PLA-6375, Transmittal of Responses to Requests for Additional Information License Renewal Application Sections B.2.11, B.2.13, B.2.16, and B.2.17

Transmittal of Responses to Requests for Additional Information License Renewal Application Sections B.2.11, B.2.13, B.2.16, and B.2.17

ML081980121
Person / Time
Site:	Susquehanna
Issue date:	06/30/2008
From:	Mckinney B Susquehanna
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
PLA-6375
Download: ML081980121 (42)

Text

Brltt T. McKinney Sr. Vice President

& Chief Nuclear Officer PPL Susquehanna, LLC 769 Salem Boulevard Berwick, PA 18603 Tel. 570.542.3149 Fax 570.542.1504 btmckinney@pplweb.com Pp I U. S. Nuclear Regulatory Commission Document Control Desk Mail Stop OP 1 -17 Washington, DC 20555 SUSQUEHANNA STEAM ELECTRIC STATION REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2, LICENSE RENEWAL APPLICATION (LRA)SECTIONS B.2.11, B.2.13, B.2.16, and B.2.17 Dock(PLA-6375 et Nos. 50-387 and 50-388 lReferences.

1) PLA-6110, Mr. B. T McKinney (PPL) to Document Control Desk (USNRC),"Application for Renewed Operating License Numbers NPF-14 and NPF-22, dated September 13, 2006.2) Letter from Ms. E. H. Gettys (USNRC) to Mr. B. T. McKinney (PPL),"Request for Additional Information for the Review of the Susquehanna Steam Electric Station, Units 1 and 2 License Renewal Application, "dated May 30, 2008.3) PLA-6241, Mr. B. T. McKinney (PPL) to Document Control Desk (USNRC),"Application for Renewed Operating License Numbers NPF-14 and NPF-22,Requests for Additional Information

-LRA Section 2.3.3..13, "dated July 24, 2007.In accordance with the requirements of 10 CFR 50, 51, and 54, PPL requested the renewal of the operating licenses for the Susquehanna Steam Electric Station (SSES)Units 1 and 2 in Reference 1.Reference 2 is a request for additional information (RAI) related to License Renewal Application (LRA) Sections B.2.11, B.2.13, B.2.16, and B.2.17.Reference 3 is listed because the response to RAI B.2.17-2 requires a revision to information previously submitted in PLA-6241, as discussed in Attachment 2.The enclosure to this letter provides the additional information requested by NRC and associated LRA changes. The RAI responses are numbered consistently with the RAI questions in Reference

2. The enclosure also contains revisions to two existing license Document Control Desk PLA-6375 renewal regulatory commitments, discussed in the responses to RAI B.2.13-1 and RAI B.2.17-4.The attachments contain LRA amendments (Attachments 1 and 2) and revised boundary drawings (Attachment

3) referenced in the RAI responses.

A new license renewal commitment is also included in Attachment 1 in response to RAI B.2.1 1-1. This new commitment credits a new aging management program for high pressure turbine casing inspections.

If you have any questions, please contact Mr. Duane L. Filchner at (610) 774-7819.I declare, under penalty of perjury, that the foregoing is true and correct.Executed on: 61 3'P01 o-(B3 ~Kinney

Enclosure:

PPL Responses to NRC Request for Additional Information (RAI)Attachments:

Attachment 1 -Response to RAI B.2.1 1-1 Attachment 2 -Response to RAI B.2.17-2 Attachment 3 -Revised SSES License Renewal Boundary Drawings Copy: NRC Region I Ms. E. H. Gettys, NRC Project Manager, License Renewal, Safety Mr. R. R. Janati, DEP/BRP Mr. F. W. Jaxheimer, NRC Sr. Resident Inspector Mr. A. L. Stuyvenberg, NRC Project Manager, License Renewal, Environmental Enclosure to PLA-6375 PPL Responses to NRC Request for Additional Information (RAI)

Enclosure to PLA-6375 Page 1 of 16 RAI B.2.11-1 In LRA Table 3.4.2-4, Condenser and Air Removal System, the Flow-Accelerated Corrosion (FAC) Program is credited with managing loss of material for carbon steel condensers (shell) in a treated water environment.

In Table 3.4.2-7, Main Turbine System, the Flow-Accelerated Corrosion (FAC) Program is credited with managing loss of material for carbon steel turbine casings (high pressure) in a treated water environment.

Please confirm that these components are included in the scope of the existing FAC Program and if not, please justify why the LRA Section B.2. 11 is not enhanced to include these components.

PPL Response: These components are not included in the scope of the existing FAC Program. A revision to LRA Section B.2.11 is not required to include these components as discussed below.LRA Section 2.3.4.4, Reason for Scoping Determination, states that the Condenser and Air Removal System is credited for providing support for safety-related components connected to the Main Steam System to preclude an adverse effect on safety-related equipment through spatial interaction.

Loss of material due to FAC is identified as an aging effect requiring management for the high pressure (HP) condenser shell. However, the HP condenser shell is not within the scope of the FAC program, and further analysis does not support adding it to the program.Currently, the HP Condenser shell, 1(2)E108A, is credited as the anchor for piping line 4"-EAD- 114 (214). However, based on further review, another anchor was identified for this pipe line before it reaches the condenser.

The anchor is located just inside the turbine building where the line enters from the reactor building.

As a result, the HP Condenser shell is no longer credited as the anchor and does not provide a structural integrity function.

With elimination of the structural integrity function, there are no aging effects that require management for the HP condenser shell, and therefore, the FAC Program does not need to be credited for aging management.

The LRA changes resulting from elimination of the HP condenser as an anchor are identified in Attachment 1.LRA Section 2.3.4.7, Main Turbine System, states that the main turbine is credited for providing support for the safety-related functional boundary with the Main Steam System. Loss of material due to FAC is identified as an aging effect requiring management for the carbon steel casing of the HP turbine. However, the HP turbine is not within the current FAC Program and based on further analysis does not need to be added because a different aging management program will be credited.

Enclosure to PLA-6375 Page 2 of 16 A new plant-specific program, Preventive Maintenance Activities

-Main Turbine Casing, is credited with managing loss of material due to FAC for the HP turbine. This program is a new LRA Commitment for license renewal and is based on existing plant activities.

The LRA changes resulting from crediting-the new aging management program"Preventive Maintenance Activities

-Main Turbine Casing" are identified in Attachment 1 as new LRA Commitment 55.RAI B.2.11-2 Please provide information on how SSES expands sample size. What acceptance criterion is used for sample expansion?

Is it related to thickness or to wear rates?PPL Response: The SSES FAC Program Procedure requires an inspection sample expansion "if the remaining life of an inspected component cannot be calculated to be at least one operating cycle." The remaining life is the time for the component wall thickness to reach the Code minimum required thickness based on an evaluation of the ultrasonic (UT) inspection data. The remaining life calculation is based on the measured component wall thickness and the calculated wear rate.The FAC Program Procedure provides additional guidance when the remaining life is adequate for another operating cycle, but the inspection results are other than what was expected.

This guidance is consistent with EPRI NSAC-202L, and requires that "If inspection results are unexpected and inconsistent with predictions and have a significant negative effect on component remaining life, the reasons for those inconsistencies shall be investigated.

An updated FAC analysis should be performed, additional inspections conducted, and material determinations made, as appropriate." Determination ofunexpected and inconsistent with predictions" is left to the judgment of the engineers performing and reviewing the component UT data evaluation.

The reviewer of the UT data evaluation is required to be task certified.

This guidance ensures that if unexpected results are obtained, a review of the affected piping system is performed to determine if the inspection coverage of the system (i.e., past inspections and inspections performed during the current outage) are sufficient to bound the condition identified.

Expanded sample inspections are specified to capture locations with the highest probability of significant wear. This provides a higher level of confidence in the overall integrity of the piping system over the next operating cycle.No LRA changes are required as a result of this response.

Enclosure to PLA-6375 Page 3 of 16 RAI B.2.13-1 In Table 3.2.2-7, Standby Gas Treatment System (SGTS), the Piping Corrosion Program is credited for managing the aging effect of loss of material for loop seal piping and valve bodies. However, a review of the AMP Evaluation results document, LRPD-05, attachment 2.11, section 2.1 .b, indicates that SGTS is not included in the scope of the Piping Corrosion Program. Please justify why it is not included.Please justify how the Piping Corrosion Program will manage the aging effects of these components in SGTS.PPL Response: Part 1 (Response to First Paragraph of the RAI): LRA Table 3.2.2-7 correctly credits the Piping Corrosion Program for managing loss of material for loop seal piping and valve bodies in the Standby Gas Treatment System. The AMP evaluation results basis document should have included the Standby Gas Treatment System (SGTS) as within the scope of the Piping Corrosion Program. The LRA Commitment 13 is revised to include the SGTS loop seal piping and valves. The license renewal application is amended as follows: Table A-i, SSES License Renewal Commitments) Table A-l, Item number 13 for the Piping Corrosion Program (on LRA page A-36) is revised by addition (bold italics) and deletion (sikethfeugh) as follows: 13) Piping Existing program is credited with the A. 1.2.38 ,,geilg Corrosion following enhancement:

Prior to the Program

• Include the Standby Gas period of Treatment System loop seals extended within the scope of the program. operation A.1.2.38 Piping Corrosion Program Section A.1.2.38 (LRA page A-17) is revised by addition (bold italics), after the second paragraph, as follows: Prior to the period of extended operation, the Piping Corrosion Program will be enhanced to include the Standby Gas Treatment System loop seals.

Enclosure to PLA-6375 Page 4 of 16 Table B-2, Consistency of SSES Aging Management Programs with NUREG-1801 The following entry in Table B-2 (on LRA page B-17) is revised by addition (bold italics).New / Consistent Exceptions Program Name Existing with NUREG- to NUREG- Plant -Enhancement 1801 1801 Specific Required Piping Corrosion Existing -- Yes Yes Program B.2.13 Piping Corrosion Program The paragraph "Required Enhancements" in Section B.2.13 (LRA page B-45) is revised by addition (bold italics) and deletion (str4kethregh):

Nefie-Prior to the period of extended operation, the enhancement listed below will be implemented in the identified program element: Scope of Program -The program scope will be enhanced to include the Standby Gas Treatment System loop seals.Part 2 (Response to Second Paragraph of the RAI): The internal environment for the loop seals on the mist eliminators, sub-components of the SGTS filter trains, and the associated isolation valves is raw water from the Service Water System.As described above, the scope of the Piping Corrosion Program will be enhanced to include the SGTS components.

Upon inclusion of the SGTS components within the scope of the Piping Corrosion Program, they will be monitored and inspected for loss of material in accordance with SSES specifications.

The program monitors and trends piping corrosion to identify piping requiring increased inspection frequency and to anticipate when piping will require replacement.

RAI B.2.13-2 The staff noted that the current "scope of program" program element, as described in the LRA, does not include commitments for two GL 89-13 guidelines incorporated in GALL Enclosure to PLA-6375 Page 5 of 16 AMP XI.M20. The specific components of the GL 89-13 program missing from the Piping Corrosion Program are a system walkdown inspection to ensure compliance with the CLB and a review of maintenance, operating, and training practices and procedures.

Please justify why this is not an exception to the GALL AMP.PPL Response: The program description for GALL AMP XI.M20 states that the open-cycle cooling water (OCCW) system program relies on implementation of the recommendations of GL 89-13. PPL provided responses to GL 89-13 through a series of correspondence with the NRC in the 1990's. The docketed correspondence contains PPL's commitments associated with GL 89-13. With respect to aging management, GALL XI.M20 states that the program addresses the aging effects of material loss and fouling due to micro- or macro-organisms and various corrosion mechanisms.

The two components of GL 89-13 mentioned in the subject RAI were one-time actions unrelated to aging management.

The recommended action in GL 89-13 (to confirm by means of system walkdown inspections that the as-built system is in accordance with the CLB) was completed, as documented in PPL correspondence to NRC via PLA-3349 [H.W. Keiser to W.T.Russell, "Response to Generic Letter 89-13," dated February 23, 1990], and PLA-3489[H.W. Keiser to T.T. Martin, "12/90 Confirmatory Response to Generic Letter 89-13," dated December 14, 1990]..The recommended action in GL 89-13 to confirm, by means of reviews that maintenance, operating, and training practices and procedures that involve the service water system are adequate, was completed as documented in PLA-3349.These recommended actions were specific considerations of GL 89-13 related to the as-built system compared to the CLB and the reduction of human errors in the operation, repair, and maintenance of the service water system. These specific actions do not involve the management of the effects of aging. These actions have been completed, as stated above, and do not constitute a required part of an effective aging management program, as evidenced by the fact that they are not further mentioned in the other elements of GALL XI.M20. Therefore, they do not constitute exceptions to the GALL AMP.No LRA changes are required as a result of this response.RAI B.2.13.-3 In a response to GL 89-13, SSES took an exception to heat transfer capability testing.The GALL Program AMP XI.M20, in the "parameters monitored/inspected" program Enclosure to PLA-6375 Page 6 of 16 element, recommends testing to ensure heat transfer capabilities.

In the LRA section B.2.13, SSES has not taken an exception to this program element.Please justify why no exception is taken in the application.

PPL Response: The "parameters monitored

/ inspected" program element of the GALL Program AMP XI.M20 states that components, including heat exchangers, that are part of the OCCW system or that are cooled by the OCCW system are periodically inspected, monitored, or tested to ensure heat transfer capabilities.

The applicable SSES program element includes inspection and monitoring.

Since the GALL program element uses the word"or," no exception is taken.However, the "scope" program element of the GALL Program AMP XI.M20 states that the guidelines of NRC GL 89-13 include a test program to verify heat transfer capabilities.

There is no test program at SSES to verify the heat transfer capability.

However, laboratory testing of a representatively fouled ECCS room cooler cooling coil, and of prototypes representing replacement cooling coils, under post accident conditions demonstrated adequate heat transfer capability

[PLA-3776, 5/92 Confirmatory Response to Generic Letter 89-13, June 11, 1992]. Additionally, based on past monitoring in response to NRC GL 89-13, PPL has demonstrated that existing activities have been acceptable to detect degradation prior to the loss of component intended functions and will remain adequate for the extended period of operation.

The license renewal application is amended as follows to include an additional exception to the Piping Corrosion Program: B.2.13 Piping Corrosion Program> Section B.2.13 (LRA page B-45) is revised by addition (bold italics) as follows: NUREG-1801 Consistency The Piping Corrosion Program is an existing SSES program that is consistent with the 10 elements of an effective aging management program as described in NIUREG- 1801,Section XI.M20, "Open-Cycle Cooling Water System," with the following exceptions:

Enclosure to PLA-6375 Page 7 of 16 Exceptions to NUREG-1801 Program Elements Affected: " Scope -NUREG-1801 states that the guidelines of NRC GL 89-13 include a test program to verify heat transfer capabilities.

There is no test program at SSES to verify the heat transfer capability.

In response to GL 89-13, PPL conducted laboratory testing of cooling coils to demonstrate adequate heat transfer capability." Preventive Actions -NUREG-1801 states that system components are lined or coated. SSES subject components are lined or coated only where necessary to protect the underlying metal surfaces." Monitoring and Trending -NUREG- 1801 states that testing and inspections are performed annually and during refueling outages. Inspection frequencies for the Piping Corrosion Program are based on operating conditions and past history; flow rates, water quality, lay-up and heat exchanger design.RAI B.2.13-4 In the "operating experience" program element of LRA Section B.2.13, the LRA states that SSES has programs in place with operating experience to demonstrate that the effects of aging on the service water systems, and on the safety-related heat exchangers that they serve, will be effectively managed during the period of extended operation.

Please provide some specific examples of issues that were found in the condition reports.PPL Response: Following are some specific examples of operating experience associated with the SSES piping corrosion program found in condition reports.A portion of the service water piping associated with the Turbine Building Closed Cooling Water heat exchanger was being replaced due to an identified through-wall leak.During that replacement, inspection revealed pipe wall thinning beyond the bounds of the planned pipe replacement.

A work order was generated to replace the additional piping during the next Unit 1 refueling outage. In addition, another work order was generated to replace the same piping on Unit 2 during the next Unit 2 refueling outage. The Unit 2 Enclosure to PLA-6375 Page 8 of 16 replacement is being done as aprecautionary measure due to the potential for leakage to develop.UT pipe wall thickness measurements that were below minimum requirements were found in the Emergency Service Water (ESW) System downstream of the ESW throttle valves in the diesel generators system. The review of the inspection results concluded the condition was due to cavitation damage. The resolution includes plans to inspect the same areas in the other diesels and to replace or repair the piping before failure. Some pipes have been replaced and others are planned for replacement.

During the periodic cleaning and inspection of the Reactor Core Isolation Cooling System (RCIC) lube oil cooler, and the associated eddy current testing, tube wall erosion was discovered.

As a result two tubes were plugged and the preventive maintenance frequency was increased to track tube condition.

During the periodic cleaning and inspection of a Reactor Building Closed Cooling Water Heat Exchanger, several areas of the end covers and shell showed some erosion damage.Weld repair and recoating were performed as part of the preventive maintenance activity.No further action was required.As a result of the cleaning and inspection activities of one of the Unit 2 generator stator coolers (not in LR scope), pitting damage was noted on the service water inlet and outlet.A work order was generated to repair and recoat these damaged areas. An action request was generated to open and inspect the other coolers, both Unit I and Unit 2.During work on one of the diesel generator lubricating oil coolers, coating damage was discovered on the waterbox divider. The repair involved weld build-up to restore the divider and recoating which were completed prior to any loss of function.No LRA changes are required as a result of this response.RAI B.2.16-1 The LRA Section B.2.16 takes an exception that the halon/carbon dioxide (C02)suppression systems and the fuel oil supply line for the diesel-driven fire pump, inspections and tests included in the Fire Protection Program (and addressed in the Technical Requirements Manual) are not credited with aging management but do provide for periodic observation of the related components.

While halon/C02 and fuel supply line internal conditions are not directly inspected or evaluated during these tests and inspections, they do provide indirect confirmation of whether degradation has occurred, prior to a loss of function.

Enclosure to PLA-6375 Page 9 of 16 1. Please justify why these tests and inspections, if required, are not credited for license renewal.2. Please justify why the internal surfaces are not inspected.

PPL Response: 1. The periodic tests and inspections for the halon and carbon dioxide (CO 2) suppression systems, and for the diesel engine-driven fire pump, are included in the site Fire Protection Program to provide assurance that operability requirements are met. As stated in LRA Section B.2.16, these operability determinations provide for periodic observation of related components.

However, these tests and inspections for operability are not credited with aging management of passive halon/C0 2 and fuel oil supply line components during the period of extended operation for the following reasons: a) For halon/CO 2 suppression systems, license renewal evaluations summarized in LRA Table 3.3.2-13 determined that: 1) halon/CO 2 spray nozzle, tubing and valve body materials (stainless steel and copper alloys) are not susceptible to aging in the ambient air environment (indoor) to which they are exposed, 2) consistent with NUREG- 1801, there are no aging effects that require management for the halon/CO 2 components with an internal dry gas environment, and 3) consistent with NUREG-1801, another program (System Walkdown Program)is credited with aging management of susceptible materials (steel and cast iron) exposed to an external environment of indoor air.b) For the diesel engine-driven fire pump, license renewal evaluations summarized in LRA Table 3.3.2-13 indicate that the Fuel Oil Chemistry Program and Chemistry Program Effectiveness Inspection are credited for management of the copper fuel oil supply line (tubing), consistent with NUREG- 1801.2. Internal surfaces of halon/CO 2 suppression components are not inspected because there are no aging effects that require management in the dry gas environments, consistent with NUREG- 1801; and normally empty halon/CO 2 spray nozzle, tubing and valve body materials (stainless steel and copper alloy) are not susceptible to aging in the ambient air (indoor) environment that they Contain. Internal surfaces of the diesel engine-driven fire pump fuel oil supply line are included in the sample population for, and scope of, the Chemistry Program Effectiveness Inspection described in LRA Section B.2.22.No LRA changes are required as a result of this response.

Enclosure to PLA-6375 Page 10 of 16 RAI B.2.17-1 LRA Table 3.3.2-7, Standby Gas Treatment System (SGTS), credits the Fire Water System Program for managing loss of material for valve bodies (deluge).

However, the SGTS is not included in the list of systems in the scope of the Fire Water System program. Please clarify why the SGTS is not in scope.PPL Response: The Standby Gas Treatment System is one of the systems in the scope of the Fire Water System Program. As listed in LRA Section 3.2.2.1.7, the Fire Water System Program manages aging effects for Standby Gas Treatment System components.

These components include the piping and valves associated with deluge of the charcoal adsorbers.

LRA Table 3.2.2-7 contains a corresponding entry for valve bodies (deluge).LRA Appendices A. 1.2.19 and B.2.17 indicate that "The Fire Water System Program (sub-program of the overall Fire Protection Program) is an existing program that is described in the Fire Protection Review Report (FPRR) and which is credited with aging management of the water suppression components in the scope of license renewal." As the piping and valves associated with deluge in the SGTS charcoal adsorbers are water suppression components in the scope of license renewal, they are in the scope of the Fire Water System Program.For clarity and completeness, the LRA is amended as follows to add the SGTS deluge piping as a component in LRA Table 3.2.2-7:

Enclosure to PLA-6375 Page 11 of 16 The following line item is added to Table 3.2.2-7, on LRA page 3.2-103: Table 3.2.2.-7 Aging Management Review Results -Standby Gas Treatment System Component

/ Intended Material Environment Aging Effect Aging NUREG-1801 Table 1 Item Notes Commodity Function Requiring Management Volume 2 Item Management Programs Piping (deluge) Pressure Carbon Steel Raw Water Loss of Fire Water VII.G-24 3.3.1-68 A Boundary (Internal)

Material System Program Indoor Air Loss of System V.B-3 3.2.1-31 A (External)

Material Walkdown Program Enclosure to PLA-6375 Page 12 of 16 RAI B.2.17-2 LRA Table 3.3.2-13 credits the Fire Water System program to manage reduction in heat transfer for heat exchanger tubes. However, the LRA Section B.2.17 states that this program is consistent with GALL AMP XI.M27, which focuses on managing the aging effect of loss of material and not reduction in heat transfer.Please justify how this program will manage reduction in heat transfer.PPL Response: The focus of the Fire Water System program is on managing loss of material due to corrosion, MIC or biofouling of components in fire protection systems exposed to water, and includes actions to ensure no significant corrosion, MIC or biofouling has occurred.The rationale for crediting the Fire Water System Program for managing reduction in heat transfer for heat exchanger tubes was that fouling of the heat transfer surfaces, if any, is expected to be from corrosion products in the fire suppression water, which is the same water used for cooling the heat exchangers.

As such, the same actions that manage loss of material in fire suppression components were considered to manage reduction in heat transfer of the associated heat exchangers.

Upon further consideration, the Heat Exchanger Inspection program has been identified as a more appropriate program for managing reduction (loss) of heat transfer for the diesel engine driven fire pump heat exchangers.

Therefore, the LRA is amended to credit the Heat Exchanger Inspection for managing reduction of heat transfer for these heat exchangers, as shown in Attachment 2.Attachment 2 includes changes to information previously provided in response to NRC RAI 2.3.3.13-5 via PPL letter PLA-6241 (Reference 3). These changes make the aging management programs credited for managing the aging effects of the heat exchanger originally identified in LRA Table 3.3.2-13 and the oil cooler identified in PLA-6241 consistent.

The Fire Water System Program is credited with managing loss of material and the Heat Exchanger Inspection is credited with managing reduction of heat transfer for the two heat exchangers associated with the diesel driven fire pump.RAI B.2.17-3 In the "operating experience" program element of LRA Section B.2.17, the LRA states that a search of condition reports was performed for the Fire Protection System. When conditions were found that required correction they were repaired in accordance with the site corrective action program.Please provide. some specific examples of issues that were found in the condition reports.

Enclosure to PLA-6375 Page 13 of 16 PPL Response: Specific examples of issues found in the condition reports are as follows: A leak was identified in the twelve inch fire protection header piping from the discharge of the electric fire pump in the Circulating Water Pump House. Ultrasonic inspection data taken on either side of the leak revealed several other sections with unacceptable wall thickness.

As a result, a section of electric fire pump discharge pipe was replaced.A pinhole leak was identified in the fourteen inch fire pump suction supply header fire protection piping, three feet downstream from the cross tie isolation valve, in the Circulating Water Pump House. The repair consisted of a temporary patch followed by replacement of a section of the fire protection piping.A leak was identified in the six inch fire protection piping in the Circulating Water Pump House. The leak was small, about 6 drops per minute. The repair consisted of a temporary patch followed by replacement of a section of the six inch fire protection line and the adjoining elbow.A small leak was discovered in the fourteen inch fire protection pump suction line in the Circulating Water Pump House. The leak was small and had no effect on the system operability.

Ultrasonic inspection data was taken on either side of the leak to determine the condition of the adjacent piping. The leak was repaired by replacing a section of the pump supply piping.No LRA changes are required as a result of this response.RAI B.2.17-4 CR 233774 addresses through wall leak on a fire water piping header. During the investigation, it was determined that water does not drain properly and stays in the pipe causing corrosion.

Stagnant water in low drainage locations is very conducive to pitting corrosion resulting in through wall leaks. The evaluation also stated that the system is between 15 to 20 years old, and recommended that since it has held up for so long and the corrosion process takes many years, that no changes be made. The expectation was that another 20 or so years of plant life can be had from minor pipe repairs. There were several other instances identified of through wall leakages in the fire water headers.(a) Since license renewal will extend the life by another 20 years, please explain if any changes are proposed for the fire water system piping to alleviate this issue.

Enclosure to PLA-6375 Page 14 of 16 (b) Please confirm if representative portions of above ground piping that are included in the enhancement for wall thickness measurement by UT will include the piping where stagnant water is present.PPL Response: (a) No changes are proposed to fire water system piping to alleviate through wall leaks.The fire protection (sprinkler) piping identified by CR233774 is normally dry and is not in the scope of license renewal. In addition, the leaks have not resulted in loss of the intended function.

The Fire Water System Program manages the aging of the fire protection piping by evaluating the issues that are identified during station activities, including walkdowns.

Specifically, any leaking piping or piping components, such as may result from corrosion, are identified to engineering for evaluation, including an evaluation for operability.

The extent of the repair itself is determined by the evaluation, and could include pipe replacement, depending on the extent of the corrosion.

This has proven to be an effective way to manage the aging of the fire water piping.(b) Representative portions of above ground piping, which may contain stagnant water, will be included in the enhancement for wall thickness measurement by UT. In addition to the monitoring, evaluation and repair approach described above, a representative portion of dry-pipe sprinkler system piping will be ultrasonically tested (UT) to provide further assurance that the intended function is maintained consistent with the CLB through the period of extended operation. (This is a revision to LRA Commitment 46)Therefore, the LRA is amended as follows to show addition of the dry pipe to the ultrasonic testing enhancement.

A.1.2.19 Fire Water System The second paragraph under Fire Water System Program in Section A. 1.2.19 (LRA page A-11) is revised by addition (bold italics) as follows: Prior to the period of extended operation, the Fire Water System Program will be enhanced to incorporate sprinkler head sampling/replacements, in accordance with NFPA 25, and ultrasonic testing of representative above ground portions of water suppression piping that are exposed to water but which do not normally experience flow or are associated with a dry-pipe sprinkler system and may contain stagnant water.

Enclosure to PLA-6375 Page 15 of 16 Table A-1 SSES License Renewal Commitments The second bullet in Table A-1, Item Number 46) Fire Water System Program (LRA page A-53) is revised by addition (bold italics) as follows: I1 46) Fire Water System Program Existing program is credited with the following enhancements: " The Fire Water System Program will be revised to incorporate sprinkler head sampling/replacements, in accordance with NFPA 25." Ultrasonic testing of representative above ground portions of water suppression piping that are exposed to water but which do not normally experience flow or are associated with a dry-pipe sprinkler system and may contain stagnant water.A.1.2.19 Prior to the period of extended operation.

Enclosure to PLA-6375 Page 16 of 16 B.2.17 Fire Water System Program The last paragraph under "Program Description" in LRA Section B.2.17 (LRA page B-53) is revised by addition (bold italics) as follows: Program Description Prior to the period of extended operation the Fire Water System Program will be enhanced to incorporate sprinkler head sampling/replacements, in accordance with NFPA 25, and ultrasonic testing of representative above ground portions of water suppression piping that are exposed to water, but which do not normally experience flow, or are associated with a dry-pipe sprinkler system and may contain stagnant water.> The second bullet under "Required Enhancements" in LRA Section B.2.17 (LRA pages B-53 and B-54) is revised by addition (bold italics) as follows:* Parameters Monitored or Inspected, Detection of Aging Effects -Ultrasonic testing of representative portions of above ground fire protection piping that are exposed to water, but do not normally experience flow, or associated with a dry-piping sprinkler system and may contain stagnant water will be performed after the issuance of the renewed license but prior to the end of the current operating term and at reasonable intervals thereafter, based on engineering review of the results.> The last paragraph under "Conclusion" in LRA Section B.2.17 (LRA page B-55) is revised by addition (bold italics) as follows: Conclusion Enhancement of the Fire Water System Program to address sprinkler head testing/replacement and ultrasonic testing of water-suppression lines that do not normally experience flow or are associated with a dry-pipe sprinkler system and may contain stagnant water will provided further assurance that aging effects are managed and subject components will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation.

Attachment 1 to PLA-6375 Response to RAI B.2.11-1 Attachment 1 to PLA-6375 Page 1 of 12 The following LRA Sections and Tables are revised in response to RAI B.2.11-1 : 2.3.4.4 Condenser and Air Removal System The following drawings under the License Renewal Drawing heading (on LRA page 2.3-128) are revised to indicate the anchor inside the turbine building provides the structural integrity function.

The revised drawings are included as Attachment 3.S 0 Unit 1: LR-M- 105 sheet 2 (Revision 3)Unit 2: LR-M-2105 sheet 2 (Revision 2)The following entries in Table 2.3.4-4 (on LRA page 2.3-128) are revised by deletion (st-Fkeaffough).

Table 2.3.4-4 Condenser and Air Removal System Components Subject to Aging Management Review Component Type Intended Function (as defined in Table 2.0-1)Bolting ICTM Volume Structural Integrity Condensers (shell, inlet/outlet water boxes, ICTM Volume tubes, tubesheet, tube plugs)Codeses(shell) 1(2)E!08A.

ICMVeKWRG S-tructuOWral IntegritY Flexible connections (expansion joints) ICTM Volume Piping ICTM Volume Attachment 1 to PLA-6375 Page 2 of 12 3.4.2.1.4 Condenser and Air Removal System) The following entries under the Aging Management Programs heading (on LRA page 3.4-6) are revised by deletion Aging Management Programs The following aging management programs manages the aging effects for the Condenser and Air Removal System components: " Bolting Integrity Program" BWR Water- Chemistr~y Proagram" Flow Acceler-ated Coffosion (FAG) Proagram"Ssem ldown Program~3.4.2.1.7 Main Turbine System The following entries under the Aging Management Programs heading (on LRA page 3.4-9) are revised by addition (bold italics) and deletion (strikethfeugh).

Aging Management Programs The following aging management programs manage the aging effects for the Main Turbine System components:

o Bolting Integrity Program o BWR Water Chemistry Program" Flow Acceler-ated Coffoesion (FAG) Proegram o Preventive Maintenance Activities

-Main Turbine Casing* System Walkdown Program Attachment 1 to PLA-6375 Page 3 of 12 3.4.3 ConclusionsThe following entries in Table 3.4.1 (on LRA pages 3.4-29 and 3.4-32), Table 3.4.2-4 (on LRA page 3.4-47), and in the Plant-Specific Notes table (on LRA page 3.4-70) are revised by addition (bold italics) and deletion (stfikedhfettgh).

Table 3.4.1 Summary of Aging Management Programs for Steam and Power Conversion Systems Evaluated in Chapter VIII of the GALL Report Item Component

/ Commodity Aging Effect I Aging Management Further Discussion Number Mechanism Programs Evaluation Recommended 3.4.1-29 Steel piping, piping components, Wall thinning due to Flow-Accelerated No Consistent with NUREG-1 801.and piping elements exposed to flow-accelerated orrosion The Flow-Accelerated Corrosion steam or treated water corrosion (FAC) Program is credited to manage loss of material due to flow-accelerated corrosion (FAC)for steel piping and piping components.

T-he-F-Gw-Accelerated Croso Program i s also credited-to_ m-anage loss of material due to FAC for attached s'teel-. con_.dPens shells;-And- tu-rbinoe casinOg. A Note C is used. The Preventive Maintenance Activities

-Main Turbine is credited to manage loss of material due to FAC for the high pressure casing of the main turbine.

Attachment 1 to PLA-6375 Page 4 of 12 Table 3.4.1 Summary of Aging Management Programs for Steam and Power Conversion Systems Evaluated in Chapter VIII of the GALL Report Item Component

/ Commodity Aging Effect I Aging Management Further Discussion Number Mechanism Programs Evaluation Recommended 3.4.1-37 Steel, stainless steel, and nickel- Loss of material due Water Chemistry No Consistent with NUREG-1 801.based alloy piping, piping to pitting and crevice The BWR Water Chemistry components, and piping corrosion Program is credited to manage elements exposed to steam loss of material for steel and stainless steel piping, piping components, and piping elements exposed to treated water (liquid and steam phases).The BWR Water Chemistry Program is also credited to manage loss of material for stainless steel spargers exposed to treated water (liquid and steam phases) and steel condenser shells and turbine casings under this item. Note C is used.

Attachment 1 to PLA-6375 Page 5 of 12 Table 3.4.2-4 Aging Management Review Results -Condenser and Air Removal System Component

/ Intended Aging Effect Aging NUREG-1801 Commodity Function Material Environment Requiring Management Volume 2 Table 1 Item Notes C m tt [Management Programs.

Item Ceadenser-s ICTM Vlume/ CGabe-n Steel Treated Water Lss of Mater.ial BWR Water V .B2 34.17 (She!!)- Stýruetur-al (Iitefaal) chemistr 010D3-, 1()1&Iftegr-ty program _ _ 409 FloI3II1.B2 4 3..2 C-, Aeeelerated 0409 Gerrfeie~(FAG)-Pr-egr am Indoor-Ar Less of Material System 3t4Ml-. 3.4-1 A2, (Extemal)

Walkde*'*

0409 Pr-egram_Condensers ICTM Volume Carbon Steel Treated Water None Identified None Required N/A N/A I, 0406 (Shell) -(Internal) 1 (2)El08A, Indoor Air None Identified None Required N/A N/A I, 0406 1(2)E1O8B

& (External) 1(2)EIO8C

_______

Attachment 1 to PLA-6375 Page 6 of 12 Table 3.4.2-7 Aging Management Review Results -Main Turbine System Component Intended Aging Effect Aging NUREG-1801 Commodity Function Material Environment Requiring Management Volume 2 Table 1 Item Notes Management Programs Item Turbine Casings Structural Carbon Steel Treated Water Loss of Material BWR Water VIII.B2-3 3.4.1-37 C, (high pressure)

-Integrity (Internal)

Chemistry 0403 1(2)G101-HPT Program Loss of Material Flew VIII.B2-4 3.4.1-29 G E Aeeeler-ated ceffesien (FAG) PP-egfa-n Preventive Maintenance Activities

-Main Turbine Indoor Air Loss of Material System VIII.H-7 3.4.1-28 A (External)

Walkdown Program Plant-Specific Notes: 0409 Certain components (e.g., main steam piping and valve bodies, and high pressure cendenser shell) support both the ICTM Volume function, as well as providing support/anchorage for connected safety-related components, and thereby provide structural integrity.

It is the structural integrity function of these components which requires aging management.

Attachment 1 to PLA-6375 Page 7 of 12 A.1.2 -Aging Management Programs and Activities The following program description is added to the listing of aging management programs and activities in Appendix A of the LRA (page A-21).A.1.2.49 Preventive Maintenance Activities

-Main Turbine The Preventive Maintenance Activities

-Main Turbine Casing is an existing program that manages loss of material due to flow-accelerated corrosion on the internal surfaces of the high pressure casing for the main turbine.The Preventive Maintenance Activities

-Main Turbine Casing is a condition monitoring program consisting of inspections performed on a nominal 10 -year (12 -year maximum) frequency to detect aging and age-related degradation.

Prior to the period of extended operation, the Preventative Maintenance Activities

-Main Turbine Casing will be enhanced to specify that the inspection of the high pressure turbine shell will consist of a VT-3 or equivalent visual inspection of accessible surfaces and an ultrasonic examination of selected locations for wall thickness.

Attachment 1 to PLA-6375 Page 8 of 12 A.1.4 License Renewal Commitment List> The following new commitment is added to the listing of license renewal commitments in Appendix A of the LRA (page A-55).Table A-1 SSES License Renewal Commitments FSAR Enhancement Supplement or Item Number Commitment on Location Implementation (LRA App. A) Schedule 55) Preventive Existing program is credited with the following enhancement:

A.1.2.49 Prior to the period Maintenance of extended Activities-Specify that the inspection of the high pressure turbine shell will opertin.Aitie consist of a visual inspection (VT-3 or equivalent) of accessible operation.

surfaces and an ultrasonic examination of selected locations for Casing wall thickness.

The program is plant-specific.

Attachment 1 to PLA-6375 Page 9 of 12 B.2 AGING MANAGEMENT PROGRAMSThe following program is added to the listing of SSES plant-specific aging management programs in Table B-1 (on LRA page B-13).Table B-1 Correlation of NUREG-1801 and SSES Aging Management Programs SSES Plant-Specific Programs Plant-Specific Program Preventive Maintenance Activities

-Main Turbine Casing See Section B.2.49.The following program is added to the listing of aging management programs in Table B-2 (on LRA page B-18).Table B-2 Consistency of SSES Aging Management Programs with NUREG-1801 New / Consistent Exceptions Plant- Enhancement Program Name Existing with NUREG- to NUREG-1801 1801 Specific Required Preventive Existing Yes Yes Maintenance Activities

-Main Turbine Casing Attachment 1 to PLA-6375 Page 10 of 12 The following program description is added to Section B.2 of the LRA.B.2.49 Preventive Maintenance Activities'-

Main Turbine Casing Program Description The purpose of the Preventive Maintenance Activities

-Main Turbine Casing is to manage loss of material due to flow-accelerated corrosion on the internal surfaces of the high pressure casing for the main turbine.The Preventive Maintenance Activities

-Main Turbine Casing is a condition monitoring program consisting of inspections to detect aging and age-related degradation.

NUREG-1801 Consistency The Preventive Maintenance Activities

-Main Turbine Casing is an existing SSES program that is plant-specific.

There is no corresponding aging management program described in NUREG- 1801.Aging Management Program Elements The results of an evaluation of each program element against the 10 elements described in Appendix A of NUREG- 1800, are provided below." Scope of Activity The Preventive Maintenance Activities

-Main Turbine Casing is credited for managing loss of material due to flow-accelerated corrosion on the internal carbon steel surfaces of the high pressure casing for the main turbine that is exposed to steam during normal plant operation.

This steam environment is evaluated as a treated water environment for license renewal." Preventive Actions No actions are taken as part of the Preventive Maintenance Activities

-Main Turbine Casing to prevent aging effects or to mitigate age-related degradation.

• Parameters Monitored or Inspected The Preventive Maintenance Activities

-Main Turbine Casing inspects the internal carbon steel surfaces of the high pressure turbine casing for signs of degradation that might be indicative of wall-thinning or loss of material.Inspections will consist of a combination of visual examination and non-destructive testing.

Attachment 1 to PLA-6375 Page 11 of 12 Detection of Aging Effects In accordance with the information provided in the Monitoring and Trending element, the Preventive Maintenance Activities

-Main Turbine Casing will detect loss of material prior to any loss of component intended functions.

The program will rely on established NDE techniques, including visual (VT-3 or equivalent) inspection of accessible surfaces and ultrasonic inspections of selected locations performed by qualified personnel to identify surface degradation and wall thickness.

Inspections are performed on a nominal 10-year (12 -year maximum)frequency based on manufacturer recommendations.

Monitoring and Trending The Preventive Maintenance Activities

-Main Turbine Casing is a conditioning monitoring program that is performed by qualified individuals at established intervals to identify internal degradation of the turbine casings through a combination of visual inspection and ultrasonic testing. If during the internal inspection of the turbine, significant or unusual or unexpected casing deterioration is noted, a condition report (CR) is written. The CR may result in analysis or further inspection, and a disposition is generated.

The disposition of this type of CR may result in a change in the frequency of inspection.

o Acceptance Criteria Any indications or relevant conditions of degradation detected during the inspections will be evaluated.

The inspection observations will be compared to predetermined acceptance criteria.

Inspection results that do not meet the acceptance criteria will be entered into the corrective action program for evaluation.

• Corrective Actions This element is common to SSES programs and activities that are credited with aging management during the period of extended operation and is discussed in Section B. 1.3.o Confirmation Process This element is common to SSES programs and activities that are credited with aging management during the period of extended operation and is discussed in Section B. 1.3.o Administrative Controls This element is common to SSES programs and activities that are credited with aging management during the period of extended operation and is discussed in Section B. 1.3.

Attachment 1 to PLA-6375 Page 12 of 12 Operating Experience The elements that comprise the Preventive Maintenance Activities

-Main Turbine Casing are based on manufacturer recommendations and have proven effective in managing the material condition of the high pressure turbine casing.A review of the most recent Work Order (WO) documentation for the turbine internal inspections reveals that inspections are performed of accessible surfaces in accordance with the appropriate procedures, results are documented and retrievable, and that, if indicated, corrective actions are taken. A review of plant-specific operating experience for the most recent 5-year period, through a search of Action Requests (ARs) and Condition Reports (CRs), revealed that no loss of pressure boundary integrity has occurred that was, or could have been, attributed to the applicable aging effects that are in the scope of the program. Both high pressure turbines have been the object of significant modification work during the last 5 years. The work associated with those modifications revealed no indication of pressure boundary wear on the high pressure turbine outer casing.Required Enhancements Prior to the period of extended operation, the Preventative Maintenance Activities

-Main Turbine Casing will be enhanced to specify that the inspection of the high pressure turbine shell will consist of a visual inspection (VT-3 or equivalent) and an ultrasonic examination for wall thickness.

Conclusion The Preventive Maintenance Activities

-Main Turbine Casing has been demonstrated to be capable of detecting and managing loss of material.

The continued implementation of the Preventive Maintenance Activities

-Main Turbine Casing provides reasonable assurance that the effects of aging will be managed such that components subject to aging management will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation.

Attachment 2 to PLA-6375 Response to RAI B.2.17-2 Attachment 2 to PLA-6375 Page 1 of 6 The following LRA Sections, Tables, and PLA-6241 (Reference 3), are amended in response to RAI B.2.17-2: 3.3.2 Results> LRA Section 3.3.2.1.13 (LRA page 3.3-19) is revised by addition (bold italics).3.3.2.1.13 Fire Protection System Aging Management Programs The following aging management programs manage the aging effects for the Fire Protection System components/commodities:

o Bolting Integrity Program o Buried Piping and Tanks Inspection Program o Chemistry Program Effectiveness Inspection o Heat Exchanger Inspection o Fire Water System Program" Fuel Oil Chemistry Program o Selective Leaching Inspection" System Walkdown Program Attachment 2 to PLA-6375 Page 2 of 6 The following entry in Table 3.3.1, (on LRA page 3.3-91), is revised by addition (bold italics).Table 3.3.1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL Report Item Component/Commodity Aging Aging Management Further Discussion Number Effect/Mechanism Programs Evaluation Recommended 3.3.1-83 Stainless steel and copper Reduction of heat Open-Cycle Cooling No Consistent with NUREG-1 801, with alloy heat exchanger tubes transfer due to Water System exceptions.

exposed to raw water fouling The Piping Corrosion Program is credited to manage loss of material for stainless steel and copper alloy heat exchanger tubes that are exposed to raw water.For the diesel engine driven fire pump heat exchanger tubes, with cooling provided by the same raw water that is used for fire suppression, the Fire Water System Program is credited to manage loss of material (thereby influencing the corrosion products that could foul heat exchanger tubes). The Heat Exchanger Inspection is credited with characterizing whether, and to what extent, a reduction of heat transfer has occurred for the diesel engine driven fire pump heat exchanger tubes.

Attachment 2 to PLA-6375 Page 3 of 6 The following entries in Table 3.3.2-13 are revised by addition (bold italics) and deletion (strikethfeugh) (on LRA page 3.3-230).Table 3.3.2-13 Aging Management Review Results -Fire Protection System Component Intended Aging Effect Aging NUREG-1801 Table I Notes Commodity Function Material Environment Requiring Management Volume 2 Item Management Programs Item Heat Pressure Copper Alloy Raw Water Loss of Fire Water VII.G-12 3.3.1-70 C Exchanger Boundary, (Copper- (Internal)

Material System (Tubes) Heat Transfer Nickel) Program Reduction in F-Fe-WateF VII.CI-6 3.3.1-83 E Heat Transfer System P~egr-avHeat Exchanger Inspection Raw Water Loss of Fire Water VII.G-12 3.3.1-70 C (External)

Material System Program Reduction in P-pe--W-at VII.C1-6 3.3.1-83 E Heat Transfer System Prhgca*rHeat Exchanger Inspection Attachment 2 to PLA-6375 Page 4 of 6 (From Page 20 of Enclosure to PLA-6241, RAI 2.3.3.13-5)

Table 3.3.2-13 Aging Management Review Results -Fire Protection System Component Intended Aging Effect Aging NUREG-1801 Table 1 Notes Commodity Function Material Environment Requiring Management Volume 2 Item Management Programs Item Heat Pressure Copper Alloy Raw Water Loss of P409 V11 H2- 3 C Exchanger Boundary, (Copper- (Internal)

Material GCor6rieR 44VII.G-12 843.3.1-70 (oil cooler) Heat Transfer Nickel) PFOgra~mFire Tubes Water System Program Reduction in PiPipg VIL.C1-6 3.3.1-83 BE Heat Transfer GCcrrcsE)S , g.a..Heat Exchanger Inspection Lubricating Oil Reduction in P4049 N/A N/A H (External)

Heat Transfer GCorosioO PrgriamHeat Exchanger Inspection 0 Attachment 2 to PLA-6375 Page 5 of 6 A.1.2.22 Heat Exchanger Inspection

> The following is a complete replacement for license renewal application Section A.1.2.22 (on LRA page A-12).The Heat Exchanger Inspection detects and characterizes the conditions of heat exchanger tubes in the Control Structure Chilled Water (CSCW), Fire Protection (FP), High Pressure Coolant Injection (HPCI), and Reactor Core Isolation Cooling (RCIC)systems.The scope of the Heat Exchanger Inspection includes the CSCW chiller oil cooler and chiller evaporator, the FP diesel engine driven fire pump heat exchanger and lube oil cooler, and the HPCI and RCIC lube oil coolers. The inspection provides direct evidence as to whether, and to what extent, cracking due to SCC or reduction in heat transfer due to fouling has occurred or is likely to occur that could result in a loss of intended function.The Heat Exchanger Inspection is a new one-time inspection that will be implemented prior to the period of extended operation.

The inspection activities will be conducted within the 10-year period prior to the period of extended operation.

B.2.24 Heat Exchanger Inspection The first 2 paragraphs under "Program Description" in Section:B.2.24 (LRA page B-75) Heat Exchanger Inspection are revised by addition (bold italics) to reflect the addition of the diesel engine driven fire pump heat exchanger:

Program Description The purpose of the Heat Exchanger Inspection is to detect and characterize cracking due to stress corrosion cracking (SCC) and reduction in heat transfer due to fouling of heat exchanger tubes that are exposed to treated water in the Control Structure Chilled Water (CSCW), High Pressure Coolant Injection (HPCI), and Reactor Core Isolation Cooling (RCIC) systems. The Heat Exchanger Inspection also detects and characterizes reduction in heat transfer due to fouling of diesel engine driven fire pump heat exchanger tubes in the Fire Protection System.The Heat Exchanger Inspection will detect and characterize the condition of the copper alloy tubes in the CSCW chiller oil cooler and chiller evaporator and the HPCI and RCIC lube oil coolers, and the stainless steel tubes in the RCIC lube oil coolers, that are exposed to a treated water environment.

In addition, the Heat Exchanger Inspection will detect and characterize the condition, with respect to a reduction in heat transfer, of the copper alloy tubes in the Fire Protection System diesel engine driven fire pump heat exchangers that are exposed to a raw water or lubricating oil environment.

Attachment 2 to PLA-6375 Page 6 of 6 The first bullet, "Scope of Activities," under "Aging Management Program Elements" (LRA Pages B-75 and B-76) is revised by addition (bold italics) as follows: Scope of Activities The Heat Exchanger Inspection detects and characterizes conditions to determine whether, and to what extent a loss of heat transfer due to fouling is occurring (or is likely to occur) for the following heat exchangers within the scope of license renewal:-CSCW chiller evaporator

-internal tube surfaces-CSCW chiller oil cooler -internal tube surfaces-RCIC lube oil coolers -internal tube surfaces-HPCI lube oil coolers -internal tube surfaces-Diesel engine driven fire pump heat exchanger

-tube surfaces-Diesel engine driven fire pump oil cooler -tube surfaces The Heat Exchanger Inspection is also credited for managing cracking due to SCC in the treated water (internal) environment of the copper alloy (admiralty brass)tubes in the RCIC and HPCI lube oil coolers.

Attachment 3 to PLA-6375 Revised SSES License Renewal Boundary Drawings 1 1 P I 1 1 4~ 1 t) *A[f r___"?f-~~ = 1:1__IAl =A.lltz_1ý6 B C Ina.L ----------------- + ==%,""NN-Aý0 0--c 11=1 Y'I!F iT,-WWI.---------IL 4ý_(4)-te-(zog- I y~L SUSQUEHANNA S. E S.UNIT 2 LICENSE RENEWAL BOUNDARY DRAWING CONDENSATE PPL CORP.LR-M-2105 2 D C Y9 I I il El F A G lB.H-- -7l 3 r 4 I 5 It 1 6 1 7 1 8 1_9 I0

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