiencies deficiencies do not constitute operability operability or reportability reportability concerns. The spalls occur occur at locations locations where cadweld sleeves have insufficient concrete concrete cover attributed to an original installation deficiency. Cadweld Cadweld splices splices have diameters diameters larger larger than the bar and thus thus have the least amount amount of concrete concrete cover. Rusting Rusting is not active and spalls are in an area where the rebar stresses are low.
d, ee && f) The condition is being monitored monitored under IWL IWL program. Remedial actions actions will be taken taken at any time the spalls degrade degrade further further and are found to affect structural integrity.
g& & h) No augmented augmented or special inspection during PEO. The containment containment concrete structure will continue to be inspected and monitored under the Containment structure Containment Inservice Inspection (CII) - IWL Inservice Program during the PEO.
IWL Program No other significant existing conditions of structural aging were identified.
significant existing identified.
410 410 Are the IP3 compliance IP3 foam tanks required for compliance CLARIFICATION REPONSE Audit Item 105 CLARIFICATION REPONSE (original response in in LR #105,
- 105, letter NL- NL-with 10 CFR 50.48. Why is the enhancement enhancement for 07-153) foam tank inspection inspection only applicable IP3?
applicable to IP3?
Audit Item 105 Clarification Clarification The LRA amendment amendment for Audit Item 105 communicated in 105 communicated in letter NL-07-153, NL-07-153, dated December I(
December 18, 2007, is replaced with the following.
18,2007, LRA Section B.1.14, Fire Water Water System, Enhancements, is revised as follows.
The following enhancements enhancements will be implemented implemented prior to the period of extended extended operation.
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Tuesday, March Tuesday, March 18, 2008 2008 Page 47 of Page of 48
Item Request Response Attributes Affected Affected
- 3. Parameters Monitored Monitored or Inspected Inspected Enhancements Enhancements Revise Revise applicable procedures procedures to inspect the internal surface surface of the foam based based fire fire suppression suppression tanks. Acceptance Acceptance criteria will be enhanced enhanced to verify no significant significant corrosion.
corrosion.
- 4. Detection of Aging Aging Effects
- 6. Acceptance Criteria Acceptance Criteria LRA LRA Section Section A.2.1.13, Fire Water Water System Program, fourth paragraph, paragraph, is revised revised to add the the following.
Revise procedures to inspect the internal Revise applicable procedures internal surface surface of the foam-based fire fire suppression suppression tanks. Acceptance Acceptance criteria will be enhanced to verify no significant significant corrosion.
corrosion.
562 In the series of LRA Tables 3.3.2-19-xx-IP2 In 3.3.2-19-xx-IP2 and LRA LRA Tables 3.3.2-19-12-1P2, 3.3.2-19-2-1P3, 3.3.2-19-14-1P3, 3.3.2-19-12-IP2, 3.3.2-19-2-IP3, 3.3.2-19-14-IP3, and 3.3.2-19-27-IP3 3.3.2-19-27-1P3 3.3.2.19-xx-IP3, 3.3.2.19-xx-IP3, there are line items that specify will be revised to list the Periodic Surveillance and Preventive Maintenance and Preventive Maintenance "cracking-fatigue" "cracking-fatigue" as the as the aging aging effect effect and "TLAA- Program managing cracking due to thermal fatigue on carbon steel portions of Program for managing metal fatigue" as the aging mamagement program. program. sight glasses. LRA 3.4.1, Item 3.4.1-1, LRA Table 3.4.1, 3.4.1-1, and LRA Section 3.4.2.2.1 3.4.2.2.1 will be be The previously accepted accepted response to audit item item revised to describe use of the Periodic Surveillance Surveillance and Preventive Preventive Maintenance Maintenance 233'stated 233 *stated that the sight glasses glasses should not be be Program to manage Program manage cracking cracking due to thermal fatigue on carbon steel portions of sight sight included included as part of the TLAA evaluation but should should glasses. LRA section B.1.29 B.1.29 will be revised to inspect the carbon steel steel portionsportions of be identified identified with the One-Time Inspection Inspection sight glasses in in the IP2 feedwater, IP3 aux steam steam and condensate return, IP3 IP3 program as an aging management management program program to condensate condensate transfer, and IP3 heater heater drain/moisture drain/moisture separator drains/vents drains/vents systems.
confirm the absence absence of cracking due to thermal fatigue. For sight glass line items in in LRA Tables Tables Information to be added to the LRA.
3.3.2-19-12-1P2, 3.3.2-19-2-IP3, 3.3.2-19-12-IP2, 3.3.2-19-2-1P3, 3.3.2-19-14-IP3, 3.3.2-19-14-1P3, and 3.3.2-19-27-IP3 3.3.2-19-27-1P3 that identify TLAA-Metal Fatigue in the AMP column, TLAA-Metal TLAA-Metal Fatigue Fatigue was changedchanged to the One-Time Inspection Inspection Program NL-07-153 to the NRC dated by letter NL-07-153 December dated December 18, 2007. The One-Time 18,2007. One-Time Inspection Program is not an appropriate appropriate aging management management program for "cracking-fatigue" on the carbon steel portions portions of sight glasses and a different different AMP should be be cited.
cited.
563 Audit item #63 is being clarified to reflect LRA B.1.22 addresses the plant speCificspecific AMP for non-EQ bolted cable connections.
discussion discussion with the NRC staff associated associated with draft Based on discussion with the NRC staff, the AMP discussion discussion for using visual LR-ISG-2007-02.
LR-ISG-2007-02. inspection is being clarified to further explain the types of connections connections and personnel safety issues safety issues of opening energized of opening energized equipment.
equipment.
An example example of where visual inspection is acceptable acceptable is motor connections connections where the the motor lead is connected connected to the field cable in a local junction junction box. Because Because of of personnel safety practices personnel practices the junction box cover would not be removed when the the cable is energized, energized, so thermography could only be performed with the junction box cover inin place, which which may not provide accurate results. Another Another example example of using inspection would be in remote visual inspection remote switchgear switchgear panels where the entire connection entire connection to the bus is covered covered with tape or an insulating boot. For both of these examples, contact resistance measurementswould resistance measurements* would require the destructive examination