L-2013-288, Response to Request for Additional Information and Re-submittal of Relief Request No. 12

Response to Request for Additional Information and Re-submittal of Relief Request No. 12

ML13303B561
Person / Time
Site:	Turkey Point
Issue date:	10/09/2013
From:	Kiley M Florida Power & Light Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
L-2013-288
Download: ML13303B561 (35)

Text

1 "1 0 October 9, 2013 PPL. L-2013-288 10 CFR 50.55a U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001 RE: Turkey Point Units 3 and 4 Docket Nos. 50-250 and 50-251 Relief Request No. 12 Response to Request for Additional Information and Re-submittal of Relief Request No. 12 By letter L-2013-113, dated May 24, 2013, (Agencywide Documents Access and Management System (ADAMS) Accession No. ML13164A186), Florida Power & Light Company (FPL) submitted Relief Request No. 12 to the U.S. Nuclear Regulatory Commission (NRC) for review and authorization. FPL requested relief from ASME Section XI, section IWB-5200, subsection IWB-5222, paragraph (b), for the Class 1 pressure test boundaries subject to system pressurization identified in Table 1 and plant drawings of Relief Request No. 12.

On September 9, 2013, via electronic mail, Ms. Farideh E. Saba, NRC Senior Project Manager for Turkey Point Units 3 and 4, requested additional information regarding Relief Request No. 12, by October 11, 2013.

Enclosure 1 to this letter contains NRC's Request for Additional Information (RAI) questions for Relief Request No. 12, and the corresponding FPL responses. Enclosure 2 to this letter contains the revised Relief Request No. 12, which supersedes in its entirety the previous Relief Request No. 12.

Due to the extended refueling outages for the extended power uprate (EPU) Turkey Point plant modifications, FPL is invoking the provision of ASME Code Section XI, IWA-2430(d)l to extend the Fourth 10-Year ISI interval by 1-year for both Turkey Point Units 3 and 4 to complete the required inservice inspections during the refueling outages for Cycle 27 and Cycle 28 for Units 3 and Units 4 respectively, and to credit those inspections/examinations to the Fourth 10-Year ISI Interval. Accordingly, FPL requests the approval of the attached revised Relief Request No. 12 by February 1, 2014 to support the Unit 3 refueling outage for Cycle 27 currently scheduled in the Spring of 2014, and the Turkey Point Unit 4 refueling outage activities currently scheduled for Cycle 28 in the Fall of 2014.

Florida Power & Light Company 9760 S.W. 344" Street Homestead, FL 33035

L-2013-288 Page 2 of 2 If you have any questions, please contact Mr. Robert J. Tomonto, Licensing Manager, at (305) 246-7327.

Very truly yours, Michael Kiley Site Vice President Turkey Point Nuclear Plant Enclosures SM cc: Regional Administrator, Region II, USNRC Senior Resident Inspector, USNRC, Turkey Point Plant Project Manager, NRR, USNRC

FPL Letter L-2013-288 ENCLOSURE 1 Florida Power & Light Company Turkey Point Nuclear Plant Units 3 and 4 Responses to NRC Request for Additional Information For Relief Request No. 12

L-2013-288 Enclosure 1 Page 1 of 4 NRC RAI-1 Describe any history of degradation, such as fatigue or stress corrosion cracking, of the subject lines at Turkey Point Nuclear Generating Unit Nos. 3 and 4.

FPL Response to RAI-1 A review of the In-service Inspection Reports and Corrective Action Program (CAP) data base indicate that there is no history of degradation, such as fatigue or stress corrosion cracking, of the subject lines at Turkey Point Units 3 and 4.

NRC RAI-2 Provide an estimate of the radiological dose associated with pressurizing the subject vent and drain lines to the required pressure.

FPL Response to RAI-2 The activity to pressurize the subject vent and drain lines to the required pressure, would involve Operations and ISI personnel to operate the valve and to perform these inspections.

This activity would normally be performed during Mode 3. The historical Mode 3 Radiation Protection survey maps were utilized to provide an estimate of the radiological dose associated with pressurizing the subject vent and drain lines to the required pressure. The radiological dose estimates for this activity yielded a value of 280 mrem for Turkey Point Unit 3 and a value of 344 mrem for Turkey Point Unit 4.

NRC RAI-3 For the 14-inch diameter segment between the residual heat removal (RHR) inlet motor operated valves (MOVs) 750 and 751, a VT-2 visual examination would indicate leakage only if the lines are pressurized or have been pressurized during operation.

a. What is the pressure in this segment during normal operation?

b. Is there a provision to pressurize the subject piping segment between the two MOVs to the required test pressure (i.e., is there a test connection in this segment)?

c. Describe the hardship associated with pressurizing this segment to the pressure corresponding to 100 percent rated reactor power and performing the VT-2 visual examination.

d. Provide a technical basis for expectation of leak tightness of the subject segment if the line is not pressurized to the required pressure when performing the VT-2 visual examination.

L-2013-288 Enclosure 1 Page 2 of 4 FPL Response to RAI-3

a. What is the pressure in this segment during normal operation?

During normal RHR operation, this segment of pipe experiences pressures equivalent to reactor cavity static head and up to 450 psig. During normal plant operations, this 14-inch diameter segment is isolated from the Reactor Coolant System (RCS). However, it is possible that the segment of pipe between MOV-3/4-750 and MOV-3/4-751 becomes pressurized due to minor leak-by past the first isolation valve. This pressurization could come close to RCS pressure.

b. Is there a provision to pressurize the subject piping segment between the two MOVs to the required test pressure (i.e., is there a test connection in this segment)?

Yes, there is a provision to pressurize the subject piping segment between the two MOVs. Both Turkey Point Units 3 and 4 have a drain connection (valves 3-750D and 4-750D respectively) in this segment. In addition, Turkey Point Unit 4 has a vent valve, 4-750A, at that pipe segment.

c. Describe the hardship associated with pressurizing this segment to the pressure corresponding to 100 percent rated reactor power and performing the VT-2 visual examination.

The RHR system limiting pressure is at 450 psig. The hardship associated with pressurizing this segment to the pressure corresponding to 100 percent rated reactor power, and performing the VT-2 visual examination, is the fact that MOV-3/4-750 would need to be bypassed by installing a pipe jumper. This pipe jumper will experience the RCS pressure and temperature conditions. Risks associated with utilizing a pipe jumper include the possibility of over pressurizing the RHR system should the RHR Inlet valves MOV-3-751 or MOV-4-751 fail. Additionally, if a leak develops at the pipe jumper; it could result in an un-isolable RCS leak. Testing and supporting personnel safety would be at risk, due to the leakage being at RCS conditions.

d. Provide a technical basis for expectation of leak tightness of the subject segment if the line is not pressurized to the required pressure when performing the VT-2 visual examination.

The subject segment is pressurized to RHR system pressure for a significant period of time during a refueling outage. Therefore, there is reasonable assurance that any leakage in this subject segment would be identified during the RCS system leakage testing.

Also, a review of the In-service Inspection Reports and CAP data base was performed. Based on this review, no leak tightness issues of the subject segment have occurred.

L-2013-288 Enclosure 1 Page 3 of 4 NRC RAI-4 Are the subject low head safety injection check valves and upstream piping continuously pressurized during an operating cycle? Would the provisions of ASME Code Case N-731 apply to these segments?

FPL Response to RAI-4 The subject low head safety injection check valves and upstream piping are continuously pressurized during an operating cycle by the Safety Injection Accumulators. Therefore, the provisions of ASME Code Case N-731 apply to these segments. Hence, no relief request is required for the subject low head safety injection check valves and upstream piping. Relief Request No. 12, previously submitted in L-2013-113, dated May 24, 2013, has been revised to delete Section 4.0 discussions addressing Safety Injection Loops Low Head Check Valves 3-875A/B/C and 4-875A/B/C, and upstream piping. The associated pressure retaining components have been deleted from Table 1 of the revised relief request.

NRC RAI-5 For the subject safety injection loop high head check valves and upstream piping lines, a VT-2 visual examination would indicate leakage only if the lines are pressurized or have been pressurized during operation.

a. What is the maximum pressure in these lines during normal operation?

b. Describe the hardship associated with pressurizing this segment to the pressure corresponding to 100 percent rated reactor power.

c. Is there a provision to pressurize the subject piping segment to a pressure that is at least the pressure of the high head safety injection pump in operation? If a hardship is associated with pressurizing the subject piping segment, please describe it.

d. Provide a technical basis for expectation of leak tightness of the subject lines if they are not pressurized when performing the VT-2 visual examination.

L-2013-288 Enclosure 1 Page 4 of 4 FPL Response to RAI-5

a. What is the maximum pressure in these lines during normal operation?

The subject piping lines are isolated during normal operation. Therefore, these lines do not experience pressure. However, it is possible that the piping becomes pressurized due to minor leakage past the first isolation valve.

b. Describe the hardship associated with pressurizing this segment to the pressure corresponding to 100 percent rated reactor power.

The following evolutions describe the hardship associated with pressurizing this segment to the pressure corresponding to 100 percent rated reactor power:

To pressurize these lines, the high head check valve will need to be temporarily modified by removing its internals. This modification will create a configuration where only one isolation valve will be available to prevent over pressurizing the high head safety injection system. At the completion of this evolution, the affected pipe segment will need to be de-pressurized in order to restore the affected check valve to its original configuration.

Another option would be to bypass one of the high head check valves by installing a pipe jumper. This pipe jumper will experience RCS pressure and temperature conditions. If a leak develops at the pipe jumper; it could result in a potential un-isolable RCS leak. Testing and supporting personnel safety would be at risk, due to the leakage being at RCS conditions.

c. Is there a provision to pressurize the subject piping segment to a pressure that is at least the pressure of the high head safety injection pump in operation? If a hardship is associated with pressurizing the subject piping segment, please describe it.

There is a provision to pressurize the subject piping segment by performing the Safety Injection System Full Flow Test. FPL performs this test during a refueling outage when the reactor head is removed and the reactor cavity is flooded. A VT-2 visual examination of the subject piping is then performed while a Safety Injection Pump is running.

d. Provide a technical basis for expectation of leak tightness of the subject lines if they are not pressurized when performing the VT-2 visual examination.

Based on a review of the In-service Inspection Reports and CAP data base, it is concluded that there are no leak tightness issues identified for the subject lines. The subject lines will be pressurized during the Safety Injection System Full Flow Test.

During this test, the lines will be VT-2 visually examined.

FPL Letter L-2013-288 ENCLOSURE 2 Florida Power & Light Company Turkey Point Nuclear Plant Units 3 and 4 Revised Relief Request No. 12

L- 2013-288, Enclosure 2 Page 1 of 11 10 CFR 50.55a Relief Request Number 12 Proposed Alternative in Accordance with 10 CFR 50.55a (a)(3)(ii)

Hardship or Unusual Difficulty Without Compensating Increase in Level of Quality or Safety

1. ASME Code Component(s) Affected:

The affected components associated with this relief request are the Turkey Point Units 3 and 4 Class 1 pressure retaining components within the identified system boundary listed in Table 1 and the attached plant drawings.

2. Applicable Code Edition and Addenda

The code of record for Turkey Point Units 3 and 4 for the Fourth 10-year Inservice Inspection (ISI) interval is the 1998 Edition with Addenda through 2000 of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (B&PV), Section Xl, "Rules for Inservice Inspection of Nuclear Power Plant Components."

3. Applicable Code Requirement

The ASME B&PV Section XI 1998 Edition with Addenda through 2000, Table IWB-2500-1, Section IWB-5200 "System Test Requirements", subsection IWB-5222 "Boundaries",

paragraph (b), requires that "The pressure retaining boundary during the system leakage test conducted at or near the end of each inspection interval shall extend to all Class 1 pressure retaining components within the system boundary."

4. Basis for Hardship or Unusual Difficulty without Compensating Increase In level of Quality or Safety:

Florida Power & Light Company (FPL) requests relief from IWB-5222(b) in accordance with 10 CFR 50.55a(a)(3)(ii) on the basis that hardship or unusual difficulty exists, without a compensating increase in the level of quality and safety. The attached Table 1 and plant drawings identify the Class 1 pressure retaining components that are associated with the requested relief.

The reason for the relief is discussed below.

Turkey Point Units 3 and 4 design of Class 1 vents and drains typically consist of a single isolation valve with a capped/blind flanged end that constitutes the Class 1 system boundary.

Many of these valves are not readily accessible due to their physical locations and radiation/contamination levels in the area. Pressurization of these locations for testing would be performed in Mode 3 and would involve opening these single isolation valves to

L- 2013-288, Enclosure 2 Page 2 of 11 pressurize to the extended Class 1 pressure retaining components within the system boundary. After performance of the required VT-2 visual examination, these single isolation valves would be closed, isolating a high temperature, pressurized volume of water between the isolation valve and the capped/blind flanged end. This results in an undesirable plant configuration that would be conducive to pressure lock or the initiation of system leakage from valve packing or capped/blind flanged ends.

In addition, the piping associated with the vents and drains will contain pressurized reactor coolant fluid between the valve and cap/blind flange. During the subsequent refueling outage, after depressurization of the reactor coolant system, the valve would need to be opened prior to cap/blind flange removal in order to release the pressurized slug of reactor coolant system fluid contained between the valve and cap/blind flange. This will need to be performed in order to eliminate a safety hazard.

Turkey Point Units No. 3 and 4 design also requires substantial effort to extend the Class 1 system boundary where check valves or non-redundant components serve as the first system isolation from the reactor coolant system. Such configurations may require check valve disassembly or other temporary configurations to achieve test pressures at upstream piping and valves. Since the Class 1 system pressure testing is performed in Mode 3, these temporary configurations could conflict with Technical Specification requirements and valve alignments. Establishing and restoring such temporary configurations could also result in an unwarranted increase in worker radiation exposures.

Relief is requested from fully pressurizing piping between the first and second isolation device on small bore size vent, drain, test, and fill lines in the Reactor Coolant System (RCS), which range in size from 0.5 inch to 2 inches. The configurations are either two small isolation valves in series, a valve and blind flange, or a valve and cap. In certain configurations, the piping between the two isolation boundaries will tee to a third valve that is also the second isolation boundary. The piping segments provide the design required double isolation barrier for the reactor coolant pressure boundary. The code required leakage test would be performed in Mode 3 at the normal operating temperature and pressure.

Leakage testing of these piping segments at nominal operating pressure in Mode 3 would require the opening of the inboard isolation valve at the normal operating RCS temperature and pressure conditions. In doing so, the design requirement for two primary coolant pressure boundary isolation devices would be violated. Additionally, opening of these valves introduces the potential risk for spills and personnel contamination. For configuration where blind flanges or caps are installed as the isolation device, opening of the inboard valve introduces the possibility of a personnel safety hazard if a flange or cap fails in the presence of inspection personnel.

A VT-2 visual examination is performed on these piping segments through the entire length as part of the Class 1 system inspection at the conclusion of each refueling outage. This leakage test does not specifically pressurize past the first isolation valve. Also, this leakage test is considered successful when no external or visible leakage is identified. Since this type

L- 2013-288, Enclosure 2 Page 3 of 11 of test assures that the combined first and second isolation devices are effective in maintaining the reactor coolant pressure boundary at normal operating temperature and pressure, the increase in safety achieved from the code required leakage test (IWB-5222(b))

is not commensurate with the hardship of performing such code required leakage testing.

14-inch Residual Heat Removal (RHR) Motor Operated Valves (MOV)

Turkey Point Unit 3: This piping segment consists of approximately 26 feet of 14-inch piping between RHR inlet valves MOV-3-750 and MOV-3-751. Within this piping segment there is a 3/4 inch pipe branch with a 3/4 inch valve that branches off into a two 1/2 inch valves.

Turkey Point Unit 4: This piping segment consists of approximately 44 feet of 14 inch piping between RHR inlet valves MOV-4-750 and MOV-4-751. Within this piping segment there is a 1 inch pipe branch with a 1 inch valve that branches off into a 1 inch valve and a 1/2 inch valve. Also, within this 14-inch piping segment, there is a 3/4 inch vent valve.

MOV-3/4-750 and MOV-3/4-751 are interlocked to avoid over-pressurization of the RHR system. The interlock prevents manual opening of the valves with RCS pressure above the required pressure interlock setpoint.

A VT-2 visual examination is performed on these piping segments through the entire length as part of the Class 1 system inspection at the conclusion of each refueling outage. This proposed system pressure test does not specifically pressurize past the first isolation valve.

It is possible that the piping becomes pressurized due to minor leakage past the first isolation valve. The leakage test is considered successful when no external or visible leakage is identified. This test will provide assurance that the combined first and second isolation devices are effective in maintaining the reactor coolant pressure boundary at normal operating temperature and pressure.

Based on the above, extension of the pressure retaining boundary during system leakage tests to Class 1 pressure retaining components within the system boundary represents a hardship and unusual difficulty that does not provide a compensating increase in the level of quality and safety.

Safety Injection Loops High Head Check Valves 3-874A/B, 4-874A/B, and Upstream Piping These two piping segments consist of a 2-in. piping span between two check valves oriented toward the RCS. Pressure testing of these piping segments at nominal operating pressure in MODE 3 would require a modification to allow pressurizing to the normal operating RCS temperature and pressure conditions.

A VT-2 visual examination is performed on these piping segments through the entire length as part of the Class 1 system inspection at the conclusion of each refueling outage. The proposed system pressure test will not specifically pressurize past the first isolation valve for

L- 2013-288, Enclosure 2 Page 4 of 11 this inspection. It is possible that the piping becomes pressurized due to minor leakage past the first isolation valve. The acceptance criteria will be that no external or visible leakage will be allowed for the test to be successful.

Based on the above, it has been determined that compliance with the ASME Code requirement to perform the system pressure test on the subject line segments would result in a hardship that would not be compensated by an increase in quality and safety. The proposed alternative provides reasonable assurance that the subject line segments' leakage integrity will be maintained.

5. Proposed Alternative and Basis for Use:

Title 10 of the Code of Federal Regulations (10 CFR), Section 50.55a(g)(4), specifies that ASME Code Class 1, 2, and 3 components (including supports) must meet the requirements, except for the design and access provisions and the preservice examination requirements, set forth in the ASME Code, Section Xl to the extent practical within the limitations of design geometry and materials of construction of the components.

Paragraph 50.55a(a)(3) of 10 CFR Part 50 states, in part, that alternatives to the requirements of 10 CFR 50.55a(g) may be used when authorized by the NRC if the licensee demonstrates (i) the proposed alternatives would provide an acceptable level of quality and safety, or if (ii) compliance with the specified requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. FPL is requesting authorization of an alternative to the requirements of the ASME Code Section Xl, IWB-5222(b) pursuant to 10 CFR 50.55a(a)(3)(ii).

The proposed alternative for this request relief uses leakage testing. The Class 1 system boundary will be maintained in a normal, operational alignment during leakage tests for the items identified within Table 1 constituting exceptions to the Code-required boundary of IWB-5222(b). The VT-2 visual examination will extend to the Class 1 pressure retaining components within the system boundary during the performance of each system leakage test required by Table IWB-2500-1 examination category B-P. Items within Table 1 will be visually examined for evidence of leakage during system leakage testing without being pressurized to nominal reactor coolant system operating pressure.

Based on the discussion provided in Section 4, it is concluded that compliance with the specified requirements would result in hardship or unusual difficulty without compensating increase in the level of quality and safety, while the proposed alternative provides reasonable assurance of structural integrity or leak tightness of the subject components.

6. Duration of Proposed Alternative:

Relief Request No. 12 is requested for Turkey Point Units 3 and 4 for the Fourth 10-Year ISI Interval. The Unit 3 Fourth 10-Year ISI Interval began February 22, 2004 to February 21, 2014 and the Unit 4 Fourth 10-Year Interval began April 15, 2004 to April 14, 2014.

L- 2013-288, Enclosure 2 Page 5 of 11 Due to the extended refueling outages for the extended power uprate (EPU) Turkey Point plant modifications, FPL is invoking the provision of ASME Code Section Xl, IWA-2430(d)1 to extend the Fourth 10-Year ISI interval by 1-year for both Turkey Point Units 3 and 4 to complete the required inservice inspections during the refueling outages for Cycle 27 and Cycle 28 for Units 3 and Units 4 respectively, and to credit those inspections/examinations to the Fourth 10-Year ISI Interval.

7. Precedent Similar relief has been granted for H.B Robinson Steam Electric Plant Unit No.2, Docket No.

50-261, TAC No. ME 8255, ML12181A26.

B. Attachments Plant Drawings referenced in Table 1

L-2013-288, Enclosure 2 Page 6 of 11 Table I Relief Request No. 12 Turkey Point Unit 3 Affected Class I Pressure Retaining Components Affected Line or Component Code Class Pipe Diameter Pipe Schedule Approx Length Exam Category Drawing No. Boundary Exception(s)

Drain line below PZR safety A376 TP316 5613-M-3041 Valve 3-545 remains closed to avoid valve RV-3-551A (pipe piece 1 3/4 in. SMLS Sch. 160 < 1 ft. B-P Sh. 2 pressurizing downstream Class 1 pipe between 3-545 and 3-545A) piece and valve 3-545A Drain line below PZR safety Valve 3-546 remains closed to avoid valve RV-3-551 B (pipe piece 1 3/4 in. A376 TP316 2 ft. B-P 5613-M-3041 pressurizing downstream Class 1 pipe between 3-546 and 3-546A SMLS Sch. 160 Sh. 2 piece and valves 3-546A and 3-585 and 3-585) ____ ______ ____ _____ ______

Drain line below PRZ safety A376 TP316 5613-M-3041 Valve 3-547 remains closed to avoid valve RV-3-551C (pipe piece 1 3/4 in. SMLS Sch. 160 1 ft. B-P Sh. 2 pressurizing downstream Class 1 pipe between 3-547and 3-547A) piece and valve 3-547A A376 TP316 RCS loop intermediate loop 2 in. SMLS Sc.16 1 ft. Valve 3-508A remains closed to avoid "A" drain valve, liquid waste 1SMLS Sch. 160 5613-M-3041 pressurizingemains dipoalpiinhndlek-ffpressurizing downstreamClos Class 11 disposal piping, and leak-off A376 valve. 3/4 in. SL TP316c.10 28 ft. Sh. 1 piping and valves 3-508B and 3-542 SMLS Sch. 160 28t RCS loop intermediate loop A376 TP316 5613-M-3041 Valve 3-515A remains closed to avoid "B" drain valve and liquid 1 2 in. A376 TP316 *1 ft. B-P 51M31 pressurizing downstream Class 1 waste disposal piping SMLS Sch. 160 Sh. 1 piping and valve 3-515B.

RCS loop intermediate loop A376 TP316 5613-M-3041 Valve 3-505A remains closed to avoid "C" drain valve and liquid 1 2 in. SMLS Sch. 160 ft. B-P Sh.1 pressurizing downstream Class 1 waste disposal piping piping and valve 3-505B.

RCP "A" seal injection drain A376 TP316 5613-M-3047 Valve 3-300A remains closed to avoid valve and blind flange SMLS Sch. 160 1 ft. B-P Sh.

S. 3 pressurizing downstream pipe piece andgeSMSflange and flange RCP 'A" seal water bypass 1 / n A376 TP316 51-307pressurizing pipe to remains closed Valve 3-300Cdownstream avoid piece vent valve and blind flange 3/4 in. SMLS Sch. 160 < 1 ft. B-P Sh. 3 and3fiange

L-2013-288, Enclosure 2 Page 7 of 11 Table I Relief Request No. 12 Turkey Point Unit 3 Affected Class I Pressure Retaining Components Affected Line or Component Code Class Pipe Diameter Pipe Schedule Approx Length Exam Category Drawing No. Boundary Exception(s)

Valve 3-300D remains closed to avoid RCP "B" seal injection drain A376 TP316 5613-M-3047 pressurizing edowns pipe p ie vleadcp13/4 valve and cap in. 6 SMLS Sch. 160 _<L 1c.

ft. B-P S.3pressurizing downstream pipe piece Sh. 3 n a and cap Valve 3-300Fdownstream pressurizing remains closed pipe topiece avoid RCP "B" seal water bypass A376 TP316 5613-M-3047 Vent valve and blind flange. 3/4 in. SMLS Sch. 160

• 1 ft. B-P Sh. 3 and flange RCP "C" seal injection drain A376 TP316 5613-M-3047 Valve 3-300G remains closed to avoid valve and cap Sch. 160 1SMLS ft. B-P Sh. 3 pressurizing downstream pipe piece and cap RCP "C" s t b Valve 3-300J remains closed to avoid RP""seal water bypass 1A376 TP316 5613-M-3047 pressurizing downstream pipe piece Vent valve and blind flange. 3/4 in. SMLS Sch. 160

• 1 ft. B-P Sh. 3 and flange S

A376eTP316 2 in. A c76 16 139 ft. Valve CV-3-311 remains closed to Auxiliary spray line vent valve B-P 5613-M-3047 avoid pressurizing downstream piping and upstream piping A376 TP316 Sh. 2 up to check valve 3-313 and vent pipe 3/4 in SMLS Sch. 160 < 1 ft. and vent valve 3-120J

-

14 in. A376TP316 26 ft. Valve MOV-3-750 to remain closed to Residual heat removal motor- SMLS Sch. 140 5613-M-3050 avoid pressuring downstream piping operated valve MOV-3-750 B-P Sh. 1 and valves, MOV-3-751, 3-750B, 3-and common suction piping 3/4 in. 1/2 in. A376 TP316 3 ft. 750C and 3-750D.

SMLS Sch. 160 Downstream piping of CV A376 TP316 5613-M-3047 Valve CV-3-310B toormi VleC--1O remain closed lsdt to 31 p o 1 3 in. A36 TP316 45 ft. B-P 5 M3 avoid pressurizing downstream piping SMLS Sch.-160 310 Sh. 2 up to check valve 3-312 B

L-2013-288, Enclosure 2 Page 8 of 11 Table I Relief Request No. 12 Turkey Point Unit 3 Affected Class I Pressure Retaining Components Line or Component Code Pipe Pipe Approx Exam Affected LineorComponent Class Diameter Schedule Length Category Drawing No. Boundary Exception(s)

A376 TP316 Check valves 3-874A and 3-874B to 2 in. SMLS Sch. 160 222 ft. remain closed to avoid disassembly or Safety Injection check valves 5613-M-3062 other temporary configurations 3-874A, 3-874B and 1 B-P Sh. 1 required to achieve test pressures at upstream piping A376 TP316 upstream piping and valves MOV 3/4 in. SMLS Sch. 160 1 ft. 866A and B, 3-941C and D, and 3-957 Valve 3-568 remains closed to Spray line drain Pressurizer vleadcp1 A376 TP316 5613-M-3041 avo presring dostream valve and cap 3/4 in. c. 160 SMLS Sch. 6 _<1ft.

-Sh.

B-P S.2avoid 2 ic n a downstream pp pressurizing pipe piece and cap Valve 3-569 remains closed to Spray line drain Pressurizer vleadcp1 A376 TP316 5613-M-3041 avo presring dostream valve and cap 3/4 in. SMLS Sch. 160 _<1Sft.16 B-P S.2avoid pressurizing downstream

- Sh. 2 pp ic n a pipe piece and cap Valve 3-201A remains closed to Regenerative Heat Exchanger A376 TP316 5613-M-3047 avo p resr dostream ing outlet drain line and cap 3/4 in. SMLS Sch. 160 _ 1 ft. B-P Sh. 1 avoid pressurizing downstream I pipe piece and cap

L-2013-288, Enclosure 2 Page 9 of 11 Table 1 Relief Request No.12 Turkey Point Unit 4 Affected Class I Pressure Retaining Components Affected Line or Component Code Pipe Pipe Approx Exam Categorý Drawing No. Boundary Exception(s)

Class Diameter Schedule Length Valve 4-545 remains closed to valve RV-4-551A (pipe piece 1 3/4 in. SMLS TP316 B-P 5614-M-3041 avoid pressurizing downstream between 4-545 and 4-545A) SMLS Sch. 160 Sh. 2 Class 1 pipe piece and valve 4-545A Drain line below PZR safety Valve 4-546 remains closed to valve RV-4-551B (pipe piece 3/4 in. A376 TP316 < 2 ft. B-P 5614-M-3041 avoid pressurizing downstream between 4-546, 4-546A, and SMLS Sch. 160 Sh. 2 Class 1 pipe piece and valves 4-4-585) 546A and 4-585 Valve 4-547 remains closed to Drain line below PRZ safety . A376 TP316 5614-M-3041 avoid pressurizing downstream valve RV-4-551C (pipe piece 3/4 in. SMLS Sch. 160 < 1 ft. B-P Sh. 2 Class 1 pipe piece and valve 4-between 4-547and 4-547A) 547A A376 TP316 RCS loop intermediate loop 2 in. SMLS Sch. 160 <1ft. Valve 4-508A remains closed to "A" drain valve, liquid waste ___10B-P 5614-M-3041 avoid pressurizing downstream disposal piping, and leak-off A376 TP316 Sh. 1 Class 1 piping and valves 4-508B valve 3/4 in. 28 ft. and 4-542 RCS loop intermediate loop A376 TP316 5614-M-3041 Valve 4-515A remains closed to "B" drain valve and liquid 1 2 in. SMLS Sch. 160 1 ft. B-P Sh. 1 avoid pressurizing downstream waste disposal piping Class 1 piping and valve 4-515B.

RCS loop intermediate loop A376 TP316 5614-M-3041 Valve 4-505A remains closed to "C" drain valve and liquid 1 2 in. SMLS Sch. 160 1 ft. B-P Sh. avoid pressurizing downstream waste disposal piping Class 1 piping and valve 4-505B.

RCP "A" seal injection drain A376 TP316 5614-M-3047 Valve 4-300A remains closed to valve and blind flange 1 3/4 in. SMLS Sch. 160 B-P Sh. 3 avoid pressurizing downstream pipe piece and flange

L-2013-288, Enclosure 2 Page 10 of 11 Table I Relief Request No.12 Turkey Point Unit 4 Affected Class I Pressure Retaining Components Affected Line or Component Code Pipe Pipe Approx Exam Categorý Drawing No. Boundary Exception(s)

Class Diameter Schedule Length RCP "A"seal water bypass A376TP316 5614-M-3047 Valve 4-300C remains closed to vent valve and blind flange 1 3/4 in. SMLS Sch. 160 Sh.

5B-P3 avoid pressurizing downstream pipe piece and flange A376P316Valve 4-300D remains closed to jc tn3/4drain seal injection A376 TP316 5614-M-3047 Vle430 lsdt ean downstream RCPa"B" RCP B"veald dria1 34pnin. 10 SMLS Sch. 160 B-P

- 514M30 Sh.f. avoid pressurizing pipe piece and cap A376P316Valve 4-300F remains closed to RCP "B" seal water bypass A376 TP316 5614-M-3047 avo p resr dostream ing Vent valve and blind flange. in. SMLS Sch. 160 <1 B-P h33/4 avoid pressurizing downstream pipe piece and flange 5614-M-3047 Valve Vle43O 4-300G remains ean closed lsdt to RCP "C" seal injection drain A376 TP316 valve and cap inetindrip 3/4 in. A36 1 ft.1B-P 56143 avoid pressurizing downstream RCPaC"veald SMLS Sch. 160 *1f. BP Sh. 3 pipe piece and iepec n cap a

sA376TP316 Valve 4-300J remains closed to RCPt ""ale wat bypndfasse 1 3/4 in. SMLS Sch. 160 5614-M-3047 avoid pressurizing downstream Vent valve and blind flange. SSh. 3 pipe piece and flange Valve CV-4-31 1 remains closed to Piping downstream of CV 1 2i. A376 TP316 2av 34 564h. V43 ean lsdt 311 1 2 in. SMLS Sch. 160 142 ft. B-P Sh.5614-M-30472avoid pressurizing downstream piping up to check valve 4-313.

Resiual emovl moor-SMLS eat 14 in. Sch. 140 44 ft. Valve MOV-4-750 to remain closed Residual heat removal motor- 5614-M-3050 to avoid pressuring downstream operated valve MOV-4-750 B-P Sh. 1 piping and valves, MOV-4-751, 4-and common suction piping 314 in. A376 TP316 750A, 4-750B, 4-750C and 4-1/2 in. SMLS Sch. 160 10 ft. 750D.

1 in.

Valve CV-4-310B to remain closed Piping downstream of CV A376 TP316 5614-M-3047 SMLS Sch. 160 48 ft. B-P 5 -3 to avoiduppressurizing piping downstream to check valve 4-312B 313B

L-2013-288, Enclosure 2 Page 11 of 11 Table 1 Relief Request No.12 Turkey Point Unit 4 Affected Class 1 Pressure Retaining Components Affected Line or Component Code Pipe Pipe Approx Exam Categorý Drawing No. Boundary Exception(s)

Class Diameter Schedule Length 2 in. A376 TP316 140 ft. Check valves 4-874A and 4-874B SMLS Sch. 160 to remain closed to avoid Safety Injection check valves 5614-M-3062 disassembly or other temporary 4-874A, 4-874B and B-P Sh. 1 configurations required to achieve upstream piping 3/4 in. A376 TP316 test pressures at upstream piping 1 in. SMLS Sch. 160 and valves MOV-4-866A and B, 4-941C and D, and 4-957 iA376TP316 Valve 4-568 remains closed to PrssrierSpaylie ran 1 3/4 in. SMSSh10 *1 ft. B-P 51M341avoid pressurizing downstream valve and cap SL c.10Sh. 2 pipe piece and cap 1 3/4 in. <1 ft. B-P avoid pressurizing downstream

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A376 TP316

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5614-M-3041___ pipe Valvepiece 4-569and cap closed to remains Pressurizer Spray line drain valve and cap SMLS Sch. 160 Sh. 2 aid presrng dnr Valve 4-201A remains closed oetedrain le and3/4 in. A3L6 T3160 1 ft. B-P 5614-M-3047 to avoid pressurizing outlet drain line and flange SMLS Sch. 160 Sh. 1 downstream pipe piece and flange