Text

License Amendment Request 264, Revision 1: Application to Modify Improved Technical Specifications Regarding Steam Generator Tube Integrity and Response to Request for Additional Information
	ML070040108
Person / Time
Site:	Crystal River
Issue date:	12/21/2006
From:	Roderick D; Florida Power Corp, Progress Energy Florida
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	3F1206-02, GL-06-001
	Download: ML070040108 (97)
	v • d • e

SProgress Energy Crystal River Nuclear Plant Docket No. 50-302 Operating License No. DPR-72 Ref: 10 CFR 50.90 December 21, 2006 3F1206-02 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001

Subject:

References:

Crystal River Unit 3 -

License Amendment Request #264, Revision 1:

Application to Modify Improved Technical Specifications Regarding Steam Generator Tube Integrity and Response to Request for Additional Information

1. NRC Generic Letter 2006-01 dated January 20, 2006, "Steam Generator Tube Integrity and Associated Technical Specifications"

2. Crystal River Unit 3 to NRC Letter dated February 13, 2006, "Crystal River Unit 3 Day Response to NRC Generic Letter 2006-01, "Steam Generator Tube Integrity and Associated Technical Specifications"

3. Crystal River Unit 3 to NRC Letter dated May 25, 2006, "Crystal River Unit 3

- License Amendment Request #264, Revision 0, Application to Modify Improved Technical Specifications Regarding Steam Generator Tube Integrity"

Dear Sir:

In accordance with the provisions of 10 CFR 50.90, Florida Power Corporation (FPC), doing business as Progress Energy Florida, Inc., hereby provides Revision 1 to License Amendment Request #264 and the response to a Request for Additional Information.

The proposed amendment would revise the Crystal River Unit 3 (CR-3) Improved Technical Specification (ITS) requirements related to steam generator tube integrity. This submittal is consistent with NRC-approved Revision 4 to Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler TSTF-449, "Steam Generator Tube Integrity." The availability of this ITS improvement was announced in the Federal Register on May 6, 2005 (70 FR 24126) as part of the consolidated line item improvement process (CLIIP).

This submittal replaces Reference 3, License Amendment Request #264, Revision 0, in its entirety.

Attachment A provides the Request for Additional Information response from a discussion with NRC Staff that occurred on September 19, 2006. Attachment B provides a description of the proposed change and confirmation of applicability. Attachment C provides the existing ITS pages marked-up to show the proposed change, and Attachment D provides those same changes presented more formally with revision bars. Attachments E and F provide similar formats for the related Bases sections.

Progress Energy Florida, Inc.

?4-ob/

Crystal River Nuclear Plant 15760 W. Powerline Street Crystal River, FL 34428

U.S. Nuclear Regulatory Commission 3F1206-02 Page 2 of 3 FPC requests approval of the proposed license amendment by February 28, 2007, with the amendment to be implemented within ninety days of issuance.

In accordance with 10 CFR 50.91, a copy of this application with enclosures is being provided to the designated Florida State Official.

This letter establishes no new regulatory commitments.

The CR-3 Plant Nuclear Safety Committee has reviewed this request and recommended it for approval.

If you have any questions regarding this submittal, please contact Mr. Paul Infanger, Supervisor, Licensing and Regulatory Programs at (352) 563-4796.

Daniel L. Roderick Director Site Operations Crystal River Nuclear Plant DLR/dar Attachments:

A.

B.

C.

D.

E.

F.

Request for Additional Information Response Description and Assessment Proposed Improved Technical Specification Changes (Mark-up)

Proposed Improved Technical Specification Changes (Revision Bar Format)

Proposed Improved Technical Specification Bases Pages (Mark-up)

Proposed Improved Technical Specification Bases Pages (Revision Bar Format) xc:

NRR Project Manager Regional Administrator, Region II Senior Resident Inspector State Contact

U.S. Nuclear Regulatory Commission 3F1206-02 Page 3 of 3 STATE OF FLORIDA COUNTY OF CITRUS Daniel L. Roderick states that he is the Director Site Operations, Crystal River Nuclear Plant for Florida Power Corporation, doing business as Progress Energy Florida, Inc.; that he is authorized on the part of said company to sign and file with the Nuclear Regulatory Commission the information attached hereto; and that all such statements made and matters set forth therein are true and correct to the best of his knowledge, info r, n, and belief.

Daniel L. Roderick Director Site Operations Crystal River Nuclear Plant The foregoing document was acknowledged before me this day of 2006, by Daniel L. Roderick.

Signature of Notary Public State of Florida S SHARON 1. LAYTON Comma DD032OW 6onded #vWa (800)432-4254::

FkFrda Notary Assn., Inc (Print, type, or stamp Commissioned Name of Notary Public)

Personally Produced Known OR-Identification

PRORESS ENERGY FLORIDA, INC.

CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302 / LICENSE NUMBER DPR-72 LICENSE AMENDMENT REQUEST #264, REVISION 1 Application to Modify Improved Technical Specifications Regarding Steam Generator Tube Integrity ATTACHMENT A Request for Additional Information Response

U.S. Nuclear Regulatory Commission Attachment A 3F1206-02 Page 1 of 12 Request for Additional Information Response On September 19, 2006, Florida Power Corporation (FPC) and NRC Staff held a phone call to discuss the content of Revision 0 of License Amendment Request (LAR) #264 for Crystal River Unit 3 (CR-3) and ten questions sent by email on September 11, 2006.

The following is submitted to respond to the NRC questions on Revision 0 of this LAR (Reference 3). Many of the responses to these questions altered the wording of the proposed Improved Technical Specification (ITS) resulting in Revision 1 to LAR #264 which follows in Attachments B through F.

NRC Request

1. In proposed technical specification (TS) 5.6.2.10.b.2, you indicate that leakage is not to exceed 1 gallon per minute (gpm) "except for specific types of degradation at specific locations as described in paragraph c of the Steam Generator Program." Since TS 5.6.2.10.c addresses all degradation, please discuss your plans to modify this statement to clarify the degradation mechanisms to which the exception applies. For example, "Leakage from all sources, excluding the leakage attributed to the degradation described in TS Section [insert appropriate Section(s)] is not to exceed 1 gpm per SG."

Florida Power Corporation (FPC) Response

1. The final sentence has been changed as shown below by deleting the last part of the last sentence.

The additional qualification for types of leakage as suggested above was unnecessary to reflect current CR-3 licensing basis. This change is technically consistent with TSTF-449, Revision 4 and therefore does not change the description or the assessment presented in Attachment B to this amendment request. Paragraph 5.6.2.10.b.2 has been changed to read:

"Accident induced leakage performance criterion. The primary to secondary accident induced leakage rate for any design basis accident, other than an OTSG tube rupture, shall not exceed the leakage rate assumed. in the accident analysis in terms of total leakage rate for all OTSGs and leakage rate for an individual OTSG.

Leakage is not to exceed one gallon per minute per OTSG, exeptf*. r specific.ypes. o degrad-ation at specific locations-as. described in par-agraph e of the Steam Generatoi NRC Request

2. In your proposed TS (and Technical Specification Task Force-449), a steam generator (SG) tube is defined as the entire length of the tube including the tube wall and any repairs made to it, between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet. Given this definition, the proposed repair criteria in TS 5.6.2.10.c may not be complete.

U.S. Nuclear Regulatory Commission Attachment A 3F1206-02 Page 2 of 12 It is also not clear that proposed TS 5.6.2.10.c appropriately lists the repair criteria for sleeves. As currently written, the repair criteria for sleeves is 40% of the tube wall. In addition, it is not clear that your proposed TS contains the appropriate repair limit for the parent tube at the locations of the sleeve-to-tube joint.

Please discuss your plans to modify your TS to address these issues. For example, the TS may be modified by using something similar to the following:

The non-sleeved region of a tube found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged or repaired except if the flaws are permitted to remain in service through application of an alternate tube repair criteria discussed below.

Tubes shall be plugged if the sleeved region of a tube is found by inservice inspection to contain flaws in the (a) sleeve or (b) the pressure boundary portion of the original tube wall in the sleeve/tube assembly (i.e., the sleeve-to-tube joint).

FPC Response

2. The text shown above, with the exception of the final parenthetical statement, replaces existing text in 5.6.2.10.c. The changes are made to provide clarification and description of the affected portion of the tube and to provide more specific repair criteria for the sleeves.

The parenthetical was omitted since it may imply the repair is limited to the sleeves. This change is technically consistent with TSTF-449, Revision 4 and therefore does not change the description or the assessment presented in Attachment B to this amendment request.

Paragraph 5.6.2.10.c has been changed to read:

"Provisions for OTSG tube repair criteria. Tubes fond by inse,,,i. e inspe.tin to eontain flaws with a depth equtal to or exceeding 40% of the nmeinal tuibe wall thickness shall be plugged or repaired. The non-sleeved region of a tube found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged or repaired except if the flaws are permitted to remain in service through application of an alternate tube repair criteria discussed below.

"Tubes shall be plugged if the sleeved region of a tube is found by inservice inspection to contain flaws in the (a) sleeve or (b) the pressure boundary portion of the original tube wall in the sleeve/tube assembly."

NRC Request

3. Regarding proposed TS 5.6.2.10.c.1, please address the following:

a. Please discuss your plans to move the first sentence to TS 5.6.2.10.d.x, since this sentence provides inspection requirements rather than repair criteria.

b. Please discuss your plans to delete the second and fourth sentences since there are no minimum sample size requirements for the random inspection and there are no inspection categories for the results of the inspection.

c. Please discuss your plans to remove the third sentence since it is consistent with the standard 40% depth-based repair criteria.

U.S. Nuclear Regulatory Commission Attachment A 3F1206-02 Page 3 of 12 FPC Response 3a-c. The first sentence in 5.6.2.10.c.1 was moved to ITS 5.6.2.10.d.4 to relocate inspection requirements to the same area. The abbreviation "IGA'" has already been defined in earlier ITS text as "intergranular attack," so that clarification is removed. The second, third and fourth sentences have been deleted because the information is either no longer a requirement or redundant to text elsewhere in the amendment request. This change is technically consistent with TSTF-449, Revision 4 and therefore does not change the description or the assessment presented in Attachment B to this amendment request. The new ITS 5.6.2.10.d.4 reads as follows:

"Inservice tubes with pit-like intergranular attack (IGA) indications in the first span of the B OTSG, identified in the OTSG Inservice Inspection Surveillance Procedure must be inspected with bobbin and Motorized Rotating Pancake Coil (MRPC) eddy current techniques from the lower tube sheet secondary face to the bottom of the first tube support plate during each inservice inspection of the B OTSG. Ne credit is to be taken for this, inspection in meet n g.

.m N sample size require ents. for the r-andom inspection. Defeetive tubes found during this inspection are to be plugged OF sleeved. Degraded or-defcteive tubes found during this inspection are not to b considcrcd in determining the inspection results category for-the r-andom inspection",

Incs ti--_;QAhe dcgradation meehanism identifi-ed is a mechanism other than pit like IGA.-"

This change relocated the entire revised text of ITS 5.6.2.10.c.]. New text will be placed in this paragraph in response to Request 8.

NRC Request Regarding proposed TS 5.6.2.10.c.2, please address the following:

4a. The first paragraph deals mainly with inspection issues. Please discuss your plans to move these requirements to TS 5.6.2.10.d.x.

In addition, discuss your plans to remove the last sentence since there are no random sample inspection requirements.

In addition, discuss your plans to clarify that the inspections will be performed at a specific interval rather than during each subsequent inspection since an inspection may be performed for reasons other than tube end cracking. For example, "The portion of the tube with an axially oriented tube end crack (TEC) must be inspected using the motorized rotating coil eddy current technique every 24 effective full power months or one refueling outage (whichever is less)."

FPC Response 4a. The first paragraph has been moved to 5.6.2.10.d.5 to relocate inspection requirements to the same area, the text regarding the random sample inspection requirements has been removed since this will no longer be a requirement, and the suggested text above has been added to clarify that inspections will be performed at a specific interval rather then during each subsequent inspection. The parentheses around the term "whichever is less" were removed.

This change is technically consistent with TSTF-449, Revision 4 and therefore does not change the description or the assessment presented in Attachment B to this amendment request. The new 5.6.2.10.d.5 reads as follows:

U.S. Nuclear Regulatory Commission Attachment A 3F1206-02 Page 4 of 12 "Tubes in-service with axially oriented tube end cracks (TEC) are identified in the OTSG Inservice Inspection Surveillance Procedure. The portion of the tube with the axial TEC must be inspected using the motorized rotating coil eddy current technique durving each suibsequent inspection. No cr-edit is to be taken for this inspeetion foi meeting the minimum sample size r-equirement for r-andom sample inspection, every 24 effective full power months or one refueling outage, whichever is less."

NRC Request 4b. Regarding the second paragraph, it is not clear that it is needed since all tubes with TECs must be reinspected per paragraph one and there is no longer a requirement to categorize the inspection results. Please discuss your plans to remove this paragraph.

FPC Response 4b. The first sentence of this paragraph remains a requirement so it has been retained. The second sentence can be deleted since it will no longer be necessary to calculate inspection categories. The first sentence is added to the single sentence in the next paragraph to form a two-sentence paragraph, and then moved one paragraph lower on the page to become the second paragraph of 5.6.2.10.c.2. This change is technically consistent with TSTF-449, Revision 4 and therefore does not change the description or the assessment presented in Attachment B to this amendment request. The revised second paragraph of 5.6.2.10.c.2 will be as follows:

"Tubes identified with TEC that meet the alternate repair criteria will be added to the existing list of tubes in the OTSG Inservice Inspection Surveillance Procedure. Tubes ident ed with TEC during the pr.evious inspection which meet the **iteria to remain insriewil oeicue when calculatinig the inspeetion eategory of the OTSG.-

The inspection data for tubes with axially oriented TEC indications shall be compared to the previous inspection data to monitor the indications for growth.

NRC Request 4c. Regarding the fourth paragraph, it is not clear that the reference to the accident-induced leakage limits (i.e., the values cited) are still needed. Please confirm that these values are consistent with your design and licensing basis. If they are consistent with your design and licensing basis, discuss your plans to remove them from this paragraph since these are already requirements of proposed TS 5.6.2.10.b.2.

FPC Response 4c. This paragraph contains information that is still consistent with the CR-3 design and licensing basis. As such, it is being retained and moved to the first paragraph of 5.6.2.10.c.2 for clarity. This change is technically consistent with TSTF-449, Revision 4 and therefore does not change the description or the assessment presented in Attachment B to this amendment request. This first paragraph of 5.6.2.10.c.2 is combined with text discussed in Request 8 to read as follows (the bolded text is the subject of this request, 4c):

U.S. Nuclear Regulatory Commission Attachment A 3F1206-02 Page 5 of 12 "Tube End Cracks (TEC) are those crack-like eddy current indications, circumferentially and/or axially oriented, that are within the Inconel clad region of the primary face of the upper and lower tubesheets, but do not extend into the carbon steel-to Inconel clad interface. Tubes with axially oriented TEC may be left in-service using the method described in Topical Report BAW-2346P, Revision 0, provided the combined projected leakage from all primary-to-secondary leakage, including axial TEC indications left in-service, does not exceed the Main Steam Line Break (MSLB) accident leakage limit of one gallon per minute, minus 150 gallons per day, per OTSG.

The contribution to MSLB leakage rates from TEC indications shall be determined utilizing the methodology in Addendum B dated August 10, 2005 to Topical Report BA W-2346P, Revision 0. The projection of TEC leakage that may develop during the next operating cycle shall be determined using the methodology in Addendum C dated August 30, 2005 to Topical Report BA W-2346P, Revision 0."

NRC Request 4d. Regarding the fifth paragraph, discuss your plans to move these inspection requirements to TS 5.6.2.1O.d.x. In addition, please discuss your plans to replace the term "defective" with a more descriptive term (since defective is no longer defined in the TS). For example, replace "are defective" with "exceed the tube repair criteria."

FPC Response 4d. These inspection requirements have been moved to 5.6.2.10.d.6 to relocate inspection requirements to the same area. The words "are defective" have been replaced with "satisfy the tube repair criteria" for clarity. This change is technically consistent with TSTF-449, Revision 4 and therefore does not change the description or the assessment presented in Attachment B to this amendment request. The new 5.6.2.10.d.6 paragraph reads as follows:

"If the plant is required to shut down due to primary-to-secondary leakage and the cause is determined to be degradation of the TEC portion of the tubes, 100% of the tubes with TEC in that OTSG shall be examined in the location of the TEC. If more than 1% of the examined tubes satisfy the tube repair criteria, 100% of the tubes with TEC in the other OTSG shall be examined in the location of the TEC."

NRC Request 4e. Regarding the fifth paragraph, please discuss your plans to more specifically state what constitutes an "appropriate approved method." Presumably, the tubes shall be repaired using the appropriate method from TS 5.6.2. 10.f or removed from service by plugging the tube.

FPC Response 4e. This comment is actually about the sixth paragraph. The suggested information is added to for purposes of clarity. That is, removal from service is clarified to mean it is done by plugging the tube. The appropriate repair method is given a reference to ITS 5.6.2.10.f Generally, the other change to this section is a revision of the words that retains the same meaning. This change is technically consistent with TSTF-449, Revision 4 and therefore does not change the description or the assessment presented in Attachment B to this amendment request. The third paragraph of 5.6.2.10.c.2 has been revised to read:

U.S. Nuclear Regulatory Commission Attachment A 3F1206-02 Page 6 of 12 "Tubes with crack-like indications within the carbon steel portion of the tubesheet, circumferentially oriented TEC, or volumetric indications within the Inconel clad region of the tubesheet shall be repaired or removed from ser.vie using the appropriate method-from 5.6.2.l0f Tubes with ireuf..

.ntialy oriented TEC e.

volumetrie indications. within the Inconel clad r-egion of the tubesheet shall b

.... ir-e or removed from service by plugging the tube."

NRC Request

5. Depending on your response to the other questions, please discuss your plans to add reference to the additional "d.x" items added above to the existing string of "d.l., d.2, and d.3."

FPC Response

5. Because of the additional items moved to 5.6.2.10.d, the text in that section was changed from "In addition to meeting the requirement of d. 1, d.2, and d. 3 below... " to "In addition to meeting the requirements of d.1 through d.8 below... " This text can be seen in the response to NRC Request 6, below (the sentence following the bolded one). This change is technically consistent with TSTF-449, Revision 4 and therefore does not change the description or the assessment presented in Attachment B to this amendment request.

NRC Request

6. As currently written, your proposed technical specification would require an inspection of the parent tube repaired with a sleeve. Please discuss your plans to modify TS 5.6.2.10.d to indicate: "In tubes repaired by sleeving, the portion of the original tube wall between the sleeve's joints is not an area requiring re-inspection."

FPC Response

6. Paragraph 5.6.2.10.d has been modified to exclude a portion of sleeve repaired tubes from re-inspection. This change is technically consistent with TSTF-449, Revision 4 and therefore does not change the description or the assessment presented in Attachment B to this amendment request. The bolded text represents the additional sentence below:

"Provisions for OTSG tube inspections. Periodic OTSG tube inspections shall be performed.

The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g.,

volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable tube repair criteria. The tube-to-tubesheet weld is not part of the tube. In tubes repaired by sleeving, the portion of the original tube wall between the sleeve's joints is not an area requiring re-inspection. In addition to meeting the requirements of d.1 through d.8 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that OTSG tube integrity is maintained until the next OTSG inspection. An assessment of degradation shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations."

U.S. Nuclear Regulatory Commission Attachment A 3F1206-02 Page 7 of 12 NRC Request Regarding proposed TS 5.6.2.10.f.2, please address the following:

7a. Please discuss your plans for removing reference to "eddy-current methods" since the new proposed technical specifications already require that techniques capable of detecting flaws of any type that may be present must be used during the inspections.

FPC Response 7a. Paragraph 5.6.2.10.f.2 remains as originally submitted since the Amendment 158 Safety Evaluation from the NRC for rerolls (Reference 4) specifically identifies eddy-current as the inspection method for rerolls.

NRC Request 7b. Please discuss your plans to replace "imperfections and degradation" with more appropriate terminology since these terms are no longer defined in your proposed TS. For example, "The repair roll must be free of fabrication or service-induced flaws for the repair to be considered acceptable. If the repair roll is unacceptable, the tube must be repaired or plugged."

FPC Response 7b. The definitions for imperfection and degradation are being deleted in this license amendment request. Instead of using these terms or the suggested 'fabrication or service-induced flaws, " the more simple term, "flaws, " is used to describe unacceptable defects in the repair roll. Additionally, the last sentence is added for clarification purposes. This change is technically consistent with TSTF-449, Revision 4 and therefore does not change the description or the assessment presented in Attachment B to this amendment request. The revised paragraph 5.6.2.1O.f 2 is as follows:

"Installation of repair rolls in the upper and lower tubesheets in accordance with BAW-2303P, Revision 4. The repair process (single, overlapping, or multiple roll) may be performed in each tube. The repair roll area will be examined using eddy-current methods following installation. The repair roll must be free of impefeetieons and degradatien flaws for the repair to be considered acceptable. If the repair roll is unacceptable, the tube must be repaired or plugged."

NRC Request 7c. Please discuss your plans to move the last paragraph to the inspection section (i.e.,

5.6.2.10.d.x) since it contains inspection requirements.

In addition, discuss your plans to replace "during each subsequent inservice inspection" with the appropriate interval (i.e.,

every 24 effective full power months or one refueling outage (whichever is less)) for the reason cited above.

FPC Response 7c. The last paragraph has been moved to 5.6.2.10.d. 7 to keep all inspection requirements in the same section. Additionally, the inspection interval is clarified to be consistent with the text change made in FPC Response 4a. This change is technically consistent with TSTF-449, Revision 4 and therefore does not change the description or the assessment presented in Attachment B to this amendment request. The new ITS 5.6.2.10.d.7 is as follows:

U.S. Nuclear Regulatory Commission Attachment A 3F1206-02 Page 8 of 12 "The repair roll in each tube will be inspected during a* h subsequent

,ns.r.vw in.pee.ie. every 24 effective full power months or one refueling outage (whichever is less) while the tube with a repair roll is in service.

NRC Request

8. There were several sections of your current TS that were not moved into your proposed TS.

Specifically, TS 5.6.2.10.4.a.7, the last paragraph of TS 5.6.2.10.4.a. 11.b, TS 5.6.2.10.4.a. 12, and TS 5.6.2.10.4.c. were not carried over into your proposed new TS. Please discuss your plans to move the appropriate requirements from these specifications (in light of the questions above) into the appropriate section of your proposed TS.

FPC Response

8. Current ITS 5.6.2.10.4.a.7 has been moved to 5.6.2.10.c.1 of LAR #264, Revision 1 and is shown as bolded text below. The additional text is provided to clarify repair criteria for IGA.

This change is technically consistent with TSTF-449, Revision 4 and therefore does not change the description or the assessment presented in Attachment B to this amendment request. The new 5.6.2.10.c.1 is as follows:

"Pit-like Intergranular Attack (IGA) indication means a bobbin coil indication confirmed by Motorized Rotating Pancake Coil (MRPC) or other qualified inspection techniques to have a volumetric, pit-like morphology characteristic of IGA. Inservice tubes with pit-like IGA indications in the first span of the B OTSG, identified in the OTSG Inservice Inspection Surveillance Procedure are acceptable to remain in service provided the indication is less than 40% of the nominal tube wall thickness."

The first sentence of the last paragraph of current ITS 5.6.2.10.4.a.11.b has been moved to 5.6.2.10.d.8 of LAR #264, Revision 1 to relocate all inspection requirements to the same area. The second sentence refers to inspection categories which have been deleted in the amendment, so this sentence is also deleted. The first sentence has been reworded to be consistent with paragraph 5.6.2.10.d.6. This change is technically consistent with TSTF-449, Revision 4 and therefore does not change the description or the assessment presented in Attachment B to this amendment request. The new paragraph 5.6.2.10.d.8 is as follows:

5.6.2.10.d.8.

"If the plant is required to shut down due to primary-to-secondary leakage and the cause is determined to be degradation of a repair roll, 100% of the repair rolls in that OTSG shall be examined. If tMat i p

ti.n r

.sults in entering

.at. g6ry C 2 or C 3 for spe.ifi. limited area ins detailed in Table 5.6.2 3, 100% ofithe r-epair rolls shal41 -be xmie in teohrOS.

Current ITS 5.6.2.10.4.a.12 has been moved to 5.6.2.10.c.2 of MAR #264, Revision 1 to keep similar subject matter together. It is shown as the non-bolded text shown in the response to NRC Request 4c., above. This change is technically consistent with TSTF-449, Revision 4 and therefore does not change the description or the assessment presented in Attachment B to this amendment request.

U.S. Nuclear Regulatory Commission Attachment A 3F1206-02 Page 9 of 12 Current ITS 5.6.2.10.4.c has been moved to the second paragraph of 5.6.2.10.d.4 of LAR

264, Revision 1 to keep inspection requirements for inservice tubes with pit-like IGA together. This change is technically consistent with TSTF-449, Revision 4 and therefore does not change the description or the assessment presented in Attachment B to this amendment request. The second paragraph of 5.6.2.10. d.4 is as follows:

"Inservice tubes with pit-like IGA indications in the "B" OTSG first span shall be monitored for growth of these indications by using a test probe equivalent to the high frequency bobbin probe used in the 1997 inspection. The indicated percentage through-wall value from the current inspection shall be compared to the indicated percentage through-wall value from the 1997 inspection."

NRC Request

9. It does not appear that your current reporting requirements in TS 5.7.2.c.2 and TS 5.7.2.c.4 were moved to your new proposed TS. Please discuss your plans to incorporate the existing TS requirements in 5.7.2.c.2 into proposed TS 5.7.2.10. Similarly, discuss your plans to incorporate the existing TS requirements in 5.7.2.c.4 into proposed TS 5.7.2.11.

FPC Response

9. A reporting requirement from current ITS 5.7.2.c.2 is added to 5.7.2.10 of LAR #264, Revision 1. The requirement in 5.7.2.c.2 to report on crack-like indications already exists in 5.7.2.11 so this was not added. The remaining requirement from the current ITS 5.7.2.c.2 was added since it was not explicitly stated in 5.7.2.10 or 5.7.2. 11 of LAR #264, Revision 0.

This change is technically consistent with TSTF-449, Revision 4 and therefore does not change the description or the assessment presented in Attachment B to this amendment request. As such, the new 5.7.2.10 is shown as follows with the newly added text in bold:

"Location, bobbin coil amplitude, and axial and circumferential extent (if determined) for each first span IGA indication, and an assessment of growth for indications in the first span of OTSG B, and" Reporting requirements from current ITS 5.7.2.c.4 are added to 5.7.2.11 of LAR #264, Revision 1. The requirement in 5.7.2.c.4 to report on the number of tubes and axially oriented TEC indications left in-service already exists in 5.7.2.11 so this was not added. The remaining requirement from the current ITS 5.7.2.c.4 was added since this was not explicitly stated in 5.7.2.10 or 5.7.2.11 of LAR #264, Revision 0. This change is technically consistent with TSTF-449, Revision 4 and therefore does not change the description or the assessment presented in Attachment B to this amendment request. The new 5.7.2.11, with the new text bolded, is as follows:

"Number of as-found and as-left tubes with TEC indications, number of as-found and as-left TEC indications, the number of as-found and as-left TEC indications as a function of tubesheet radius, the as-found, as-left, probability of detection and new TEC leakage for upper and lower tubesheet indications. The projected accident leakage and an assessment of growth for TEC indications will be provided. An assessment of the adequacy of the predictive methodology in Addendum C to Topical Report BAW-2346P, Revision 0, including assessing the distribution of indications found in each OTSG to ensure the assumption regarding the similarity of the

U.S. Nuclear Regulatory Commission Attachment A 3F1206-02 Page 10 of 12 distribution of indications remain consistent from one cycle to the next and that the assumption of a linear increase in leak rate remain valid. Corrective actions in the event that the assessment indicates the assumptions can not beffully supported."

NRC Request

10. There appears to be a couple of typographical errors in your TS Bases. On page B 3.4-76, 10 CFR 50.361(2)(ii) should be 10 CFR 50.36(c)(2)(ii)). In the last sentence on page B 3.4-81, it would appear that "steam generator repairs" should be "steam generator tube repairs."

Please discuss your plans to correct these apparent typographical errors.

FPC Response

10. FPC has reviewed Title 10 of the Code of Federal Regulations and determined that 10CFR50.36(c)(2)(ii) is the appropriate reference. The Bases has been corrected to reflect this change. FPC has reviewed previous ITS Bases 3.4-81 and concluded that the word "tube" was inadvertently omitted. The ITS Bases page 3.4-81 has been corrected to read, "Steam generator tube repairs. " This change is technically consistent with TSTF-449, Revision 4 and therefore does not change the description or the assessment presented in Attachment B to this amendment request.

While discussing the above responses with the NRC staff, the subject of primary-to-secondary leakage and the relationship between operating leakage, accident leakage and accident-induced leakage was discussed. Steam generator performance issues and the role these parameters play in the accident analysis have recently gained industry-wide visibility. Currently, efforts are being made by the Nuclear Energy Institute and the Electric Power Research Institute to resolve concerns in these matters with the NRC. Rather than attempt to settle these issues for CR-3 prematurely, FPC prefers to allow the industry and NRC to arrive at a consensus before determining if a change to the CR-3 ITS is necessary. As such, the content of Revision 1 to this license amendment request only reflects the intent of NRC Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-449, "Steam Generator Tube Integrity," Revision 4 and the NRC requested changes already discussed. There is no change in the amendment request to address the on-going industry discussions on operational and accident primary-to-secondary leakage.

In the interest of completeness, FPC is providing the following description of the CR-3 licensing basis for operational and accident leakage. This information supports approval of the proposed LAR 264, Revision 1, without additional changes.

The existing CR-3 accident analyses assume a maximum accident primary-to-secondary leakage of one gallon per minute (gpm) total from both Once-Through Steam Generators (OTSG) in a Loss of Coolant Accident, one gpm from the unaffected OTSG in a Steam Generator Tube Rupture, and one gpm from the affected OTSG in a Steam Line Break accident. The present (and proposed) CR-3 ITS limits primary-to-secondary leakage during normal operation to 150 gallons per day (gpd). The current approved licensing basis for these parameters is not changed by this amendment request.

Generic Letter (GL) 95-05 (Reference 1) provided guidance on preparing a Technical Specifications change request to implement alternate steam generator tube repair criteria for Westinghouse-designed steam generators.

It introduced provisions for augmented inspections and more restrictive operational leakage limits. In part, the GL suggested reducing the restriction

U.S. Nuclear Regulatory Commission Attachment A 3F1206-02 Page 11 of 12 on primary-to-secondary leakage during normal operation from one gpm to 150 gpd through each steam generator. As stated in the GL, the identified provisions (e.g., reducing this leakage restriction to 150 gpm) were to ensure that structural and leakage integrity continue to be maintained with an acceptable level of margin during normal, -operating, transient, and postulated accident conditions. At the time the GL was issued, the CR-3 ITS primary-to-secondary leakage limit during normal operation was one gpm. To improve leakage integrity, CR-3 reduced this to 150 gpd per OTSG consistent with the GL. This limit was introduced as a temporary (one cycle) revision to the CR-3 ITS in Amendment 154 (Reference 5), and made permanent in Amendment 158 (Reference 2).

In Amendment

158, the change to the Bases described this primary-to-secondary leakage through all OTSGs as follows:

"This LEAKAGE limit is established to ensure that tubes initially leaking during normal operation do not contribute excessively to total leakage during postulated accident conditions.

The 150 gpd limit is a conservative limit which is consistent with the operational leakage limit specified in NRC Generic Letter 95-05 for plants implementing Alternate Repair Criteria. CR-3 has elected to voluntarily adopt this conservative limit to ensure plant shutdown in a timely manner in response to detection of primary to secondary LEAKAGE."

The 150 gpd per OTSG is a limit placed on primary-to-secondary leakage during normal operation. Under accident conditions, total primary-to-secondary leakage is assumed to increase to no more than one gpm. This one gpm accident leakage is not mechanistically modeled in the accident analysis based on an initial operating leakage of 150 gpd per OTSG.

It is not mathematically derived from the allowed operating leakage.

The value assumed for primary-to-secondary leakage during accident conditions is an analytical assumption, unrelated to the value defined in the CR-3 ITS for allowed operating leakage. Both values are currently part of the approved licensing basis for CR-3. As stated earlier, these remain unchanged by this amendment request, consistent with TSTF-449, Revision 4.

Additional margin between operational and accident leakage is provided by procedural implementation of NEI 97-06, "Steam Generator Program Guidelines." CR-3 plant procedures ensure enhanced monitoring is established when primary-to-secondary leakage is detected greater than 5 gpd. Monitoring is escalated if the leak grows above 30 gpd and the procedure begins an orderly plant shutdown for leakage above 75 gpd. These limits are the combined leakage from both OTSGs.

These procedural controls provide addition margin between operational leakage and the assumed accident leakage value of one gpm.

References:

1. NRC Generic Letter 95-05 dated August 3, 1995, "Voltage-Based Repair Criteria for Westinghouse Steam Generator Tubes Affected by Outside Diameter Stress Corrosion Cracking"

2. NRC to Crystal River Unit 3 Letter dated October 28, 1997, "Crystal River Unit 3 - Staff Evaluation and Issuance of Amendment Re: Steam Generator Tube Intergranular Attack Degradation [TAC No. M98262]

3. Crystal River Unit 3 to NRC Letter dated May 25, 2006, "Crystal River Unit 3 - License Amendment #264, Revision 0, Applicability to Modify Improved Technical Specifications Regarding Steam Generator Tube Integrity"

U.S. Nuclear Regulatory Commission Attachment A 3F1206-02 Page 12 of 12

4. NRC to Crystal River Unit 3 Letter dated September 10, 2001, "Crystal River Unit 3 -

Issuance of Amendment Regarding Reroll Repair for Once-Through Steam Generator Tubing (TAC No. MB1519)"

5. NRC to Crystal River Unit 3 Letter dated April 30, 1996, "Crystal River Nuclear Generating Plant Unit 3 - Issuance of Amendment Re: Alternate Repair Criteria for Steam Generator Tubing (Tac No. M92548)"

PRORESS ENERGY FLORIDA, INC.

CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302 / LICENSE NUMBER DPR-72 LICENSE AMENDMENT REQUEST #264, REVISION 1 Application to Modify Improved Technical Specifications Regarding Steam Generator Tube Integrity ATTACHMENT B Description and Assessment

U.S. Nuclear Regulatory Commission Attachment B 3F1206-02 Page 1 of 4 Description and Assessment

1.0 INTRODUCTION

The proposed license amendment revises the requirements in the Crystal River Unit 3 (CR-3) Improved Technical Specification (ITS) related to steam generator tube integrity.

The changes are consistent with NRC approved Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-449, "Steam Generator Tube Integrity," Revision 4. The availability of this technical specification improvement was announced in the Federal Register on May 6, 2005 as part of the consolidated line item improvement process (CLIIP). This request replaces License Amendment Request

264, Revision 0, submitted May 25, 2006, in its entirety.

2.0 DESCRIPTION

OF PROPOSED AMENDMENT Consistent with the NRC-approved Revision 4 of TSTF-449, the proposed ITS changes include:

Revised ITS definition of LEAKAGE

Revised ITS 3.4.12, RCS [Reactor Coolant System] Operational Leakage

New ITS 3.4.16, Steam Generator (OTSG) Tube Integrity

" Revised ITS 5.6.2.10, Steam Generator (OTSG) Program

" Revised ITS 5.7.2.c, d, and e, Steam Generator Tube Inspection Report(s)

Proposed revisions to the ITS Bases are also included in this application. As discussed in the NRC's model safety evaluation, adoption of the revised ITS Bases associated with TSTF-449, Revision 4 is an integral part of implementing this ITS improvement. The changes to the affected ITS Bases pages will be incorporated in accordance with the ITS Bases Control Program.

3.0 BACKGROUND

The background for this application is adequately addressed by the NRC Notice of Availability published on May 6, 2005 (70 FR 24126), the NRC Notice for Comment published on March 2, 2005 (70 FR 10298), and TSTF-449, Revision 4.

4.0 REGULATORY REQUIREMENTS AND GUIDANCE The applicable regulatory requirements and guidance associated with this application are adequately addressed by the NRC Notice of Availability published on May 6, 2005 (70 FR 24126) the NRC Notice for Comment published on March 2, 2005 (70 FR 10298),

and TSTF-449, Revision 4.

5.0 TECHNICAL ANALYSIS

Florida Power Corporation (FPC) has reviewed the safety evaluation (SE) published on March 2, 2005 (70 FR 10298) as part of the CLIIP Notice for Comment. This included the NRC staff's SE, the supporting information provided to support TSTF-449, and the changes associated with Revision 4 to TSTF-449.

FPC has concluded that the

U.S. Nuclear Regulatory Commission 3F1206-02 Attachment B Page 2 of 4 justifications presented in the TSTF proposal and the SE prepared by the NRC staff are applicable to CR-3 and justify this amendment for the incorporation of the changes to the CR-3 ITS.

6.0 REGULATORY ANALYSIS

A description of this proposed change and its relationship to applicable regulatory requirements and guidance was provided in the NRC Notice of Availability published on May 6, 2005 (70 FR 24126), the NRC Notice for Comment published on March 2, 2005 (70 FR 10298), and TSTF-449, Revision 4.

6.1 Verification and Commitments The following information is provided to support the NRC staff's review of this amendment application:

Plant Name, Unit No.

Crystal River Unit 3 Steam Generator Model(s):

177FA Effective Full Power Years (EFPY) of service for currently Approximately 19.2 as of Refuel 14 (Nov. 05, 2005) installed OTSGs Tubing Material Alloy 600 Stress Relieved Number of tubes per OTSG 15,531 Number and percentage of tubes OTSG A OTSG B plugged in each OTSG 351 (2.3%)

862 (5.6%)

Number of Tubes repaired in each OTSG OTSG A OTSG B Tubes wi sleeves (Inservice) 159 156 Tubes wI repair rolls (Inservice) 948 1401 Primary Water Stress Corrosion Cracking Degradation mechanism(s)

(PWSCC) degrdtion m-Outside Diameter Intergranular Attack/Stress identified Corrosion Cracking (OD IGA/SCC)

Wear / Fretting / Thinning Per SG: 150 gallons per day (gpd) per LCO Current primary-to-secondary 3.4.12.d leakage limits:

Total:

No total limit specified in ITS Temperature condition leakage is evaluated at: room temperature

U.S. Nuclear Regulatory Commission 3F1206-02 Attachment B Page 3 of 4 Approved Alternate Tube Repair Criteria (ARC):

1. First Span IGA

2. Tube End Cracks (TECs)

- Approved by: Amendment 158 dated 10/28/97

- Applicability: Inservice tubes with pit-like IGA indications in the first span of OTSG B

- Any special limits on allowable accident leakage:

None

- Any exceptions or clarifications to the structural performance criteria that apply to the ARC: None Approved by: Amendments 188 dated 10/01/99 and 222 dated 10/31/05 Applicability: Inservice tubes with axially-oriented TECs in either OTSG Any special limits on allowable accident leakage:

1 gallon per minute (gpm) minus 150 gpdfor TECs combined with all other postulated accident leakage Any exceptions or clarifications to the structural performance criteria that apply to the ARC: None Approved OTSG Tube Repair Methods

1. Sleeves

2. Repair Rolls Approved by: Amendment 136 dated 09/11/91 Applicability limits, if any: (ITS 5.6.2.10.4.a.1l.a)

No more than five thousand sleeves may be installed in each OTSG.

Repair criteria: 40% of the sleeve wall thickness Approved by: Amendment 198 dated 09/10/01 Applicability limits, if any: None.

Repair criteria: 40% of the initial wall thickness Performance criteria for accident Primary to secondary leak rate values assumed in leakage licensing basis accident analysis, including assumed temperature conditions: 1 gpm at room temperature assumed in the CR-3 Final Safety Analysis Report 7.0 NO SIGNIFICANT HAZARDS CONSIDERATION FPC has reviewed the proposed no significant hazards consideration determination published on March 2, 2005 (70 FR 10298) as part of the CLIIP. FPC has concluded that the proposed determination presented in the notice is applicable to CR-3 and the determination is hereby incorporated by reference to satisfy the requirements of 10 CFR 50.91(a).

U.S. Nuclear Regulatory Commission Attachment B 3F1206-02 Page 4 of 4 8.0 ENVIRONMENTAL EVALUATION FPC has reviewed the environmental evaluation included in the model SE published on March 2, 2005 (70 FR 10298) as part of the CLIIP. FPC has concluded that the staff's findings presented in that evaluation are applicable to CR-3 and the evaluation is hereby incorporated by reference for this application.

9.0 PRECEDENT This application is being made in accordance with the CLIIP. FPC is not proposing variations or deviations from the ITS changes described in TSTF-449, Revision 4, or the NRC staff's model SE published on March 2, 2005 (70 FR 10298). Several clarifications have been requested by the NRC Staff as described in Attachment A. These proposed changes are consistent with the CLIIP model application.

10.0 REFERENCES

Federal Register Notices:

Notice for Comment published on March 2, 2005 (70 FR 10298)

Notice of Availability published on May 6, 2005 (70 FR 24126)

PRORESS ENERGY FLORIDA, INC.

CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302 / LICENSE NUMBER DPR-72 LICENSE AMENDMENT REQUEST #264, REVISION 1 Application to Modify Improved Technical Specifications Regarding Steam Generator Tube Integrity ATTACHMENT C Proposed Improved Technical Specification Changes (Mark-up)

Stikeei* -4 indicates deleted text.

Aýg indicates added text.

TABLE OF CONTENTS 3.3 3.3.11 3.3.12 3.3.13 3.3.14 3.3.15 3.3.16 3.3.17 3.3.18 3.4 3.4.1 3.4.2 3.4.3 3.4.4 3.4.5 3.4.6 3.4.7 3.4.8 3.4.9 3.4.10 3.4.11 3.4.12 3.4.13 3.4.14 3.4.15 F3.4 16 3.5 3.5.1 3.5.2 3.5.3 3.5.4 3.6 3.6.1 3.6.2 3.6.3 3.6.4 3.6.5 INSTRUMENTATION (continued)

Emergency Feedwater Initiation and Control (EFIC) System Instrumentation.................

3.3-26 Emergency Feedwater Initiation and Control (EFIC)

Manual Initiation......................

3.3-30 Emergency Feedwater Initiation and Control (EFIC) Automatic Actuation Logic..............

3.3-32 Emergency Feedwater Initiation and Control (EFIC)-Emergency Feedwater (EFW) -Vector Valve Logic...................................

3.3-34 Reactor Building (RB)

Purge Isolation-High Radiation.....................................

3.3-35 Control Room Isolation-High Radiation...........

3.3-36 Post Accident Monitoring (PAM)

Instrumentation.. 3.3-38 Remote Shutdown System...........................

3.3-42 REACTOR COOLANT SYSTEM (RCS) 3.4-1 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB)

Limits............

3.4-1 RCS Minimum Temperature for Criticality.........

3.4-3 RCS Pressure and Temperature (P/T) Limits.......

3.4-4 RCS Loops-MODE 3................................

3.4-6 RCS Loops-MODE 4................................

3.4-8 RCS Loops-MODE 5, Loops Filled..................

3.4-10 RCS Loops-MODE 5, Loops Not Filled..............

3.4-13 Pressurizer......................................

3.4-15 Pressurizer Safety Valves.......................

3.4-17 Pressurizer Power Operated Relief Valve (PORV)

.. 3.4-19 Low Temperature Overpressure Protection (LTOP)

System....................................

3.4-21 RCS Operational LEAKAGE..........................

3.4-22 RCS Pressure Isolation Valve (PIV)

Leakage...... 3.4-24 RCS Leakage Detection Instrumentation...........

3.4-27 RCS Specific Activity............................

3.4-30 Steam Generator,(OTSG) Tube Inteqri~ty.............3.4-34, EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5-1 Core Flood Tanks (CFTs)..........................

3.5-1 ECCS-Operating..................................

3.5-4 ECCS - Shutdown...................................

3.5-7 Borated Water Storage Tank (BWST) 3.5-9 CONTAINMENT SYSTEMS.................................

3.6-1 Containment......................................

3.6-1 Containment Air Locks............................

3.6-3 Containment Isolation Valves....................

3.6-8 Containment Pressure.............................

3.6-15 Containment Air Temperature.....................

3.6-16 (continued)

Crystal River Unit 3 ii Amendment No. 1,6-1

TABLE OF CONTENTS B 3.3 INSTRUMENTATION (continued)

B 3.3.12 Emergency Feedwater Initiation and Control (EFIC)

Manual Initiation....................

B 3.3-100 B 3.3.13 Emergency Feedwater Initiation and Control (EFIC) Automatic Actuation Logic............

B 3.3-105 B 3.3.14 Emergency Feedwater Initiation and Control (EFIC)-Emergency Feedwater (EFW)-Vector Valve Logic.................................

B 3.3-110 B 3.3.15 Reactor Building (RB)

Purge Isolation-High Radiation..................................

B 3.3-114 B 3.3.16 Control Room Isolation-High Radiation.........

B 3.3-119 B 3.3.17 Post Accident Monitoring (PAM)

Instrumentation B 3.3-124 B 3.3.18 Remote Shutdown System.........................

B 3.3-145 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4-1 B 3.4.1 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB)

Limits...........

B 3.4-1 B 3.4.2 RCS Minimum Temperature for Criticality........

B 3.4-6 B 3.4.3 RCS Pressure and Temperature (P/T) Limits......

B 3.4-9 B 3.4.4 RCS Loops-MODE 3...............................

B 3.4-17 B 3.4.5 RCS Loops-MODE 4...............................

B 3.4-22 B 3.4.6 RCS Loops-MODE 5, Loops Filled.................

B 3.4-27 B 3.4.7 RCS Loops-MODE 5, Loops Not Filled.............

B 3.4-33 B 3.4.8 Pressurizer.....................................

B 3.4-37 B 3.4.9 Pressurizer Safety Valves......................

B 3.4-43 B 3.4.10 Pressurizer Power Operated Relief Valve (PORV)

.B 3.4-47 B 3.4.11 Low Temperature Overpressure Protection (LTOP)

System...................................

B 3.4-52 B 3.4.12 RCS Operational LEAKAGE.........................

B 3.4-53 B 3.4.13 RCS Pressure Isolation Valve (PIV)

Leakage..... B 3.4-58 B 3.4.14 RCS Leakage Detection Instrumentation..........

B 3.4-65 B 3.4.15 RCS Specific Activity...........................

B 3.4-71 B3.4.16 7 Seam Generator (OTSG)

Tube Integýy......B3 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

B 3.5-1 B 3.5.1 Core Flood Tanks (CFTs).........................

B 3.5-1 B 3.5.2 ECCS-Operating.................................

B 3.5-9 B 3.5.3 ECCS-Shutdown..................................

B 3.5-20 B 3.5.4 Borated Water Storage Tank (BWST)

B 3.5-24 B 3.6 CONTAINMENT SYSTEMS................................

B 3.6-1 B 3.6.1 Containment.....................................

B 3.6-1 B 3.6.2 Containment Air Locks...........................

B 3.6-6 B 3.6.3 Containment Isolation Valves...................

B 3.6-15 B 3.6.4 Containment Pressure............................

B 3.6-29 B 3.6.5 Containment Air Temperature....................

B 3.6-32 B 3.6.6 Reactor Building Spray and Containment Cooling Systems..............................

B 3.6-35 (continued)

Crystal River Unit 3 vi Amendment No. 14ý2

Definitions 1.1 1.1 Definitions LEAKAGE (continued)

3.

Reactor Coolant System (RCS)

LEAKAGE through a steam generator OTSG)-tu

.e to the secondary system rprmary to_ econd ILEAKAGE).

b.

Unidentified LEAKAGE All LEAKAGE that is not identified LEAKAGE.

c.

Pressure Boundary LEAKAGE MODE NUCLEAR HEAT FLUX HOT CHANNEL FACTOR (FQ(Z))

NUCLEAR ENTHALPY RI ýE, HOT CHANNEL FACTOR AFNH)

OPERABLE-OPERABILITY LEAKAGE (except O*,SGtu*e,leakage i

y m

decondary LEAKAGE) through a non-isolable fault in an RCS component body, pipe wall, or vessel wall.

A MODE shall correspond to any one inclusive combination of core reactivity condition, power level, average reactor coolant temperature, and reactor vessel head closure bolt tensioning specified in Table 1.1-1.

FQ(Z) shall be the maximum local linear power density in the core divided by the core average fuel rod linear power density, assuming nominal fuel pellet and fuel rod dimensions.

FNH shall be the ratio of the integral of linear power along the fuel rod on which minimum departure from nucleate boiling ratio occurs to the average fuel rod power.

A system, subsystem, train, component, or device shall be OPERABLE when it is capable of performing its specified safety function(s) and when all necessary attendant instrumentation, controls, normal or emergency electrical power, cooling and seal water, lubrication and other auxiliary equipment that are required for the system, subsystem, train, component, or device to perform its specified safety function(s) are also capable of performing their related support function(s).

PHYSICS TESTS shall be those tests performed to measure the fundamental nuclear characteristics of the reactor core and related instrumentation.

PHYSICS TESTS (continued)

Crystal River Unit 3 1.1-5 Amendment No. 149

RCS Operational LEAKAGE 3.4.12 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.12 RCS Operational LEAKAGE LCO 3.4.12 RCS operational LEAKAGE shall be limited to:

a.

No pressure boundary LEAKAGE;

b.

1 gpm unidentified LEAKAGE;

c.

10 gpm identified LEAKAGE; and

d.

150 gpd of primary to secondary LEAKAGE through any one steam generator (OTSG).

I

-rr I-

^

-nA M

r I VVW V

.1 I -.

jJ' 11

.II IC I I LJ 1ý J

I-L.I'%JU-1LL.-

APPLICABILITY:

MODES 1, 2,

3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

RCS ' perationalI A.1 Reduce LEAKAGE to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months LEAKAGE not within within limits.

limits for reasons other than pressure boundary LEAKAGE'L6_r

!primaryto secondary' LEAK.AGE.

B.

Required Action and B.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met.

AND OR B.2 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Pressure boundary LEAKAGE exists.

LTPrimary to secondar 7LEAKAGE not within Crystal River Unit 3 3.4-22 Amendment No. 1-5-8 1

RCS Operational LEAKAGE 3.4.12 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.12.1 NOTE.-----------------------

,17-Not required to be performed in MODE 4.

Not required in MODE 3 until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of steady state operation.

2. -N

-t-pl

-ble to pri'mary, to secondary ILEAKAGE.

Verify,RCS operational LEAKAGE i~s with~i imit*Gs by pece of Perform RCS water inventory balance during steady state e.=rat stat 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months SR 3.4.12.2 NOTE Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment.of steady sta* t operati on.

Verify steam generator tube integrity is in 1 -

2ý.

in aeeordance with the Steam G.enerator ub Su rvei 11

.ane Pro7a2nho 72_ hoursý CL%%,UlI U,,"

IC VV I LI L

I-

,. LT 1I c

,Jc L

l Ic : I C.Li..UII U U ::

.urveillance Program. Mefy p Isendary LEAKAGE is <:5 150 gallons per daj ithrouah anv,,one steam aenerator.,

Crystal River Unit 3 3.4-23 Amendment No. 1-4-9

qTSG Tube Integrity 3.4 REACTOR COOLANT SYSTEM (RCS) 3-T.4-.46 Steam'- enerator (OiT§G-)Tube Ttegjjý LCO 3.4.16 OTSG tube-inteqrity shall be maintained.!

'AWN 0, All OTSG tubes satisfying the tube repair criteria shall be pugged :or~r:epaired in acco rdance with the Steam Generato r Program APPLICABILITY:

MODES 1. 2',*' 3 and.41

NOTE --------.--------------------

~

Separate Condition entry is allowed for each OTSG tube*.l I------------------------------------------------

I---------

t

-ONDITION REQ flR:E D~ ACTIf-fON

`0MPLETION~ TIME One or more OTSG A.1 Verify tube inteegritý 7 -da tubes satisfyingt--he f the affected

,tube repair cri thria tube(s) is maifnectd id and not pluggedaor~

unti l the next.

k repaired id rrefueling outage or accordance with the OTSG tube,inspection.

Steam Generatorn LProg~ram.AN A.2 Plug or repair the

[Prior to entering'

!affected tube(s) in MODE 4 following' laccordance with the the next r S~team GeneratorFý outage or OTSG R og r a m itube inspection

-ReqUired Action and 10.1 Be in MODE7hu associ ated Compl etion 1Time of Condition Ar WD not met.

iB.2 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months

,TS-G tube integrit' not maintainedp.

Crystal River Unit 3 3.4-34 Amendment No. XX

PTtSGTube Integrity 13.4.16 SURVEI-LLAN.CEREQOUI-RýEMENT-S,__________

SURVEILLANCE REQUENCY_

SR 3.4.16.1 Verify OTSG tube integrity in accordancý tIn accordance with!

'with the StearnGeneriator Program;

'the Steam'

,Generatq~r Program

~R34>62Vrif y that each inpce PTGtbe-a

'rior to enter~ing satisfies the tube repaircriteria is MODE 4 folljowin a

dor repaired in accordancewith the! bTSG tube

'SteamjIGene rato r P~rogram.f I.

nspet oj Crystal River Unit 3 3.4-35 Amendment No. XX

Procedures, Programs and Manuals 5.6 5.6 rrocedures, Programs and Manuals (continued) f/-*Ii-f=. f=. "%

"I-I

=-

5.6. 2. :0

~rn~m (.nr.arnrr~r 11113/4fl I iir.n '~i:r-..'p~ I I2fl~D Prflrlr2m

~

I LALfl.

-~

J I= q*w (.&l I I Each OTSG shall be demonstrated OPERABLE by performance ofth following augmented inservice inspection program.

1. Each OTSG shall be determined OPERABLE during shutdown by selecting and inspecting at least the minimum number of OTSGs specified in Table 5.6.2 1.

2. The OTSG tube minimum sample size, inspection result classification, and the corresponding action required shall be as specified in Table 5.6.2 2.

The inservice.e...

c-tion of OTSG tubes shall be performed at the frequencies-specified in Specification 5.6.2.1:0.3 andthinpce tubes shall be verified acceptable per the accpac criteria of Specification 5.6.2.1:0.4. The tbsselec-ted for each isrceinspection shall include at least 3%o the total number of tubes in all 0TSGs. The tubes selected for these npcin shall be selected on a random basis txeeptt

a. Where experience in similar plants with similar water chemistry indicates critical areas to be inspected, then at least 50% of the tubes inspected shall be Fro these critical areas.

b. The first inservice in'spection (subsequent to the preservice inspection) of @eah OTSG shall include:

1.

11l nonplugged tubes that previouslyha detectable wall penetrations (>20%), and

2. Tubes in those areas where exper ience has4; indicated potential problems&.-

C.The second and third ineric inspections may be less than a full tube inspection by concentrating (selectIng at least 50% of the tubes to be inspected) the inspection on those areas of the tube sheet array antd on those portions of the tubes where tubes with imperfecton were previously foun

d.

Tubes in"s i

limited areas which are distinguished by unique operating condItUiVn or physical constructiOn may be excluded from random samples if all such tubes (continued)

Crystal River Unit 3 5.0-13 Amendment No. 1-49

Procedures, Programs and Manuals 5.6 rE-Procedures, rrograms and Manualsy 5.6.2.10 OTSG Tube Surveillance Program (continued)-

in the specific area of an OTSG are inspected withth insectonresult classification and the corresponding action required as specified in Table 5.6.2 3. No credit will be taken for these tubes in meeting minimu sample size.req uirements.

Degraded or defective tube found in these areas will not be considered in determining the inspection results category as long as the mode of degradation is uniqu to that area andno random in nature-.-

t.-Inservice tubes with pit like IGA indications in thte first span of the B OTSG, identified in the OTSG inservice Inspection Surveilla nce..

Procedure, must be p.. ted with bobbin and Motorized Rotating rancake Col MRPC) eddy current techniques from the lower tube setsecondary face to the bottom of the first tube support plate during each inserviceinpcto of thB OTSG.

No credit is to be taken for thisinpconn meeting iiu sample Siz requrements for the rano insecton.

Defective tubes found during this inspection are to be plugged or sleeved. Degraded or defective tubes found during this inspection are not to be considered in determining the inspection results category for the random inspection, unless the degradation mechanism identified is a mechanism other than pit like IGA-.

f.---Tubes in service with axially oriented tube end crak (TEC) are identified in the OTSG Inservice Inspectio Surveillance procedure. The portion of the tube with the axial TEC must be inspected using the motorized rotating coil eddy current technique during each subsequent inspection.

No credit is to be taken fo~r this inspection for meeting the miniu saple size requirement for random sampleinpco.

Tubes identified with TEC that meet the alternate repair criteria will be added to the existing list of tubes i the OTSG inservice Inspection Surveillance procedure Tubes identified with TEC during the previou inspetion whieh meet the ci

,'-ri ia to remain in service I

wI not be included when c lating the inspection category of the (co nti nued)

Crystal River Unit 3 5.0-14 Amendment No. I-&&

Procedures, Programs and Manuals 5--6 5-rS--Procedures, Programs and Manualsy 5.6.2.10 OTSG Tube Surveillance Program (continuedI)I The inspecion data for tubes with axially oriented TEC indications shall be compred to h reiu inpetion data to monitor the-idctos for growth.

Tubes with axially orienmted TEC may e lft in servic using%

the~

meho decie i oialRpr AW 23346P, Re%-v Iision 0,provi ded thecmidprjtd leakatge fEC

']

aill V Indr V%

e,'"in lilE:

I1IUI ;%.LdLI UII3 ICICLC IUI I

eh I

e dlll~l sL I LII *ULIA I *lL K~~ 1.

Main Steam Line BrapML)acdn ekg limit of oneI galln 1pe minue minus..

150 gallons per..day.per II1*1L

.LlAuJly 11; I I n ut~iiudi'k UIII1 L

&Ji L

yUSL Id, l

LgU e!!n r

k. -.- AIn.

pt4-n t A I~eakaje LI&L L*eI*tx tL uu y

i V u ei i uli h l~lE KuIIa Lt ll L

UUJ*I E;

LUk:

\\E~LIJl uO ITIa J

Topical ~~

A.

Reor BA 34P Rvsin0 toseonar lAkageandu th caused i eerie to b th lcain of the1 TEC Ifmr hn 1% ofth with j TEC in the ote OTG sthall ed exmndiuh location ofte the TEC.-

Tueswih rak ik ndice atios wtin dth carb4 onb steel ~

k-T-C portion of the tubesethalbrpiedo method.

Tubes~

with cicufretally orentxmied TE r

vh oluetrcidcti onoiti thee-F17-Incone cla rftego ofted tubeshe sall beecie repaied orreoed from sevice u ing the appr OrIt Vap

.pr oved3 meIItho idA.I l1ý The esutso of eahe bobincoi apeisecinsalb clasifed iheaklk intoonoatetolowng wthree ctheegories:

ste nlr rt!i~n-? [theftub shreet shall

...L removed I

II on,*CII seI vI,

n%

II.L.

-Fl

.I

-L~lE I

ýlll U/

M me thod.

Tubelsl l

I i

I with iei Igp 1, dy

.i111I e~l i

signficatr

(>10 icfuthers wall pntrationstome be incue in the belowperentag chalclations.d rreoý4-ý"

elas If i

L.d i nto one of:I the I

I I wIv I-II1 IVI U

%.1.1III e

lea e I E...

the I

t-liow, pe e

-nt g

(e:Il FI/ W.*

II=,

I GL-L.

1 I I

VlI ii UJ I II]L y-NOTE For theý iseto conducted in accordance wvith 5.6.2.102f ony tubes wit TEC L'

indications identified after te 1997inspection will be included in the below percenitage -call cul ati ons.

I*entinutd}

55.0 14A Amn et No. 222

- -Sý w ý P M

ý 1Y.JL.LL* I

\\

Vt.l UII I I.J

Procedures, Programs and Manuals 5.6 I5-6-Proledures, rrograms and ManualsI 5,.L-E----+ OTSG Tube Surveillanee Program I

(ontinued) insnection Resulits C 1:

Less than 5% of the total tubes-inspeced are deg!rSIde tubes and none of te inspet tubeS are de-II(eive.

C 2 One or more tubes, but not more than 1% of the total tubes inspected ar defective.o between 5% and 10% of the1 total tubers insected are degraded tubes.

C 3 More than 10% of the total tubes-1inspecede are degraded _tubes or more tha~n,/

%Jof thIe inspecte tubesJ @ are defective.

3. The above re~quired -inservice inspections of OTSG tubes shl be perfome-d at the followin frqenis

'Of not lp I an 111U1-IILV..

l-II fvrU iIIUI men IIL LVEI~d~~~

I I/OUL I*

.Li/OiI LII 4

LdiCiLa I d

Liii after th!eprevou isetion.

if two consecutive insectonsfolowig ervice under all volatil p!Is I

I I

I

/

I L

Ir UI I

" I I i

tion rIesl ts IuHty ILE u,1E L

IIE u1OWpL IEUiE,IL,eS.~

L,~u~

inspections dmntae at peiouslwobposeredtv degrIIaation has not co ntinued IandI no add itional degjradation has occurred, the inspeto Thterval may be etened o a axium f one pr 4 months.

b.

If the inservce,III tlI n of an OTIl

, conducted in acrance with ITable 5.6.2 2 or Tabl e a.6.

2 3 reqie inpetin reuench hllapy until a subsequent 1nsp1 e 1ti demonstrates that-a Ird,11s*inspeti4on is not required.if the CI I nsIpt in results classi.ica-tion i s due toi incl.

uding new tubes with T[i i ndiceati ons that meet the cri teri a to. remain H in servICe, no reduction in inspectOn frequency

-I required.

e.Additional unscheduled isrcenpctons shall be promed on each OTSG3' in accoidrdance wvith the firs-t Sample inspectio1n specifited in Table 5.6.2 2 or Table 5..

3 duin tQ shtow usequent to any of th-e

i. Primaryt secondary tube -e-aks-_-(nt-Tnl1ud~npq

+ak~o1-gmILIII IIn

-U1, t

t~ub sheet-Vwe us in excess of the limits of Specification 3.4.12-,

2. A seismic occuirrence greater than the Operating Basis [arthquake,

3. A loss of coolant accident reuig acetuati on of the engineered safeguards, or

4. A main steam line or feedwater line break(.

(conti nued)

Crystal River Unit 3 S.0-15 Amendment No. 2-2-2

Procedures, Programs and Manuals 5.6 5--.r 1.edures, r

egrams and ManuaIlI 5.6.2.10 OTSG Tube Surveillanee Program (continued)-

4. Acceptance iera

a. Vocabulary as used in this Specification:

1. Tubing or Tube means that portion of the tube o sleeve which forms the primary system to secondary system pressure boundary.

2. Imperfection means an exception to the dimensions, finish or contour of a tube from that required by fabrication drawings or specifications. Eddy eurrent testing indications below 20% of the nominal tube wall thickness, if detectable, may be eonsidered as imperfections-.

3. Degradation means a servi..

induced cracking, wastage, wear, or general orrosion ccurr ag on either inside or outside of a tube.

4. Degraded Tube means a tube containing degradation

>20% through wall but < 40% through wall in the pressure boundary.

5. % Degradation/% Through wall means the percentagje of the tube (pressure boundary) wall thicknes affected or removed by degradation.

6. Defective Tube means a tube containing degradation

>40% through wall in the pressure boundary.-Aney tube which does not permit the passage of the eddy current inspection probe shall be deemed-a defective tube.

7.

Pt like in t-T lar Attack (IGA) indiatio--

means a bobbi n coil i ndi cati on confi rmed by Motorized Rotating Pancake Coil (MRrC) or othe qualified inspection techniques to havea volumetrie, pit like morphology characteristico (conti nued)

Crystal River Unit 3 5.0-16 Amendment No. 14ýO

Procedures, Programs and Manuals 5.6 7-6-Rrocedures, Programs and Manuals A-l-t" P

-r_

_I-t"....

-i =ii L.

e +/-J OTSU Tube Surveillanee Pr ogram (1-ntinued)

8.

Plugging/Repair Limit man the extent of pressure boundary degradation beyond which the tube shall either be removed from serviee by installation of plugs or the area of degradation shall be remoe from serviee (a new pressure boundary established) a Approved Repair Te.hnique.

The plugging/.repair limit is 40% through wall for all pressure boundary degradation.

9.

Unserviceable describes the condition of a tub it leaks or contains a defect large enough to affect its structural integrity in the event of an Operating Basis Earthquake, a loss of.colant accident, or a main steam line or feedwater line break, as specified in 5.6.2.1O0.3.e, above.

10. Tube inspection means an inspection of the OTSIG tube pressure boundary.

14. Approved Repair Technique means a technique, o than plugging, that has been accepted by the NRC as a methodology to remove or repai r degraded or defective portions of the pressure boundary and to establish a new pressure boundary.

Following are Approved Repair Techniques:

a) Sleeve installation in accordance with the B&

process (or method) described in report BAW 2120P.

No more than five thousand sleeves may be installed in each OTSG.

b) installation of repair rolls in the upper and lower tubesheets in accordance with BAW 230aP-,

Revision 4.

The repair process

single, overlapping, r multiple roll) maytabe performed in each tube.

The repair roll a will be examined using eddy current methodsl following installation.

The repair roll mut be free of imperfections and degradationfo the repair to be considered acceptable.

(continued)

Crystal River Unit 3 5.0-17 Amendment No. +9ý8

Procedures, Programs and Manuals

_576 6-Proeedures, Programs and Manualsy

.6--2--+,OTJSG Tube Surveillance Program

(,ontinued)

The repair roll in each tube will be inspete during each subsequent inservice inspecti on whiIe the tube VlIt I l I epair roll is in sevice.

The repair roll will be considerea specific limited area and will be excluded from the random sampling.

No credit will be taken for meeting the minimu saple size.

if primary to secondary leakage results in-a shutdown of the plant and the cause_ is determined to be degradation in a repairrol 100% of the repair rolls in that OTSG shallb examined.

if that inspection, results in entering Category C 2 or C 3 for specific limited area inspection, as detailed in Tabl-e 5.6.2 3, 1:00% of the repair rolls shall be e aied in the other OTSG-.

1:2.

Tube End Cracks (TEC) are those crack like eddy currnt ndications, circumferentially and/or axially oriented, that are within the in1onel clad region of the primary face of the upper and lower tubesheets, but do not extend into the carbont steel to inIonel clad interface.

b. The OTSG shall be determined OP[RABLE after compl the correspondi-g a--tions (plug or.repai.

all tubes, exceeding the plugging/'repai r limit) requi red by Tabl 5.6.2 2 eand Table 5.6.2 3 if the o i s ins of Specification 5.6.2.10.2.d are utillized).

inservile tubes with pit like IGA indications in the "B" OT-SG first span shall be monitored for growth of ths indications by using a test probe equivalent to the high frequency bobbin probe used in the 1997 inpci.

The indicated percentage throughwall value from, th crent ispetion shall be compared to the indicated percentage ThOgwall value from the 1997 incn

-E~eonnued)

Crystal River Unit 3 5.0 17A Amendment No. 198

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals 5.6

.7A0Steam_

Generqtor_-(0TSq)_Pr~g~ranm A Steam Generator Program shall be established and implemented to ensure that OTSG tube integrity is maintained.,

In addition, th LISteam Generator__Pro9gram shall include the following roiVcs

a.

Provisions n

or condition monitoring assessments.

Condition monltoring assessment means, an evaluation of the "as found"

'condition of the tubing withres*pect to the performance

'criteria fo'r structural integrity and ~accidentinduiced,-

leakage.

The, "as found" condition refers to the c*ne d ii of the tubing during an OTSG inspection outage, asm__

'determined' from the inservice inspectio~n results or by other means, prior to~ the pluggi~ng or repa~ir of tubes.!~

I Condi'tion monitoring' assessments shall be conducted duringi each outage during which the OTSG tubes are inspectedF-plugged, or repaired to confirm that the performanc-kcr-iteriaare beingLmet.j

Perf0o-rmance criteri

'or OTSG tube,integrity. -iOT`uT

)integrity shall be maintained by meeting the performance

,criteria for tube structural integrity., acciden 1,eakage..

a~ndope rati onal-LEAýKAGE.1

11.

'Structural integrity performance criterion.:

All in-,

1service steam generator tubes'shall retain structural integrity over the full range of normal,o:perating

,conditions (i-ncluding startup, op~eration in'the powe'

irange, hot standby, and cool down and all anticipated itransientsincluded in the design specification) and

'design basis accidents.

This includes retaining a*

safety facto

' r of* 3.0 agAinst burstt under normal-- :ed'.

-to-seconda' stt~fl power operation pri~mary-t-ecnar%

!pressure differential and a safety factor of 1,4 iagainst burst applied to the design basis accident primary-to-secondary pressure differentials.

Aparf

'from' the above '~requi rements, additional, lodi n Iconditions associated with the'design basis accidents, pr combination of accidents in accordance with the--

'design, and licensing basis,' shall also be evaluate'0Vfd determine if the associa<tecd loads: contriibut4e_

slignificantly to burst or'colla'pse.

In the assessmenit, of tube 'integrity, those loads that do significantly 1'affect burst or collapse shall be determined and ---

assessed in combination with the loads due-to pressure wi*th ;a' safety factor of 1.2 on the combined pri 1loads and 1.0 on axial secondary loads.

(continued)

Crystal River Unit 3 5.0-13 Amendment No. XX

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals

2.

Accident induced leakage performance criterion: The primary to ~secondary accident induced leafrage rate fo-r' any design basis accident, other than an OTSG tube rupture, shall not exceed the leakage rate assumed in ithe accident analysis in terms of total leakage rate

,for all OTSGs and~< leakage rate for an individual OT~S'U2 Leakage is*,not to exceed one gallon per minute per OTSG.

L3 Tjhe operational. LEAKAGE performanc e criterion is.

spe5cified 'n LCO 3..12,

"~RCS Op~eainl~EKG~

1c.

Provisions for OTSG tube repair criteria.

The non-sleeved Iregion of a~ tube found ~by inservice inspection~ to contain'-

'flwswit adeth equal to ~or exceeding 40% oftenominjal tube wallth*ckness shall be plugged or repaired exceptif the flaws are permitted to remain in service througH applicati on of an alternate tube repajrcritertea discussed beow.

1 lubes shall be plugged iif the sleeved 'region of a tube i found by inser'vice inspection to contain flaws in the (a)

Isleeve or (b) the pressure boundary, portion of the origi"nal

'tb ali h sleeve/tube assembly, 1The following alternate tube repair criteria may be applied sa an alternatjive to -the 40%,depth based criteria:-

bbi.ci ranuliar Attack (IGA) indiciaion wmeans a bobbiný:coil indication Iconfirmed by Motorized Rotatingl tPancake Coil (MRPC) or other,qualified-inspection'

techniques,to have a volumetric'c, pit-like morph characteristic of IGA.

Inservice tubes with pit-like TIGA indications in the first span of the B OTSG,-

lidentified in the OTSG Inservice Inspection-Surveillance Procedure are acceptable to remiin service, provide*h e "indication is less than 40% -of the nominal tube wall thickness.1 (continued)

Crystal River Unit 3 5.0-14 Amendment No. XX

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals

!5.-6.2. 10 OTSG Program (continued~

'2.Tube End Cracks (TEC) are those crack-like edd9

__7_current i ndi catioQs, circumferentially and/or axiall]Y oriented, that are within the Inconel clad region 'of, the primary face of the upper and lower tubesheetsf

,but do not extend into the carbon steel-to Inconel Clad interface.

Tubes with axially oriented TEC

,be left in-service using the method described iný jTopical Report BAW-2346P, Revision 0, provided combined: projected leakage from all primary-to-.!

!secondary leakage, including axial TEC indicatioons, Reft in-service, does not exceed the Main Steam Li n~e 1

ýBreak (MSLB) accident leakage limit of one gallon per minute, minus 150 gallons per, day, per OTSG.

The' contribution to MSLB leakage rates from TEC' II ndications shall be determined utilizing the methodology in Addendum B dated August 10, 2005 to ropical Report BAW-2346P, Revision 0. The projection

,of TEC leakage that may develop during the nexJt!

Ipperating cycle shall be determined using the' methodology in Addendum C dated Augu Ist 30, 265'ol, Toprical Report BAW-2346,P., Revision 0.F Tdes-ice-niif9Fie~d wi-t~h TECTt~iaTI ýmeet~*t'IW al~tern~ate___

repair criteria will be added to the existing list of, 1tubes in the OTSG Inservice Inspection Surveillance Procedure.

The inspection data for tubes with axial'iV oriented TEC indications shall be compared to them previous inspection data to monitor the indicatjopjs hE_ g~rowth."

Tubes with crackl-ike i-ndications withi n the carb6on-

,steel portion of the,,tubesheet, circumferentially7,-

opriented TEC, or volumetric indications withinte IInconel clad region of the tubesheet shall be repaire-d

using the appropriate method from 5.6.2.10.f ot r removed from service by pl uggi ng the tube.

(continued)

Crystal River Unit 3 5.0-15 Amendment No. XX

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals 65*T721-ý0 OTSG Ptr oam (co-nti n--ued)]

s4Z17Pi6Vi sjhfcaKOTSGVtuhbe_ _i nspect~i67~.

rPeFi6_di,-OTSGC tuH.

inspections shall be performed.

The number and portions of fthe tubes inspected and methods of inspection shall be_

performed ~w~ith the objective of detecting flawvs of any'-ti-e 1(e.g., volumetric flaws, axia] and circumferential cracks)1 that may be present along the length of the tube, from th*

tube-to-tubesheet weld at the tube inlet to the tube-to--

rtubesheet weld at the tube outlet, and that may satisfy the I

applicable tube repair criteria.

The tube-to-tubesýýee

,weld is not part of the htube.

In tubes repaired by isleeving, t~he portion of the original tube wall betweenth lI.Teeve's jointsis~ not an area requi ring re-inspection._

rin

!addition to meeting the requirements of d.1 through d&8 below, the inspection scope, inspection methods, and nspection interal~yse sushal besuch as to ensure th at-oS Os -G I

tu be i ntegrity~ is mai ntai~ned until the next OTSG,

~Inspection.

An assessment of degradation shall li____

performed to determine ~the type) and location of flaws td, which the tube~s may be 4suscep~tible and,~ based on thi!5s--

6ssessment, to determine ~which inspectio n methods need~

bje epl__oyed and at what Ilocati6ns.J

. nsp-ec 710%

f~t-h tubes i-n a`7-OTSG during the ifirst refueling outage following OTSG replacement.

ZT Ihsýpec-t1-TO f -Tofhe tubes7at sequent a]

eoids of6 effective full power months.

The first sequentialL_

period shall be considered to begin after the first inservice inspection of the OTSGs.

No OTSG shall-ope~rate for more than 24 effectiv~e full power month,ý pr one refueling outage (whichever is less) without being inspected.

c.rack idicatins a Re'

' f7id' 6 -d -n*, 0 TS S"G itue, "the rthe next inspection for each OTSG for the degradationr mechanism that caused the crack indication shall not<

exceed 24 effe ctive full power months or one refueli'hig putage (whichever i~s less).'

If definiti ve

,information, such as from examination of aýiV5TiTed

'tube, diagnostic non-destructive testing, on engineering eval uation i ndi cates that at crack-7T1-i-ke

,indication is not associated with a crack(s),jthen JhIe cindication need not be treated as a crack.

(continued)

Crystal River Unit 3 5.0-16 Amendment No.

XX

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals 562.10 OTSG Program,:__(contin ued)j

-ser ttke IGA ipdi n

tions in f7jL ifirst span of the B OTSG, identified in the OTSQG Inservi ce,Inspection0 Su rveill ance Procedure must 'be inspected with tbobbi n and Motorized Rotat~i ng Pancaki e Foil (MRPC) eddy current techniques! from 'the lowerm__.

Itube sheet secondary face to the bottom of the first_

tube support plate during a* h i-nse-*

ce i

-spVc n d-f

,he B -0TSG.1 Inservice tubes with pit-like IGA indications inthe

ý"B" OTSG first span shall be monitored for growth of,__

,these indications ~b~y uinTga test probe eqiaetto

'the high frequency bobbin probe used in the 1997[

'inspection.

The indicated percentage through-wal*;l value from the current inspection shall be comp~ared to

,the indicated :percentage through-wall value from the 1997 inspection.

5. Tubes ini-service witfh axia iy o-riented tfibe end 'cracks (TEC) are identified in the OTSG Inservice InspectionH Surveillance Procedure.

The portion of the tube with' the axial TEC must be inspected using the motorized rotating ~coil eddy current technique every 24, pffective full power months or one refueling-outage_,J whichever is lesst.]

to-secondary leakage and the cause is determined to be',

degradation of the TEC portion of the tubes, 100% ofi the tub*es with TEC in t~hat OTSG shall be examine*d in the location of the TEC.

If more than 1% of the examined tubes satisfy the tube repair criteria,.100%

ojf the 'tubes with TEC in the other OIG§hjib) examined in the location of the TEC.

7.

The repair roll in each tube will be inspected every,

,24 effective full power months or one refueling outage I(whicheer is less) while the tube with a repair roll-lis in service.j

,8.If thie p6iant i s requi red to shuit, dowindii to prima~yi,,7 o-secondary leakage and the cause is determined to be degradation of a repair roll, 100% of the repair roll4 i~n t hat TSQs h~all be eamnnud.

(conti nued)

Crystal River Unit 3 5.0-17 Amendment No. XX

Procedures, Programs and Manuals 5.6

ý5 6' Proced-ur e-s,-, Program ~an,1n~s 5.2.O OTSG Ph-'rqriam '(conti-nu-e-d--)I 7Pro6visions fo-r monitoring operatioa prmary t6 se nd

~~LEAKAGE.

L3-7 7

_ProvT_1o6n~sfo~r -OT-SGtube repai r m-e-t ids.

Semgene ratorj tube repair methods shall provide the means to reestablisH r

he RCS pressure boundary integrity of QTSG tubes without removing the tube from service.

For the pu~rposes of thes Specifications, tub~e plugging is not a, repair.

Alli acceotable tube reroair methods are ]isted below.ý

1.

Sleeve 'insta))ation in accordance with theT B&W processl

ý(or method) described in report BAW-2120P.

No morer-_

Ithan five th~ousand sleeves may be installed in each

2. Installation of repair rolls in the upper and lower, 7tube sh'eets in accordance with BAW-2303P, 'Revision 4 IThe repair process (single, overlapping, or multlipl roll) may be performed in each'tube. The repair,rolli area will be examined using eddy-current methods following insta'llation.~ The repair roll m~ust be free of~ flaws for the repair to be considered accept'able.~

'If the repair~ roll is unacceptable, the tube must be k~ai red or plýug'ged.j (continued)

Amendment No. XX Crystal River Unit 3 5.0-18

Procedures, Programs and Manuals 5.6

~-Amm r

r C

'1 i-.--

__c

.N UIr L

I-.L -

L I

LI Ut I UL rreservice inspection-5 Number of OTSGs TWO First Inservice Inspection OfIe Second and Subsequent inser..v-

-Tnspeetionsy~e The '.nservice inspection may be limited to one OTSG

ý*Q*

n

-kn-I.l :1 an

^C *--

6

-n i-.-c-~ 4-C

%illr CA i

w.

"t taL I

.J.11:

uI tiI p

a tj i

ne rsu its of tene ti rst or previu

*nseecti ons indicate that both OTSGs are per i a like manner.

Note that under s ec umstances, the operating conditions in one OTSG may be found to be more severe than those in the other

,TSG. Under such cicustances the sample sequence shall be modified to inpet the most severe eondition~s.

Crystal River Unit 3 5.0-24 Amendment No. 1-4-9

Procedures, Programs and Manuals 5.6 I

^rc-

-rI 1l Tn flf'fk w.JIJ'j I

uLu

ý J1 "ý I ýWll 1st Sample inspeetion 2n~d Sample inspectiern f3rd Sample imspeetion 5Req+ee I Requi~f i~

__redul R-eqýred A minimum of

-tubes-per E)TFSG E-4 Nene N/'A N7/A N/A N-/A 4

4 4

4-Plug or deFeet+ve tubes-and

!-n~et an addi ti onal this= OTSG.

C-I None N/A N/A de Fee -

e 4S tubes r

this -eTSG--

None Plug or Perform C 3 result samp! e.~

E-3 Per-for E3

.re..t of-first N/A N/A 4

4 4

1

+

E-3 inspeet-all thi s-OTSG, repai-r Aefeeti e

+/-tubes, eaeh-other OTSG, and noti-fy-NRE p~er

!OEFR50.7 AI+/--othe-r OT5G~-a-re C-I Nome N/A N/A Some OTSGS Perform N/

N7/A C 2-but no ftc n-for additional E 2 restl* t*

OTSCs-a-re of-seeend C-3 sample.

Addi ti -n&-

OTSG is C 3 inspect-all tubes-i i, eaeh-OT-5GC7 plug or repair defeetive notfy-NREC I10CFR50.72.-

N/A N/A 1k

- ___ N i

f 3 N/n %

Where N is the number of O-Gs in the unit and n is the number of v,,SGs ispeeted during ispeetio, period.

Crystal River Unit 3 5.0-25 Amendment No. +-

Procedures, Programs and Manuals 5.6 "p

A I"I I r

P P

-- i

-*i

_r IPR)LL J.UL-J

.L

'C uI

.J.

L.A...=LI

=LN..

L=I'I=L I L.-L rI%-Ll-r

=LI1-..I L-.. I.LJII ist Sample inspe.tion of a Sample inspection of a "Speeifie Liited A "Spe.ifi Limited Area" SapeRsl etin ReutAetion 10096 of area E-4 Noel~

/

i n-both OTS~s Plug or N/A N/A defeeti e efeet*'

100% orf area rNone N/A N/A in one OTFSG__

SPlug or E-None efeetive tue n

-Z Pl ug or f:0e9-6 defeetive

_repnn

~tubery-E-3 Pug o E-4None repai-r defective

&2 lgo tutbes-and

~p-ihspeet-+O00 defectiv corresponding other OTSG.-rpr defeeti ve I

I I

Crystal River Unit 3 5.0-26 Amendment No.

18

Reporting Requirements 5.7 5.7 Reporting Requirements 5.7.1.2 Not Used 5.7.2 Special Reports Special Reports shall be submitted in accordance with 10 CFR 50.4 within the time period specified for each report.

The following Special Reports shall be submitted:

a.

When a Special Report is required by Condition B or F of LCO 3.3.17, "Post Accident Monitoring (PAM)

Instrumentation," a report shall be submitted within the following 14 days.

The report shall outline the preplanned alternate method of monitoring, the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the Function to OPERABLE status.

b.

Any abnormal degradation of the containment structure found during the inspection performed in accordance with ITS 5.6.2.8 shall be reported to the NRC within 30 days of the current surveillance completion.

The abnormal degradation shall be defined as findings such as delamination of the dome concrete, widespread corrosion of the liner plate, corrosion of prestressing elements (wires, strands, bars) or anchorage components extending to more than two tendons and group tendons force trends not meeting the requirements of 10CFR50.55a(b)(2)(ix)(B).

The report shall include the description of degradation, operability determination, root cause determination and the corrective actions.

"A report shal1 -be s,Nbmitted wit-h in 180 day-saft -er f-initial entry into MODE 4 following completion of aný iinspection performed in accordance with the Specification-5.6.2.10, Steam Genneratojr (OTSG)

Progiram The p

shall p1 ncl ude:J

,The scope of inspections,performed on each OTSG,J ILAct-ive diegraý,da-ti-oýn,ýmechanisms fowindQ1 Nondestructive examination techniques utilized for eacH

degrýadti on mechani sm_,j

14. -oca i-n,or t-F t -ai 6 f-Ii-near o

and" asu rýd:F-i zes9 L(if available) of service induced indications,7 (continued)

Crystal River Unit 3 5.0-28 Amendment No. 224

Reporting Requirements 5.7 5.7 Reporting Requirements 5.7.2 Special Reports (continued)

F5.

Nu'mber of tubes

_p ugged or re~pai redd~udr-ing 'theý 1inspection outage for each active degradationf mechari sin, nuTotalnumber and percentage of tubes lug' repaired to datej 7.V_ T res Sts f on t i -7mon i tori g, i iin 1-6 nl udgi ng-t Iresults of tube, pulls and in-situ testing_,-

[8 The-..e ffecpir-ve pT1u-ggng ercen e f itube repairs in each OTSG,j_

ý 9.~Repair metfhod utilizd>dth jmbrofiesrpjd by each repai r method,

e.

Following eaI h inser*

vieinspetion of steam generator prior to ascension into MODE 4a

1.

Number of tubes plugged and repaired;

2.

Crack like indications and assessment of growthfr indications in the first span; U3-Results of in situ pressure testing, if performed, and 4.--

Number of tubes and left insrie, the assessment of growth "II "'l I -

I -

V=1 5

-1 M.

"M pros prm Auj 1.7

~

LC v uLA

~

i etdaccidentl leakage, and an TEC ind*icNat-ions.

(continued)

Crystal River Unit 3 5.0-28 Amendment No. 2-2-2

Reporting Requirements 5.7 5.7 Reporting Rets 5.7.2 Special Reports (continued)

d. Results of OTSG tube inspections that fall into Category C 3 shall be reported to the NRC in accordance with IOCFR5O.72.

e. The complete results of the OTSG tube inservice inspection sna.IiE e s

,*umItUI ed to tne I

I,*,,

L wIU

, itnin Ju3L day aII er re a*

- ,er-closure following restart.

The report shall include:

1.

Number and extent of tubes inspected,

2.

Location and percent of wall thickness penetration for each indication of an imperfectiont,-.-I,=IILocation, bobbin coil amplitude, and axial and circumferential extent (if determined) for each first span IGA i ndi cati on, and FariV-a--s-s-essmen6hit of gr__6=tf

-j~

'indications in the first *span of OTSG B,_ and

4.

Identification of tubes plugged or repai red and specification of the repair methodology implemented for each-+/-tube. n:11.Number of as-found and as-left tubes with TEC indications, number of as-found and as-left TEC indications, the number of as-found and as-left TEC indications as a function of tubesheet radius, the as-found, as-left, probability of detection and new TEC leakage for upper and lower tubesheet indications. jT-h-

,projected accident leakage and an assessment of got~

1for TEC indications will be proie An assessment of the adequacy of the predictive methodology in Addendum C to Topical Report BAW-2346P, Revision 0, including assessing the distribution of indications found in each OTSG to ensure the assumption regarding the similarity of the distribution of indications remain consistent from one cycle to the next and that the assumption of a linear increase in leak rate remain valid. Corrective actions in the event that the assessment indicates the assumptions can not be fully supported.

Crystal River Unit 3 5.0-29 Amendment No. 22-1-2

PRORESS ENERGY FLORIDA, INC.

CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302 / LICENSE NUMBER DPR-72 LICENSE AMENDMENT REQUEST #264, REVISION 1 Application to Modify Improved Technical Specifications Regarding Steam Generator Tube Integrity ATTACHMENT D Proposed Improved Technical Specification Changes (Revision Bar Format)

TABLE OF CONTENTS 3.3 INSTRUMENTATION (continued) 3.3.11 Emergency Feedwater Initiation and Control (EFIC)

System Instrumentation.................

3.3-26 3.3.12 Emergency Feedwater Initiation and Control (EFIC)

Manual Initiation......................

3.3-30 3.3.13 Emergency Feedwater Initiation and Control (EFIC) Automatic Actuation Logic..............

3.3-32 3.3.14 Emergency Feedwater Initiation and Control (EFIC)-Emergency Feedwater (EFW) -Vector Valve Logic...................................

3.3-34 3.3.15 Reactor Building (RB)

Purge Isolation-High Radiation.....................................

3.3-35 3.3.16 Control Room Isolation-High Radiation...........

3.3-36 3.3.17 Post Accident Monitoring (PAM)

Instrumentation.. 3.3-38 3.3.18 Remote Shutdown System...........................

3.3-42 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4-1 3.4.1 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB)

Limits............

3.4-1 3.4.2 RCS Minimum Temperature for Criticality.........

3.4-3 3.4.3 RCS Pressure and Temperature (P/T) Limits.......

3.4-4 3.4.4 RCS Loops-MODE 3................................

3.4-6 3.4.5 RCS Loops-MODE 4................................

3.4-8 3.4.6 RCS Loops-MODE 5, Loops Filled..................

3.4-10 3.4.7 RCS Loops-MODE 5, Loops Not Filled..............

3.4-13 3.4.8 Pressurizer......................................

3.4-15 3.4.9 Pressurizer Safety Valves.......................

3.4-17 3.4.10 Pressurizer Power Operated Relief Valve (PORV)

.. 3.4-19 3.4.11 Low Temperature Overpressure Protection (LTOP)

System....................................

3.4-21 3.4.12 RCS Operational LEAKAGE..........................

3.4-22 3.4.13 RCS Pressure Isolation Valve (PIV)

Leakage......

3.4-24 3.4.14 RCS Leakage Detection Instrumentation...........

3.4-27 3.4.15 RCS Specific Activity............................

3.4-30 3.4.16 Steam Generator (OTSG)

Tube Integrity............

3.4-34 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5-1 3.5.1 Core Flood Tanks (CFTs)..........................

3.5-1 3.5.2 ECCS-Operating..................................

3.5-4 3.5.3 ECCS-Shutdown...................................

3.5-7 3.5.4 Borated Water Storage Tank (BWST) 3.5-9 3.6 CONTAINMENT SYSTEMS.................................

3.6-1 3.6.1 Containment......................................

3.6-1 3.6.2 Containment Air Locks............................

3.6-3 3.6.3 Containment Isolation Valves....................

3.6-8 3.6.4 Containment Pressure.............................

3.6-15 3.6.5 Containment Air Temperature.....................

3.6-16 (continued)

Crystal River Unit 3 i i Amendment No.

TABLE OF CONTENTS B 3.3 B 3.3.12 B 3.3.13 B 3.3.14 B 3.3.15 B

B B

3.3.16 3.3.17 3.3.18 B 3.4 B 3.4.1 INSTRUMENTATION (continued)

Emergency Feedwater Initiation and Control (EFIC) Manual Initiation....................

B 3.3-100 Emergency Feedwater Initiation and Control (EFIC) Automatic Actuation Logic............

B 3.3-105 Emergency Feedwater Initiation and Control (EFIC)-Emergency Feedwater (EFW)-Vector Valve Logic.................................

B 3.3-110 Reactor Building (RB)

Purge Isolation-High Radiation..................................

B 3.3-114 Control Room Isolation-High Radiation.........

B 3.3-119 Post Accident Monitoring (PAM)

Instrumentation B 3.3-124 Remote Shutdown System.........................

B 3.3-145 REACTOR COOLANT SYSTEM (RCS)

B 3.4-1 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB)

Limits...........

B 3.4-1 RCS Minimum Temperature for Criticality........

B 3.4-6 RCS Pressure and Temperature (P/T) Limits...... B 3.4-9 RCS Loops-MODE 3...............................

B 3.4-17 RCS Loops-MODE 4...............................

B 3.4-22 RCS Loops-MODE 5, Loops Filled.................

B 3.4-27 RCS Loops-MODE 5, Loops Not Filled.............

B 3.4-33 Pressurizer.....................................

B 3.4-37 Pressurizer Safety Valves......................

B 3.4-43 Pressurizer Power Operated Relief Valve (PORV)

.B 3.4-47 Low Temperature Overpressure Protection (LTOP)

System...................................

B 3.4-52 RCS Operational LEAKAGE.........................

B 3.4-53 RCS Pressure Isolation Valve (PIV)

Leakage..... B 3.4-58 RCS Leakage Detection Instrumentation..........

B 3.4-65 RCS Specific Activity...........................

B 3.4-71 Steam Generator (OTSG)

Tube Integrity...........

B 3.4-75 3.4.2 3.4.3 3.4.4 3.4.5 3.4.6 3.4.7 3.4.8 3.4.9 3.4. 10 3.4.11 3.4.12 3.4.13 3.4.14 3.4.15 3.4.16 3.5 3.5.1 3.5.2 3.5.3 3.5.4 3.6 3.6.1 3.6.2 3.6.3 3.6.4 3.6.5 3.6.6 EMERGENCY CORE COOLING SYSTEMS (ECCS)

B Core Flood Tanks (CFTs).........................

B ECCS-Operating.................................

B ECCS-Shutdown..................................

B Borated Water Storage Tank (BWST)

B 3.5-1 3.5-1 3.5-9 3.5-20 3.5-24 CONTAINMENT SYSTEMS................................

B 3.6-1 Containment.....................................

B 3.6-1 Containment Air Locks...........................

B 3.6-6 Containment Isolation Valves...................

B 3.6-15 Containment Pressure............................

B 3.6-29 Containment Air Temperature...................

B 3.6-32 Reactor Building Spray and Containment Cooling Systems..............................

B 3.6-35 (continued)

Crystal River Unit 3 vi Amendment No.

Definitions 1.1 1.1 Definitions LEAKAGE (continued)

3. Reactor Coolant System (RCS)

LEAKAGE through a steam generator to the secondary system (primary to secondary LEAKAGE).

b.

Unidentified LEAKAGE All LEAKAGE that is not identified LEAKAGE.

c.

Pressure Boundary LEAKAGE MODE NUCLEAR HEAT FLUX HOT CHANNEL FACTOR (FQ(Z))

NUCLEAR ENTHALPY RISE HOT CHANNEL FACTOR (FVH)

OPERABLE-OPERABILITY PHYSICS TESTS LEAKAGE (except primary to secondary LEAKAGE) through a non-isolable fault in an RCS component body, pipe wall, or vessel wall.

A MODE shall correspond to any one inclusive combination of core reactivity condition, power

level, average reactor coolant temperature, and reactor vessel head closure bolt tensioning specified in Table 1.1-1.

FQ(Z) shall be the maximum local linear power density in the core divided by the core average fuel rod linear power density, assuming nominal fuel pellet and fuel rod dimensions.

FNH shall be the ratio of the integral of linear power along the fuel rod on which minimum departure from nucleate boiling ratio occurs to the average fuel rod power.

A system, subsystem, train, component, or device shall be OPERABLE when it is capable of performing its specified safety function(s) and when all necessary attendant instrumentation, controls, normal or emergency electrical power, cooling and seal water, lubrication and other auxiliary equipment that are required for the system, subsystem, train, component, or device to perform its specified safety function(s) are also capable of performing their related support function(s).

PHYSICS TESTS shall be those tests performed to measure the fundamental nuclear characteristics of the reactor core and related instrumentation.

(continued)

Crystal River Unit 3 1.1-5 Amendment No.

RCS Operational LEAKAGE 3.4.12 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.12 RCS Operational LEAKAGE LCO 3.4.12 RCS operational LEAKAGE shall be limited to:

a.

No pressure boundary LEAKAGE;

b.

1 gpm unidentified LEAKAGE;

c.

10 gpm identified LEAKAGE; and

d.

150 gpd of primary to secondary through any one steam generator LEAKAGE (OTSG).

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

RCS operational A.1 Reduce LEAKAGE to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months LEAKAGE not within within limits.

limits for reasons other than pressure boundary LEAKAGE or primary to secondary LEAKAGE.

B.

Required Action and B.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met.

AND OR B.2 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Pressure boundary LEAKAGE exists.

OR Primary to secondary LEAKAGE not within limit.

Crystal River Unit 3 3.4-22 Amendment No.

RCS Operational LEAKAGE 3.4.12 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.12.1 NOTES----------------------

1. Not required to be performed in MODE 4.

Not required in MODE 3 until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of steady state operation.

2. Not applicable to primary to secondary LEAKAGE.

Verify RCS operational LEAKAGE is within limits by performance of RCS water inventory balance.

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months SR 3.4.12.2 ---------------

NOTE-----------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation.

Verify primary to secondary LEAKAGE is

< 150 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months gallons per day through any one steam generator.

Crystal River Unit 3 3.4-23 Amendment No.

OTSG Tube Integrity 3.4.16 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.16 Steam Generator (OTSG)

Tube Integrity LCO 3.4.16 OTSG tube integrity shall be maintained.

AND All OTSG tubes satisfying the tube repair criteria shall be plugged or repaired in accordance with the Steam Generator Program.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS

NOTE--------------------------------

Separate Condition entry is allowed for each OTSG tube.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more OTSG A.1 Verify tube integrity 7 days tubes satisfying the of the affected tube repair criteria tube(s) is maintained and not plugged or until the next repaired in refueling outage or accordance with the OTSG tube inspection.

Steam Generator Program.

AND A.2 Plug or repair the Prior to entering affected tube(s) in MODE 4 following accordance with the the next refueling Steam Generator outage or OTSG Program.

tube inspection B. Required Action and B.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A AND not met.

B.2 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months OR OTSG tube integrity not maintained.

Crystal River Unit 3 3.4-34 Amendment No'.

OTSG Tube Integrity 3.4.16 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.16.1 Verify OTSG tube integrity in accordance In accordance with with the Steam Generator Program.

the Steam Generator Program SR 3.4.16.2 Verify that each inspected OTSG tube that Prior to entering satisfies the tube repair criteria is MODE 4 following a plugged or repaired in accordance with the OTSG tube Steam Generator Program.

inspection Crystal River Unit 3 3.4-35 Amendment No.

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals 5.6.2.10 Steam Generator (OTSG)

Program A Steam Generator Program shall be established and implemented to ensure that OTSG tube integrity is maintained.

In addition, the Steam Generator Program shall include the following provisions:

a.

Provisions for condition monitoring assessments.

Condition monitoring assessment means an evaluation of the "as found" condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage.

The "as found" condition refers to the condition of the tubing during an OTSG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging or repair of tubes.

Condition monitoring assessments shall be conducted during each outage during which the OTSG tubes are inspected, plugged, or repaired to confirm that the performance criteria are being met.

b.

Performance criteria for OTSG tube integrity.

OTSG tube integrity shall be maintained by meeting the performance criteria for tube structural integrity, accident induced leakage, and operational LEAKAGE.

1.

Structural integrity performance criterion:

All in-service steam generator tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, and cool down and all anticipated transients included in the design specification) and design basis accidents.

This includes retaining a safety factor of 3.0 against burst under normal steady state full power operation primary-to-secondary pressure differential and a safety factor of 1.4 against burst applied to the design basis accident primary-to-secondary pressure differentials.

Apart from the above requirements, additional loading conditions associated with the design basis accidents, or combination of accidents in accordance with the design and licensing basis, shall also be evaluated to determine if the associated loads contribute significantly to burst or collapse.

In the assessment of tube integrity, those loads that do significantly affect burst or collapse shall be determined and assessed in combination with the loads due to pressure with a safety factor of 1.2 on the combined primary loads and 1.0 on axial secondary loads.

(continued)

Crystal River Unit 3 5.0-13 Amendment No.

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals 5.6.2.10 OTSG Program (continued)

2.

Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than an OTSG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all OTSGs and leakage rate for an individual OTSG.

Leakage is not to exceed one gallon per minute per OTSG.

3.

The operational LEAKAGE performance criterion is specified in LCO 3.4.12, "RCS Operational LEAKAGE."

c.

Provisions for OTSG tube repair criteria.

The non-sleeved region of a tube found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged or repaired except if the flaws are permitted to remain in service through application of an alternate tube repair criteria discussed below.

Tubes shall be plugged if the sleeved region of a tube is found by inservice inspection to contain flaws in the (a) sleeve or (b) the pressure boundary portion of the original tube wall in the sleeve/tube assembly.

The following alternate tube repair criteria may be applied as an alternative to the 40% depth based criteria:

1.

Pit-like Intergranular Attack (IGA) indication means a bobbin coil indication confirmed by Motorized Rotating Pancake Coil (MRPC) or other qualified inspection techniques to have a volumetric, pit-like morphology characteristic of IGA.

Inservice tubes with pit-like IGA indications in the first span of the B OTSG, identified in the OTSG Inservice Inspection Surveillance Procedure are acceptable to remain in service provided the indication is less than 40% of the nominal tube wall thickness.

(continued)

Crystal River Unit 3 5.0-14 Amendment No.

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals 5.6.2.10 OTSG Program (continued)

2.

Tube End Cracks (TEC) are those crack-like eddy current indications, circumferentially and/or axially oriented, that are within the Inconel clad region of the primary face of the upper and lower tubesheets, but do not extend into the carbon steel-to Inconel clad interface.

Tubes with axially oriented TEC may be left in-service using the method described in Topical Report BAW-2346P, Revision 0, provided the combined projected leakage from all primary-to-secondary leakage, including axial TEC indications left in-service, does not exceed the Main Steam Line Break (MSLB) accident leakage limit of one gallon per minute, minus 150 gallons per day, per OTSG.

The contribution to MSLB leakage rates from TEC indications shall be determined utilizing the methodology in Addendum B dated August 10, 2005 to Topical Report BAW-2346P, Revision 0. The projection of TEC leakage that may develop during the next operating cycle shall be determined using the methodology in Addendum C dated August 30, 2005 to Topical Report BAW-2346P, Revision 0.

Tubes identified with TEC that meet the alternate repair criteria will be added to the existing list of tubes in the OTSG Inservice Inspection Surveillance Procedure.

The inspection data for tubes with axially oriented TEC indications shall be compared to the previous inspection data to monitor the indications for growth.

Tubes with crack-like indications within the carbon steel portion of the tubesheet, circumferentially oriented TEC, or volumetric indications within the Inconel clad region of the tubesheet shall be repaired using the appropriate method from 5.6.2.10.f or removed from service by plugging the tube.

(continued)

Crystal River Unit 3 5.0-15 Amendment No.

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals 5.6.2.10 OTSG Program (continued)

d.

Provisions for OTSG tube inspections.

Periodic OTSG tube inspections shall be performed.

The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable tube repair criteria.

The tube-to-tubesheet weld is not part of the tube.

In tubes repaired by sleeving, the portion of the original tube wall between the sleeve's joints is not an area requiring re-inspection.

In addition to meeting the requirements of d.1 through d.8 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that OTSG tube integrity is maintained until the next OTSG inspection.

An assessment of degradation shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.

1.

Inspect 100% of the tubes in each OTSG during the first refueling outage following OTSG replacement.

2.

Inspect 100% of the tubes at sequential periods of 60 effective full power months.

The first sequential period shall be considered to begin after the first inservice inspection of the OTSGs.

No 0TSG shall operate for more than 24 effective full power months or one refueling outage (whichever is less) without being inspected.

3.

If crack indications are found in any OTSG tube, then the next inspection for each OTSG for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever is less).

If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.

(continued)

Crystal River Unit 3 5.0-16 Amendment No.

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals 5.6.2.10 OTSG Program (continued)

4.

Inservice tubes with pit-like IGA indications in the first span of the B OTSG, identified in the OTSG Inservice Inspection Surveillance Procedure must be inspected with bobbin and Motorized Rotating Pancake Coil (MRPC) eddy current techniques from the lower tube sheet secondary face to the bottom of the first tube support plate during each inservice inspection of the B OTSG.

Inservice tubes with pit-like IGA indications in the "B" OTSG first span shall be monitored for growth of these indications by using a test probe equivalent to the high frequency bobbin probe used in the 1997 inspection.

The indicated percentage through-wall value from the current inspection shall be compared to the indicated percentage through-wall value from the 1997 inspection.

5.

Tubes in-service with axially oriented tube end cracks (TEC) are identified in the OTSG Inservice Inspection Surveillance Procedure.

The portion of the tube with the axial TEC must be inspected using the motorized rotating coil eddy current technique every 24 effective full power months or one refueling outage, whichever is less.

6.

If the plant is required to shut down due to primary-to-secondary leakage and the cause is determined to be degradation of the TEC portion of the tubes, 100% of the tubes with TEC in that OTSG shall be examined in the location of the TEC.

If more than 1% of the examined tubes satisfy the tube repair criteria, 100% of the tubes with TEC in the other OTSG shall be examined in the location of the TEC.

7.

The repair roll in each tube will be inspected every 24 effective full power months or one refueling outage (whichever is less) while the tube with a repair roll is in service.

8.

If the plant is required to shut down due to primary-to-secondary leakage and the cause is determined to be degradation of a repair roll, 100% of the repair rolls in that OTSG shall be examined.

(conti nued)

Crystal River Unit 3 5.0-17 Amendment No.

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals 5.6.2.10 OTSG Program (continued)

e.

Provisions for monitoring operational primary to secondary LEAKAGE.

f.

Provisions for OTSG tube repair methods.

Steam generator tube repair methods shall provide the means to reestablish the RCS pressure boundary integrity of OTSG tubes without removing the tube from service.

For the purposes of these Specifications, tube plugging is not a repair.

All acceptable tube repair methods are listed below.

1.

Sleeve installation in accordance with the B&W process (or method) described in report BAW-2120P.

No more than five thousand sleeves may be installed in each OTSG.

2.

Installation of repair rolls in the upper and lower tubesheets in accordance with BAW-2303P, Revision 4.

The repair process (single, overlapping, or multiple roll) may be performed in each tube.

The repair roll area will be examined using eddy-current methods following installation.

The repair roll must be free of flaws for the repair to be considered acceptable.

If the repair roll is unacceptable, the tube must be repaired or plugged.

(continued)

Crystal River Unit 3 5.0-18 Amendment No.

Procedures, Programs and Manuals 5.6 THIS PAGE INTENTIONALLY LEFT BLANK Crystal River Unit 3 5.0-24 Amendment No.

Procedures, Programs and Manuals 5.6 THIS PAGE INTENTIONALLY LEFT BLANK Crystal River Unit 3 5.0-25 Amendment No.

Procedures, Programs and Manuals 5.6 THIS PAGE INTENTIONALLY LEFT BLANK Crystal River Unit 3 5.0-26 Amendment No.

Reporting Requirements 5.7 5.7 Reporting Requirements 5.7.1.2 Not Used 5.7.2 Special Reports Special Reports shall be submitted in accordance with 10 CFR 50.4 within the time period specified for each report.

The following Special Reports shall be submitted:

a.

When a Special Report is required by Condition B or F of LCO 3.3.17, "Post Accident Monitoring (PAM)

Instrumentation," a report shall be submitted within the following 14 days.

The report shall outline the preplanned alternate method of monitoring, the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the Function to OPERABLE status.

b.

Any abnormal degradation of the containment structure found during the inspection performed in accordance with ITS 5.6.2.8 shall be reported to the NRC within 30 days of the current surveillance completion.

The abnormal degradation shall be defined as findings such as delamination of the dome concrete, widespread corrosion of the liner plate, corrosion of prestressing elements (wires, strands, bars) or anchorage components extending to more than two tendons and group tendons force trends not meeting the requirements of 10CFR50.55a(b)(2)(ix)(B).

The report shall include the description of degradation, operability determination, root cause determination and the corrective actions.

c.

A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5.6.2.10, Steam Generator (OTSG)

Program.

The report shall include:

1.

The scope of inspections performed on each OTSG,

2.

Active degradation mechanisms found,

3.

Nondestructive examination techniques utilized for each degradation mechanism,

4.

Location, orientation (if linear), and measured sizes (if available) of service induced indications, (continued)

Crystal River Unit 3 5.0-28 Amendment No.

Reporting Requirements 5.7 5.7 Reporting Requirements 5.7.2 Special Reports (continued)

5.

Number of tubes plugged or repaired during the inspection outage for each active degradation mechanism,

6.

Total number and percentage of tubes plugged or repaired to date,

7.

The results of condition monitoring, including the results of tube pulls and in-situ testing,

8.

The effective plugging percentage for all plugging and tube repairs in each OTSG,

9.

Repair method utilized and the number of tubes repaired by each repair method,

10.

Location, bobbin coil amplitude, and axial and circumferential extent (if determined) for each first span IGA indication, and an assessment of growth for indications in the first span of OTSG B, and

11.

Number of as-found and as-left tubes with TEC indications, number of as-found and as-left TEC indications, the number of as-found and as-left TEC indications as a function of tubesheet radius, the as-found, as-left, probability of detection and new TEC leakage for upper and lower tubesheet indications. The projected accident leakage and an assessment of growth for TEC indications will be provided.

An assessment of the adequacy of the predictive methodology in Addendum C to Topical Report BAW-2346P, Revision 0, including assessing the distribution of indications found in each OTSG to ensure the assumption regarding the similarity of the distribution of indications remain consistent from one cycle to the next and that the assumption of a linear increase in leak rate remain valid.

Corrective actions in the event that the assessment indicates the assumptions can not be fully supported.

Crystal River Unit 3 5.0-29 Amendment No.

PRORESS ENERGY FLORIDA, INC.

CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302 / LICENSE NUMBER DPR-72 LICENSE AMENDMENT REQUEST #264, REVISION 1 Application to Modify Improved Technical Specifications Regarding Steam Generator Tube Integrity ATTACHMENT E Proposed Improved Technical Specification Bases Pages (Mark-up)

SiPkeeut-4e*t Indicates deleted text.

Highlightedit indicates added text.

RCS Operational LEAKAGE B 3.4.12 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.12 RCS Operational LEAKAGE BASES BACKGROUND During the life of the plant, the joint and valve interfaces contained in the RCS can produce varying amounts of reactor coolant LEAKAGE, through either normal operational wear or mechanical deterioration.

The purpose of the RCS Operational LEAKAGE LCO is to limit system operation in the presence of LEAKAGE from these sources to amounts that do not compromise safety.

This LCO specifies the types and amounts of LEAKAGE.

10 CFR 50, Appendix A, GDC 30 (Ref. 1), requires means for detecting and, to the extent practical, identifying the source of reactor coolant LEAKAGE.

Regulatory Guide 1.45 (Ref.

2) describes acceptable methods for selecting leakage detection systems.

OPERABILITY of the leakage detection systems is addressed in LCO 3.4.14, "RCS Leakage Detection Inst rumentati on."

The safety significance of RCS LEAKAGE varies widely depending on its source, rate, and duration.

Therefore, detecting, monitoring, and quantifying reactor coolant LEAKAGE is critical.

Quickly separating the identified LEAKAGE from the unidentified LEAKAGE is necessary to provide quantitative information to the operators, allowing them to take corrective action should a leak occur.

A limited amount of leakage inside containment is expected from auxiliary systems that cannot be made 100% leaktight.

Leakage from these systems should be detected, located, and isolated from the containment atmosphere, if possible, to not interfere with RCS leakage detection.

APPLICABLE SAFETY ANALYSES Except for primary to secondary LEAKAGE, the safety analyses do not address operational LEAKAGE.

However, other operational LEAKAGE is related to the safety analyses for a LOCA in that the amount of leakage can affect the probability of such an event.

The safety analysis for an event resulting in steam discharge to the atmosphere assumes 1 gpm primar.y tc seeondary LEAKAGE ars the initial eondition.

(continued)

Crystal River Unit 3 B 3.4-53 Revision No. +0

RCS Operational LEAKAGE B 3.4.12 BASES APPLICABLE hat primary to secondary LEAKAGE fromall:steam generatorl SAFETY ANALYSES f(OTSGs) is one gallon per minute or increases to one gallon' (continued) per minute as a result of accident induced conditions. The LCO *requi rement to 1 limi t pri mary to secondary LEAKAGE through any one OTSG to less han or equal to 150gailns per day is*significantly less than the conditi ons assumed in the safety analysis.!

The FSAR (Ref.

3) analysis for steam generator tube rupture (SGTR) assumes the contaminated secondary fluid is only briefly released via safety valves and the majority is steamed to the condenser.

The 1 gpm primary to secondary LEAKAGE f-ety*analysi--s assumptiVo is relatively inconsequential in terms of offsite dose.

The safety analysis for the Steam Line Break (SLB) accident assumes th'e et-iF 1 gpm primary to secondary LEAKAGE +fn one is through theaffe,(1/2 generator as an initial condition (Ref.

4).

The dose consequences resulting from the SLB accident meet the acceptance criteria defined in 10 CFR 50.67.

RCS operational LEAKAGE satisfies Criterion 2 of the NRC Policy Statement.

LCO RCS operational LEAKAGE shall be limited to:

a.

Pressure Boundary LEAKAGE No pressure boundary LEAKAGE is allowed, being indicative of material deterioration.

LEAKAGE of this type is unacceptable as the leak itself could cause further deterioration, resulting in higher LEAKAGE.

Violation of this LCO could result in continued degradation of the reactor coolant pressure boundary (RCPB).

LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

b.

Unidentified LEAKAGE One gallon per minute (gpm) of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the containment atmosphere and sump level monitoring equipment can detect within a reasonable time period.

Violation of this LCO could result in continued degradation of the RCPB, if the LEAKAGE is from the pressure boundary.

(continued)

Crystal River Unit 3 B 3.4-54 Revision No. 7

RCS Operational LEAKAGE B 3.4.12 BASES LCO

c.

Identified LEAKAGE Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with the detection of unidentified LEAKAGE and is well within the capability of the RCS makeup system.

Identified LEAKAGE includes LEAKAGE to the containment from specifically known and located sources, but does not include pressure boundary LEAKAGE or controlled reactor coolant pump (RCP) seal leakoff (a normal function not considered LEAKAGE).

Violation of this LCO could result in continued degradation of a component or system.

d.

Pri marv t uo S-u,,d, y

L-nEAnAG-through

An,,^-' Lin--

Steam This LEAKAGE limit is established to ensure that tube initially laigdr ngora operation do not contribute exessvl tottllekg luring postulated acietcniin.The 150 gpd! limit is acnservative limit which is consistent with the operational leakag lm i spcfied in NRC Generict Letter 95 05 fir plats,mplementing Alternate Repr Criter-iaI.

R--

11has*

eeted to voluntarily adopt thIS conservative limit to ensure plant shutdown in, timely manner in respnse to detection of primary t secondary LEAKAGE rmary to secondary LEAKAGE mut be included in the talallowable limitfr identified LEAKAGE.

Two OTSGs are also required to be OPERABLE. This requi rment IU s mt!bysti f te mented inservice inspection requirements of the Steam Generator Tube Surveillance Proga (Sp eiiation

.d PHiar "t6-oS econdaY EKE -thEhh r-An5*h-ne O TSG The--l-ii-i-ftof-1:5-O -al-ons per day per FOTSG--s--bas-ed--n

,the operational LEAKAGE performance criterion in NEI, j97-06, Steam Generator Program Guidelines (Ref.

5').F The, Steam Generator Program operati onal LEAKAGE performance criterion in NEI 97-06s tates, "The RC%,

pperational primary to secondary leakage through anyL one SG shall be limited to 150 gallons per day."

The flimit is based on operating experience with OTSG tube

'degradation mechanisms that result intube leakage.,

fheT operational e eakage rate crite*rion in conj uncti*on with the implementation of the Steam Generator Programs is an effective measure for minimizing the frequency of steam generator tube ruptures..

L(rtntionued)N Crystal River Unit 3 B 3.4-55 Revision No. 5.4

RCS Operational LEAKAGE B 3.4.12 BASES ACTIONS A.1 If unidentified LEAKAGE-B identified LEAKAGE, or primary to se.ondary LEAKAGE Care in excess of the LCO limits, the LEAKAGE must be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

This Completion Time allows time to verify leakage rates and either identify unidentified LEAKAGE or reduce LEAKAGE to within limits before the reactor must be shut down.

This action is necessary to prevent further deterioration of the RCPB.

B.1 and B.2 If any pressure boundary LEAKAGE exists rprimary FseconJaryLEAKAGEis n6t, withi*n imits!, or if unidentified-identified, or primary to secondary LEAKAGE cannot be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , the reactor must be placed in a lower pressure condition to reduce the severity of the LEAKAGE and its potential consequences.

The reactor must be placed in MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

This action reduces the LEAKAGE and also reduces the stresses that tend to degrade the pressure boundary.

The Completion Times allowed are reasonable, based on operating experience, to reach the required conditions from full power conditions in an orderly manner and without challenging plant systems.

In MODE 5, the pressure stresses acting on the RCPB are much lower and further deterioration is much less likely.

SURVEILLANCE SR 3.4.12.1 REQUIREMENTS Verifying RCS LEAKAGE within the LCO limits ensures that the integrity of the RCPB is maintained.

Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection.

Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance.

Prima-ry to secondary LEAKAGE is also measured by performance of an RCS waterinVentory balance in conjunction with effluent monitoring within the secondary steam and condensate sys-tems.

FKc-n t i n ueýd)j CrytaIRve U

it3I 3i

-I

.4 UICI.

-tCLI 56 Rev-,.

is..

on No.-1 Crystal River Unit 3 B 3.4-56 Revision No. 0

RCS Operational LEAKAGE B 3.4.12 BASES SURVEILLANCE SR 3.4.12.1 (continued)

REQUIREMENTS The RCS water inventory balance must be performed with the reactor at steady state operating conditions and with RCS temperature greater than 400 0 F.

The test must be performed prior to entry into MODE 2 if it has not been performed within the past 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months near normal operating pressure.

This surveillance is modified by two notes.

Note 1 states Khat it is not required to be performed for entry into MODE 4 er-MODE-3 or for non-steady state conditions in MODE 3, but must be performed in MODE 3 above 400'F if 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of steady state operation are achieved.

If the test is not performed prior to all other requirements for entry into MODE 2 being satisfied, entry into MODE 2 must be delayed until steady state operation is established and the requirements of SR 3.0.4 are satisfied.

Steady state operation is required to perform a meaningful water inventory balance; calculations during maneuvering are not useful.

For RCS operational LEAKAGE determination by water inventory balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP pump seal injection and return flows.

'Note 2 states that this SR is not applicable to primary t, secondary LEAKAGE because LEAKAGE of 150 gallons per da cannot be measured accurately by Ian RCS water inventor bal ance i The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Frequency is reasonable to trend LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents.

SR 3.4.12.2 This SR provides the means necessary to determine OTS.G O,*RABILITY in an pri, al MOD[.

The requirement to demonstrate OTSG tube integritHy in accordance with the Steam Generator Tube Surveillance-rrgamephasizes the imorane of )T-SG tube integrit.y, even though this Scurveillance cannot be performed at normal operating condi ti ons.

(conti nued)

Crystal River Unit 3 B 3.4-57 Revision No. 0

RCS Operational LEAKAGE B 3.4.12 BASES SURVEILLANCE SR 3.4.12.2 (continued)j REQUIREMENTS 1T Thiis-SR verifTie6s that~p-rimary' to-seco6n-dary LEAKAGE is-les-s

,than or equal to 150 gallons per day through any one OTSGý.

,Satisfying the primary to secondary LEAKAGE limit ensures that the operational LEAKAGE performance criterion in the Steam Generator Program is met.

-If this SR is not met,]

1compance with* LCO 3.4.16, "Steam Generator Tube,

.nteg r ty, "

should be evaluated.

The 150

,gall 6ns° pe:i*:

limit is mneasured at room temperature as described in' Reference 6.

The. operational LEAKAGE rate limit appV[esYt LEAKAGE through any one OTSG.

If it is not practical to-,

assign the LEAKAGE to an individual OTSG, all the pr~irarYL-16 se~condary LEAKAGE~ should be con se rvat i vely a~ssumed to be The Surveillance is modified by a Note which states thatý ithe Surveillance is not required to be performed until, i2 hours after establishment of steady state operation.

Fon

-CS pri.ma.ry toseco. ary LEAK GE determination, steady!

mstate is defined as stable RCS pressure, temperature, _powe Ilevel, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.*

The Surveillance Frequency of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is a reasonabl-F n

terval to tren~d primary to secondary LEAKA~GE'a~

recognizes the importance of early leakage detectio n t eiY prevention of accidents.

The primary to secondary LEAKAGEV iis determined using continuous process radiation monitorsE or radiochemical grab sampling in accordance with the EPRI' udelines (Ref., 6).j REFERENCES

1.

10 CFR 50, Appendix A, GDC 30.

2.

Regulatory Guide 1.45, May 1973.

3.

FSAR, Section 14.2.2.2.

4.

FSAR, Section 14.2.2.1.

{5 NEI 97-06, "Steam Generator Program Guidelines.

RkI

'"P-re"s-sur zi~ed

-Water7R e'a-`tor P-r i maryToýc-SondarjiF

ýLeak Guidelines."

Crystal River Unit 3 B 3.4-58 Revision Amendment No. 9

QTSG Tube Intlelgritf9 B 3.

4.

16 R3.

REACTOR COOLANT SYSTEM (RC:S)]

B*3.4*16 Steam Gene rator (OTS-SGTube Integrite BACKGROUND Steam generator (OTSG) tubes are smaiame thrnih walled tubes ;t'that carry primary coolant through the primary to secondary heat exchanges.

The OTSG tubes have a numbe*

of impor tant safety functions.

Steam generator tubes are an integ'ral part of the reactor coolant pressure boundary,'

(RCPB) -and, as s'such, 'are relied on to maintain the primary

.system's pressure and inventory. The OTSG. tubes isolate the radioactive fission, products in the primary coolant from: t he secondar y s system.

In addition, as part of the

RCPB, the OTSG tubes are--unique in that they act as the

!heat transfer surface between the primary and secondary, Isystems to remove heat' from the primary system.

This'*

_hi

!Specification addresses only the RCPB integrity funct*ion-of Ithe OTSG.

The OTSG heat removal function is addressed b **y ILCO 3.4.4, "RCS Loops MODE 3," LCO 3.4.5, "RCS Loops MODE, 4," LCO 3.4.6, "RCS Loops -

MODE 5, Loops Filled," and

[is implicitly requiqred in MODES 1 and 2 in order to prevent

'aReactor Protecti~on, St.....;yst emactuation ((LCO 3.3..1),!

OTSG tube integrity means that the tubes are capbeofL performing their intended RCPB safety function consistenit I with the licensing basivs, including applicable u

regVatory

[requ Orements.

~t~~~genratr tuingIs sbjeto ta variety of

'degradation mechanisms.

Steam generator tubes may

'experience tube degradation related to corrosion phenom~ena.

~such as wastage, pitting, intergranular' att~ack, and stress, corrosion cracking, along with other mechanically induced phenomena such as denting" and wear.

Thesedegraidation" miechanisms, can impair tube integrity if they are not managed effect'ively.,

The OTSG performance criteria are'

.used, to manage OTSG tube degradatin.

,Specificat---ion 5.6.2.10, "Steam Generator (OTSG)- P-roramOil requires that a program be established, and implemented to.

ensure that OTSG tube integrity'is maintained.

Pursuant to Specification 5.6.2.10, tube integrity is maintained when=

the OTSG performance criteria are met.

There are three OTSG performance criteria: structural integrity, accideii, induced leakage--,

and operational LEAKAGE.

The OTSG' (continued)

Crystal River Unit 3 B 3.4-75 Revision No. XX

)TSG Tube Integrity, B 13 4.16 BASES BACKGRQUND

' per-rman c riter-i a eare descr ind n.. p iicat

_on-

~coninud).6.210.-- eetng the OTSG performance criteria provides Ireasonable assurance of maintaining tube integrity a

normal and accident conditions.

The processes s nedtdo-meet the OTSG performance criteri7 are defi ned by-_the__5_teami Generator Program. Gu~ideli nes, j Ref. 1).

APPLICABLE T e steam generator tub rd1 t

SAFETY ANALYSES limiting design basi~s event ~for-OTSG tubes and avoidting an

.SGTR.

is the basi.s for this Specification.

The analysi]s, o 1aSGTR event assumes; a bound ing primary to secon ar-d iLEAKAGE rate equal to the erational LEAKAGE rate limiTs in LCO 3.4.12, "RCS Operational LEAKAGE,"

plus the leakage rate associated with a double-ended rupture of a sin.gije tube. The accident analysis for a SGTR,assumes the contami nated secondary f ui di is only y briefl y rel eased-to 1the atmosphere via safety valves and the majorityj S

i'scharged to the main condenser.

, e-janal-ysfis for sdign s acs.

d

...ents

'other than a SGTR assume the OTSG tubes retain their sst~ructural integrit ty (i.'e, they are assumed not to rupture).

In-these analyses, the steam discharge to the latmosphere is based on the total primary to secondary LEALAKGE,from -alt 0TSGs of one gallon per minute or is assumed to increase to one gallon per minute as a, resulYt6'of accident induced conditions.

For accidents that do-nolt involve fuel damage, the primary coolant activity level-ofi DOSE EQUIVALENT 1-131 is assumed to be equal to the LCO 13.4.15, ",RCS Specific Activity," limits.-For accidents, ithatassuflie fuel damage, the primary coolant activity a*v functionof the amount of activi~ty released from the'

'damaged fuel.

The dose consequences of these events are_

,within the limits of GDC 19 (Ref.

2),

10 CFR 50.67 (Ref.

3) or the NRC approved licensing bases (e.g_,_

a small fraction

'of theselmts

,St:Eam generator tuFbe ifte-rity Cri teIrion2o-f-,

IcýFR 50.36(_c)(2_)(ii--jr LC ~

~

h C req~u res that OTSG tu Th-C--

ibeý I:1Etegjr-itfy b e- --ma-intained.

he LCO alsoi equires that all OTSG tubes that satisfy the repair criteria be plugged or repaired in accordance withý-

ithe Steam Generator Program.

(continued)

Crystal River Unit 3 B 3.4-76 Revision No.

XX

ýTSG Tube Integrity

!B 3. 4. 16 BASES CO During an OTSG inspection, any inspectedtube---thFa--*

(continued) satisfies the Steam Generato r Programrepai r cri-te a iT

ýrepajired or r~emoved fr'om service :by plu~ggin~g.~ If a tube Was determined t satisfy the repair criteria but was not

!plugged or repairedd, the tube may still have tube 7

integrity_

'I~n the context ofThs~ Speci-fication, an OTSG tube-&is

~dfi ned as the entire length of the tuibe, including the tube wall and any repairs made to it, between the tube-to-Xcu besheet weld at the tube inlet and the tuube-to-tubesheet Weld at the tube outlet.

The tube7to-tubesheet weld is snot Ic~onsidered part of the tube.1

'An i0TS tu*asbe.

Integr~ity wheni7 t satis--

es te OTS*G p~erfor~mance criteria. ~The O0TSG perfor~mance criteria are

,defined in Specification 5.6.2.10, "Steam ~Generator' PProgram," and describe acceptable OT SG tube performance.

The Steam Generator Program also provides the ýevaluation Iprocess for determining conformance with the OTSG' erforaice criteri a.

IThere are t[Fe-e-OTS, G performance cri ter'i**

>- structura-jj integrity, accident induced leakage,ý and operationall LEAKAGE.

Failure to meet any one of these criteria-is

,considered failure,,,to meet: the: -CO.F MehstFu~ctualY1 nt~eg~rity

-perfor~mance cr~iterion -provi~de-s margnniof safety against tube burst or collapse underf rormal and accident conditions, and ensures structural integrity of: the OTSG tubes under, all anticipated_

itransients included in the design specification. Tubi burst is defined as, "The gross structural failure of thn tu b~e'wal

The condition! typicall y.co rýresponds,ýto an Unstable openi~n~gdisplacement te.g.,ý, openi*ng area increa!sed in response to constant pressure) accompanied by ductiler-(plastic) tearing of-the tube material at the ends of th, degradation."

Tube collapse is defined as, "For the load displacement curve.for a given structure, collapse occursi liat top of the load versus displacement curve where th6 Islope of the~ curve becomes' zero." 'The structuiral integrit~j performance criteri~on provides guidance on assessingh loads tthat have a significant effect on burst or collapse.

Inr Ithat context, the term "significant" is defined as

,accident loading condition other than differential preisFsu (continued)

Crystal River Unit 3 B 3.4-77 Revision No. XX

OTSG Tube Integrityj iB 3,.16_

BASES

.LCO is considered significant when the addition of such load, (continued) in the assessment of the structura] integrity performance

ý~criterion could cause a~ lower structural limi~t or 1imiti. ng bu rst/collapse condition to be established.".For tu* I integrity evaluations, except for circumferential degradation, axial thermal ]oads are classified as secondary loads.

For ci rcumferential degradation,,th I lassi f i cati on Iof 'axi a] thera lod a

p Iri mary orI seconday loads will be evaluated on a se-by-cas Th'e ~division between primary and secondary classi fi cati on~s will be based~ on detailed ~analysis and/or testin.

truc tural ntegrity require s that the, primary membr ane st ress intensity in a tube not exceed the yield strength for all ASME Code,Section III, Service Level A(normalf ope~rating ~coniditions) an~d Service Lev~el B (upset or,"_

bnormal cond.itions)transients included in the desii, specification.

This includes safety factors and ~applicable

,esign basis loads based on ASME Code*,Section IIIl Subsection NB (Ref. 4) and'Draft Regulatory Guide 1.121 L(Ref.

5).

iacident induced leakage performa.nce criterion ensures, that the ;primary to secondary LEAKAGE caused by a desigrn basis accident, other than a : SGTR, is wvithin the accident analysis assumptions.

The accident analysis assumes that

ccident induced leakage does not exceed one gallon per_

minute per OTSG, except for specific types of degradation

!at ýs~peci~fic location's where the ~NRC has approved greaterVr-

,accident induced *leakage.

The accident induced leakage Irate includes any primary to secondary LEAKAGEexisting prior to the accident-in addition to primary to secondaryj LLEAKAGE induced during the accident.-

IThe operational LEAKAGE performance criterion provides an observable indicatio6n o~f OTSG tube conditions~ during plant, operatiOn.

The limit on operatioIonal LEAKAGE is contained tin LCO 3.4.12, "RCS Operational LEAKAGE,"

and limitsf--

primary to secondary LEAKAGE through any one OTSG to 150

',gallons per day.

This limit is based on the assumption_

jthat a single crack leaking this amount would not propagate

,to a SGTR underthe stress coditions of.a LOCAor a. main -F steam li'nebreak.

If this amount of LEAKAGE is due to more than one crack, the cracks are very:small, and the above4 assumption is conservative.

[(cont i nue d Crystal River Unit 3 B 3.4-78 Revision No. XX J

QTSG Tube Integrity

-B 3.4.16' BASES APPL-ICABILITY Steam gene ratoF _tub~e inte 7grity i~s challenged ~when_-the pressure differential across the tubes is large.

LaF g ldifferential. pressures across OTSG tubes can onlyje gperienced in MODE 1,.2,.3, or_4.,

KRS condi tiHns arejfar 1 ess chalngi -ngi-n PODES S_ and 6 than during MODES 1, 2, 3, and 4 In MODES 5 and 6, pri*rary to secondary differential pressure is low, resultingi*r lower stresses and. reduced potential-, for LEAKAGE.

ACTIONS

.The ACTIONS* are modified' by a Note clarifyi ng that th'e 7Conditions may be entered independently for each OTSG tube.

This is acceptable because the Required Actions provide-apppropriate compensatory actions for each affected OTSd ftlbe.l Complying with the Required Actions may allow ~forL--

continued operation, and subsequent affected OTSG tubes are governed by subsequent Condition entry and application of, associated. Requi red _Actions.

A.1 and ~A..

'Condition A applies if it is discovered that one or more OTSG tubes examined in an inservice inspection satisfy th-e tube repair criteria.but were not plugged or repaired inF-accordance with the,Steam Generator Program as required ',*

iSR 3.4.16.2.

An evaluation of OTSG tube integrity ofthe' affected tube(s) must be made.

Steam generator tube*t integrity is based on, meeting the OTSG performance criteria described ii the Steam Generator Program..

The, OTSG repairj criteria define limi 'ts on OTSG tube degradation that allow for flaw growth between inspections while still providing assurance that the OTSG performance criteria will continue Ito be met.

In order to determine if an OTSG tube that,-

should have been plugged or repaired has: tu be integrittyn evaluation must be completed-that >deMonstrates that the OTSG performance criteria will continue to-be met until the next refueling outage or OTSG tube inspection.

The tuber--

integrity determination is based on the estimated conditýiýon

,of.the tube. at, the time the situation is discovered and the' estmat'ted growth of the degradat.on prior to the next OTSG 1tube inspecti5on.

If it is determined that tube integri tvf s not being maintained, Condition B applies.

(conti nued)

Crystal River Unit 3 B 3.4-79 Revision No. XX

')TSG Tube Integrity B. 3.4_A16 BASES ACTION'S KAJand

_(Eti~nu~eM)T A--Cjomj-ple-t--ionTime of7-f a-s uffi

-e--nt to compl]tthe

,eval uati on wh le mi nimzing the risk of plant operation with an OTSG tube that may not have tube integrity.

If the -v-al-ua-ti-o--n-' d-e-t-e-r-miii-nUe--h---t- --

t-h -af6iffcted tubi~e( ) -iarv-e Itube integrity, Requi red Action ~A.2 allows plant ope -ration pto* continue until the next refueling outage or OTSG' I

inspection provided the inspecti on i nterval conti nuesto: b-upported by an operati6nal assessment that reflects the--

,a-ffected tubes.

Howev'er, the affected tube(s), must beF_

'plugged or r~epaired~ prior, to entering MODE 4 following thR next refuelinhg outage or~ OTSG i nspectioo.

This KComp-eti o~n jTime is acceptable since operation until the nex*

inspection is supported by the operati ona assessment.

B1d-B72i iI f- _t hF6 R6ý u i r e d-TA-c-t1-i6* n _d Tn77 s oc'a-t-e*d *ComP 0 1 6 Ti me si791 Ito~ndltlon ::A: are notc ::met o r : if OTSG t ube. integrlity i::ls *not ibein9 maintained, the reactor must be brought to MODE r within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 within, 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .]

,The -liodw-edCoffp.RiffhTTimesa~r~e' --

e6asoraIb e, 'base -on operati n g-expri ence to reach the desi re'dpiant coidit-fi--n-from full power conditions in an orderly manner and without!

chalI enging pl ant systems.

SURVEILLANCE~

R 3.471T6. 1 iREQUIREMENTIS; D-uring' sh-utd-own perio-ds-the-OTS-s are inspected as requir-e-d by this SR and the Steam Generator Program.

NEI 97-06,]

,Steam Generator Program Guidelines (Ref.

1), and its7_

Ireferenced. EPRI Guidelines, establish the content of fh

~Steami Generator Program.

Use of the Steam Generator lProgram ensures :that the inspection is apprropriate ahd Iconsistent with accepted industrypractices.!.

D-uTing OTS`GCInspections a condi-ion monitoring assessment

'of the OTSG tubes iss performed.j The condition monitoring' assessment determines the "as found" conditis'on of t OTSG

,.ubes.

The purpose of the condition monitoring as.sessment is to ensure that the OTSG performance criteria have been*

met for the previous operatingjperiod.

(continued)

Crystal River Unit 3 B 3.4-80 Revision No. XX

LTSG Tube Integrity

ýB* 3.4.16d BASES SOR V EI LL A N C 5 S R' 3.4.f 6.1- (c-o n_____u RýEQUIREMEN!TS iTheSteam Generator Program determines the scope of-the inspectiion and the methods Iused to determine whether thke

'tubes contain flaws satisfying the tube repair criteria.

Inspection scope I(,i.e., which tubes or areas of tubing within~ the QTSG are to be inspected) is a funiction of,

'existing and! potential degradation locations.

The Steam Gene rato r Program also specifies' the, inspection methods -t-lbe used to find potential adegradation.

Inspection methods, are a, function ~of degradation, morphology, non-destructiver exami nat~ion (N)iis and ins~ci'on 1 ocati ons~.

he Steam Generator Program defines the Frequency off

,3.4.16.1.

The Frequency is determined by the operationalJ assessment and other 'limits in the, OTSG examinatio guidelines (Ref. 6)'

The Steam Generator,Program uses iinformati'on'on existi'ng deggradations and

' growth rates to, ldetermine an inspection Frequency that provides reasonabTe_

assurance that the tubing will meet the OTSG performance criteria at the next:scheduled inspection.

In addition,l Sp'eci'fic~ation 5'.6.2.10 contains pr~escriptive& requ'irerntfeis~,

'concerning*inspection intervals tto6 provilde added assurance Yhat the OTSG performance criteria will be met between.,

scheduled inspections. '

During ah OTSt'inspection, any afnspected tif isatisfies the Steam Generator Program repair criteria-is, repaired or removed from service by plugging. 'The tube repair criteria delineated in Specification 5.,6.2.10

.'aLgre In tended to ensure that tubes r

cceptedfmr continued Iervice satisfy the OTSG performance criteria with..

allowance for error in the flaw size measurement and forL_

future flaw growth.

In addition, the tube repair criteriWa]

in conjunction with other elements of the Steam Generator P1"rogram,,

ensure'thatthee OTSG performance criteria will conti nue to be met, until, the, next*i*nspecti on of the

~subect, tube(s).

Reference 1 provides guidance for performing9 operational assessments to verify that the tubes remaining in service will continue to meet the OTSG~performance, 1c r ite r ia.J Steam generator tube 'repairs are oni y per fo.rmedi us*g*

,approved repair methods as described in the Steam Generator 1,P rogram.f (continued)

Crystal River Unit 3 B 3.4-81 Revision No. XX

,JTSG Tube Integrity iB _3.4.16 BASES SURVEILLANCE SR 3.4.16.2 (conti nued)j

EUIREMENT__

The Freque ney ofp ri o-r to enterring MODE 4, fol owing a OTSG inspection ensures that the Su rveilla;nce h a ws been* completed and all tubes meeting* the repair,criteria are plugged ohn repai red prior to subjecti ng the OTSG tubes to si gni f icant prj!mry to secondary pressure differential.

AtrE"ERENCES-1.~ NEI 97-06,- "§týa-m- ~Ge-ne'rator-Pro-gramGuyi del Ine~s.

10 CFR 50,Appendix A, GDC 19.

13.

10 CFR 50.67.

'4-.

A-S[-'E Boiie-r vn Prsu EVssel ~co ct I on IT-ijT bsection NB.

5_ Draft Regulatory'Guide 1.121, "Basi s for Pluggi ng Degraded Steam Generator Tubes," August 1976.,

[6.,*--m,

EPRT, "Pre s s u ri-ized&'Water Reactor.,

Steam' Genea rojr Exaniintjon Gdi d~eli nes-.] '

Crystal River Unit 3 B 3.4-82 Revision No. XX

PRORESS ENERGY FLORIDA, INC.

CRYSTAL RIVER UNIT 3 DOCKET NUMBER 50-302 / LICENSE NUMBER DPR-72 LICENSE AMENDMENT REQUEST #264, REVISION 1 Application to Modify Improved Technical Specifications Regarding Steam Generator Tube Integrity ATTACHMENT F Proposed Improved Technical Specification Bases Pages (Revision Bar Format)

RCS Operational LEAKAGE B 3.4.12 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.12 RCS Operational LEAKAGE BASES BACKGROUND During the life of the plant, the joint and valve interfaces contained in the RCS can produce varying amounts of reactor coolant LEAKAGE, through either normal operational wear or mechanical deterioration.

The purpose of the RCS Operational LEAKAGE LCO is to limit system operation in the presence of LEAKAGE from these sources to amounts that do not compromise safety.

This LCO specifies the types and amounts of LEAKAGE.

10 CFR 50, Appendix A, GDC 30 (Ref. 1),

requires means for detecting and, to the extent practical, identifying the source of reactor coolant LEAKAGE.

Regulatory Guide 1.45 (Ref.

2) describes acceptable methods for selecting leakage detection systems.

OPERABILITY of the leakage detection systems is addressed in LCO 3.4.14, "RCS Leakage Detection Instrumentation."

The safety significance of RCS LEAKAGE varies widely depending on its source, rate, and duration.

Therefore, detecting, monitoring, and quantifying reactor coolant LEAKAGE is critical.

Quickly separating the identified LEAKAGE from the unidentified LEAKAGE is necessary to provide quantitative information to the operators, allowing them to take corrective action should a leak occur.

A limited amount of leakage inside containment is expected from auxiliary systems that cannot be made 100% leaktight.

Leakage from these systems should be detected, located, and isolated from the containment atmosphere, if possible, to not interfere with RCS leakage detection.

APPLICABLE SAFETY ANALYSES Except for primary to secondary LEAKAGE, the safety analyses do not address operational LEAKAGE.

However, other operational LEAKAGE is related to the safety analyses for a LOCA in that the amount of leakage can affect the probability of such an event.

The safety analysis for an event resulting in steam discharge to the atmosphere assumes (continued)

Crystal River Unit 3 B 3.4-53 Revision No.

RCS Operational LEAKAGE B 3.4.12 BASES APPLICABLE that primary to secondary LEAKAGE from all steam generators SAFETY ANALYSES (OTSGs) is one gallon per minute or increases to one gallon (continued) per minute as a result of accident induced conditions.

The LCO requirement to limit primary to secondary LEAKAGE through any one OTSG to less than or equal to 150 gallons per day is significantly less than the conditions assumed in the safety analysis.

The FSAR (Ref.

3) analysis for steam generator tube rupture (SGTR) assumes the contaminated secondary fluid is only briefly released via safety valves and the majority is steamed to the condenser.

The 1 gpm primary to secondary LEAKAGE safety analysis assumption is relatively inconsequential in terms of offsite dose.

The safety analysis for the Steam Line Break (SLB) accident assumes the entire 1 gpm primary to secondary LEAKAGE is through the affected generator as an initial condition (Ref.

4).

The dose consequences resulting from the SLB accident meet the acceptance criteria defined in 10 CFR 50.67.

RCS operational LEAKAGE satisfies Criterion 2 of the NRC Policy Statement.

LCO RCS operational LEAKAGE shall be limited to:

a.

Pressure Boundary LEAKAGE No pressure boundary LEAKAGE is allowed, being indicative of material deterioration.

LEAKAGE of this type is unacceptable as the leak itself could cause further deterioration, resulting in higher LEAKAGE.

Violation of this LCO could result in continued degradation of the reactor coolant pressure boundary (RCPB).

LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

b.

Unidentified LEAKAGE One gallon per minute (gpm) of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the containment atmosphere and sump level monitoring equipment can detect within a reasonable time period.

Violation of this LCO could result in continued degradation of the RCPB, if the LEAKAGE is from the pressure boundary.

(continued)

Crystal River Unit 3 B 3.4-54 Revision No.

RCS Operational LEAKAGE B 3.4.12 BASES LCO

c.

Identified LEAKAGE (continued)

Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with the detection of unidentified LEAKAGE and is well within the capability of the RCS makeup system.

Identified LEAKAGE includes LEAKAGE to the containment from specifically known and located sources, but does not include pressure boundary LEAKAGE or controlled reactor coolant pump (RCP) seal leakoff (a normal function not considered LEAKAGE).

Violation of this LCO could result in continued degradation of a component or system.

d.

Primary to Secondary LEAKAGE through Any One OTSG The limit of 150 gallons per day per OTSG is based on the operational LEAKAGE performance criterion in NEI 97-06, Steam Generator Program Guidelines (Ref.

5).

The Steam Generator Program operational LEAKAGE performance criterion in NEI 97-06 states, "The RCS operational primary to secondary leakage through any one SG shall be limited to 150 gallons per day."

The limit is based on operating experience with OTSG tube degradation mechanisms that result in tube leakage.

The operational leakage rate criterion in conjunction with the implementation of the Steam Generator Program is an effective measure for minimizing the frequency of steam generator tube ruptures.

(continued)

Crystal River Unit 3 B 3.4-55 Revision No.

RCS Operational LEAKAGE B 3.4.12 BASES ACTIONS A.1 If unidentified LEAKAGE or identified LEAKAGE is in excess of the LCO limits, the LEAKAGE must be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

This Completion Time allows time to verify leakage rates and either identify unidentified LEAKAGE or reduce LEAKAGE to within limits before the reactor must be shut down.

This action is necessary to prevent further deterioration of the RCPB.

B.1 and B.2 If any pressure boundary LEAKAGE exists or primary to secondary LEAKAGE is not within limits, or if unidentified or identified LEAKAGE cannot be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , the reactor must be placed in a lower pressure condition to reduce the severity of the LEAKAGE and its potential consequences.

The reactor must be placed in MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

This action reduces the LEAKAGE and also reduces the stresses that tend to degrade the pressure boundary.

The Completion Times allowed are reasonable, based on operating experience, to reach the required conditions from full power conditions in an orderly manner and without challenging plant systems.

In MODE 5, the pressure stresses acting on the RCPB are much lower and further deterioration is much less likely.

SURVEILLANCE SR 3.4.12.1 REQUIREMENTS Verifying RCS LEAKAGE within the LCO limits ensures that the integrity of the RCPB is maintained.

Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection.

Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance.

(continued)

Crystal River Unit 3 B 3.4-56 Revision No.

RCS Operational LEAKAGE B 3.4.12 BASES SURVEILLANCE SR 3.4.12.1 (continued)

REQUIREMENTS The RCS water inventory balance must be performed with the reactor at steady state operating conditions and with RCS temperature greater than 400'F.

The test must be performed prior to entry into MODE 2 if it has not been performed within the past 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months near normal operating pressure.

This surveillance is modified by two notes.

Note 1 states that it is not required to be performed for entry into MODE 4 or for non-steady state conditions in MODE 3, but must be performed in MODE 3 above 400°F if 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of steady state operation are achieved.

If the test is not performed prior to all other requirements for entry into MODE 2 being satisfied, entry into MODE 2 must be delayed until steady state operation is established and the requirements of SR 3.0.4 are satisfied.

Steady state operation is required to perform a meaningful water inventory balance; calculations during maneuvering are not useful.

For RCS operational LEAKAGE determination by water inventory balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP pump seal injection and return flows.

Note 2 states that this SR is not applicable to primary to secondary LEAKAGE because LEAKAGE of 150 gallons per day cannot be measured accurately by an RCS water inventory balance.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Frequency is reasonable to trend LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents.

SR 3.4.12.2 This SR verifies that primary to secondary LEAKAGE is less than or equal to 150 gallons per day through any one OTSG.

Satisfying the primary to secondary LEAKAGE limit ensures that the operational LEAKAGE performance criterion in the Steam Generator Program is met.

If this SR is not met, compliance with LCO 3.4.16, "Steam Generator Tube Integrity," should be evaluated.

The 150 gallons per day limit is measured at room temperature as described in Reference 6.

The operational LEAKAGE rate limit applies to (continued)

Crystal River Unit 3 B 3.4-57 Revision No.

RCS Operational LEAKAGE B 3.4.12 BASES SURVEILLANCE SR 3.4.12.2 (continued)

REQUIREMENTS LEAKAGE through any one OTSG.

If it is not practical to assign the LEAKAGE to an individual OTSG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one OTSG.

The Surveillance is modified by a Note which states that the Surveillance is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation.

For RCS primary to secondary LEAKAGE determination, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

The Surveillance Frequency of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is a reasonable interval to trend primary to secondary LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents.

The primary to secondary LEAKAGE is determined using continuous process radiation monitors or radiochemical grab sampling in accordance with the EPRI guidelines (Ref.

6).

REFERENCES

1.

10 CFR 50, Appendix A, GDC 30.

2.

Regulatory Guide 1.45, May 1973.

3.

FSAR, Section 14.2.2.2.

4.

FSAR, Section 14.2.2.1.

5.

NEI 97-06, "Steam Generator Program Guidelines."

6.

EPRI, "Pressurized Water Reactor Primary-to-Secondary Leak Guidelines."

Crystal River Unit 3 B 3.4-S8 Revision No.

OTSG Tube Integrity B 3.4.16 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.16 Steam Generator (OTSG)

Tube Integrity BASES BACKGROUND Steam generator (OTSG) tubes are small diameter, thin walled tubes that carry primary coolant through the primary to secondary heat exchanges.

The OTSG tubes have a number of important safety functions.

Steam generator tubes are an integral part of the reactor coolant pressure boundary (RCPB) and, as such, are relied on to maintain the primary system's pressure and inventory.

The OTSG tubes isolate the radioactive fission products in the primary coolant from the secondary system.

In addition, as part of the RCPB, the OTSG tubes are unique in that they act as the heat transfer surface between the primary and secondary systems to remove heat from the primary system.

This Specification addresses only the RCPB integrity function of the OTSG.

The OTSG heat removal function is addressed by LCO 3.4.4, "RCS Loops -

MODE 3,"

LCO 3.4.5, "RCS Loops -

MODE 4,"

LCO 3.4.6, "RCS Loops -

MODE 5, Loops Filled," and is implicitly required in MODES 1 and 2 in order to prevent a Reactor Protection System actuation (LCO 3.3.1).

OTSG tube integrity means that the tubes are capable of performing their intended RCPB safety function consistent with the licensing basis, including applicable regulatory requirements.

Steam generator tubing is subject to a variety of degradation mechanisms.

Steam generator tubes may experience tube degradation related to corrosion phenomena, such as wastage, pitting, intergranular attack, and stress corrosion cracking, along with other mechanically induced phenomena such as denting and wear.

These degradation mechanisms can impair tube integrity if they are not managed effectively.

The OTSG performance criteria are used to manage OTSG tube degradation.

Specification 5.6.2.10, "Steam Generator (OTSG)

Program,"

requires that a program be established and implemented to ensure that OTSG tube integrity is maintained.

Pursuant to Specification 5.6.2.10, tube integrity is maintained when the OTSG performance criteria are met.

There are three OTSG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE.

The OTSG (continued)

Crystal River Unit 3 B 3.4-75 Revision No.

OTSG Tube Integrity B 3.4.16 BASES BACKGROUND performance criteria are described in Specification (continued) 5.6.2.10.

Meeting the OTSG performance criteria provides reasonable assurance of maintaining tube integrity at normal and accident conditions.

The processes used to meet the OTSG performance criteria are defined by the Steam Generator Program Guidelines (Ref.

1).

APPLICABLE SAFETY ANALYSES The steam generator tube rupture (SGTR) accident is the limiting design basis event for OTSG tubes and avoiding an SGTR is the basis for this Specification.

The analysis of a SGTR event assumes a bounding primary to secondary LEAKAGE rate equal to the operational LEAKAGE rate limits in LCO 3.4.12, "RCS Operational LEAKAGE,"

plus the leakage rate associated with a double-ended rupture of a single tube.

The accident analysis for a SGTR assumes the contaminated secondary fluid is only briefly released to the atmosphere via safety valves and the majority is discharged to the main condenser.

The analysis for design basis accidents and transients other than a SGTR assume the OTSG tubes retain their structural integrity (i.e., they are assumed not to rupture).

In these analyses, the steam discharge to the atmosphere is based on the total primary to secondary LEAKAGE from all OTSGs of one gallon per minute or is assumed to increase to one gallon per minute as a result of accident induced conditions.

For accidents that do not involve fuel damage, the primary coolant activity level of DOSE EQUIVALENT 1-131 is assumed to be equal to the LCO 3.4.15, "RCS Specific Activity," limits.

For accidents that assume fuel damage, the primary coolant activity is a function of the amount of activity released from the damaged fuel.

The dose consequences of these events are within the limits of GDC 19 (Ref. 2),

10 CFR 50.67 (Ref.

3) or the NRC approved licensing bases (e.g., a small fraction of these limits).

Steam generator tube integrity satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO The LCO requires that OTSG tube integrity be maintained.

The LCO also requires that all OTSG tubes that satisfy the repair criteria be plugged or repaired in accordance with the Steam Generator Program.

(continued)

Crystal River Unit 3 B 3.4-76 Revision No.

OTSG Tube Integrity B 3.4.16 BASES LCO During an OTSG inspection, any inspected tube that (continued) satisfies the Steam Generator Program repair criteria is repaired or removed from service by plugging.

If a tube was determined to satisfy the repair criteria but was not plugged or repaired, the tube may still have tube integrity.

In the context of this Specification, an OTSG tube is defined as the entire length of the tube, including the tube wall and any repairs made to it, between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet.

The tube-to-tubesheet weld is not considered part of the tube.

An OTSG tube has tube integrity when it satisfies the OTSG performance criteria.

The OTSG performance criteria are defined in Specification 5.6.2.10, "Steam Generator Program," and describe acceptable OTSG tube performance.

The Steam Generator Program also provides the evaluation process for determining conformance with the OTSG performance criteria.

There are three OTSG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE.

Failure to meet any one of these criteria is considered failure to meet the LCO.

The structural integrity performance criterion provides a margin of safety against tube burst or collapse under normal and accident conditions, and ensures structural integrity of the OTSG tubes under all anticipated transients included in the design specification.

Tube burst is defined as, "The gross structural failure of the tube wall.

The condition typically corresponds to an unstable opening displacement (e.g., opening area increased in response to constant pressure) accompanied by ductile (plastic) tearing of the tube material at the ends of the degradation."

Tube collapse is defined as, "For the load displacement curve for a given structure, collapse occurs at the top of the load versus displacement curve where the slope of the curve becomes zero."

The structural integrity performance criterion provides guidance on assessing loads that have a significant effect on burst or collapse.

In that context, the term "significant" is defined as "An accident loading condition other than differential pressure (continued)

Crystal River Unit 3 B 3.4-77 Revision No.

OTSG Tube Integrity B 3.4.16 BASES LCO (continued) is considered significant when the addition of such loads in the assessment of the structural integrity performance criterion could cause a lower structural limit or limiting burst/collapse condition to be established."

For tube integrity evaluations, except for circumferential degradation, axial thermal loads are classified as secondary loads.

For circumferential degradation, the classification of axial thermal loads as primary or secondary loads will be evaluated on a case-by-case basis.

The division between primary and secondary classifications will be based on detailed analysis and/or testing.

Structural integrity requires that the primary membrane stress intensity in a tube not exceed the yield strength for all ASME Code,Section III, Service Level A (normal operating conditions) and Service Level B (upset or abnormal conditions) transients included in the design specification.

This includes safety factors and applicable design basis loads based on ASME Code,Section III, Subsection NB (Ref. 4) and Draft Regulatory Guide 1.121 (Ref.

5).

The accident induced leakage performance criterion ensures that the primary to secondary LEAKAGE caused by a design basis accident, other than a SGTR, is within the accident analysis assumptions.

The accident analysis assumes that accident induced leakage does not exceed one gallon per minute per OTSG, except for specific types of degradation at specific locations where the NRC has approved greater accident induced leakage.

The accident induced leakage rate includes any primary to secondary LEAKAGE existing prior to the accident in addition to primary to secondary LEAKAGE induced during the accident.

The operational LEAKAGE performance criterion provides an observable indication of OTSG tube conditions during plant operation.

The limit on operational LEAKAGE is contained in LCO 3.4.12, "RCS Operational LEAKAGE,"

and limits primary to secondary LEAKAGE through any one OTSG to 150 gallons per day.

This limit is based on the assumption that a single crack leaking this amount would not propagate to a SGTR under the stress conditions of a LOCA or a main steam line break.

If this amount of LEAKAGE is due to more than one crack, the cracks are very small, and the above assumption is conservative.

(conti nued)

Crystal River Unit 3 B 3.4-78 Revision No.

OTSG Tube Integrity B 3.4.16 BASES APPLICABILITY Steam generator tube integrity is challenged when the pressure differential across the tubes is large.

Large differential pressures across OTSG tubes can only be experienced in MODE 1, 2, 3, or 4.

RCS conditions are far less challenging in MODES 5 and 6 than during MODES 1, 2, 3, and 4.

In MODES 5 and 6, primary to secondary differential pressure is low, resulting in lower stresses and reduced potential for LEAKAGE.

ACTIONS The ACTIONS are modified by a Note clarifying that the Conditions may be entered independently for each OTSG tube.

This is acceptable because the Required Actions provide appropriate compensatory actions for each affected OTSG tube.

Complying with the Required Actions may allow for continued operation, and subsequent affected OTSG tubes are governed by subsequent Condition entry and application of associated Required Actions.

A.1 and A.2 Condition A applies if it is discovered that one or more OTSG tubes examined in an inservice inspection satisfy the tube repair criteria but were not plugged or repaired in accordance with the Steam Generator Program as required by SR 3.4.16.2.

An evaluation of OTSG tube integrity of the affected tube(s) must be made.

Steam generator tube integrity is based on meeting the OTSG performance criteria described in the Steam Generator Program.

The OTSG repair criteria define limits on OTSG tube degradation that allow for flaw growth between inspections while still providing assurance that the OTSG performance criteria will continue to be met.

In order to determine if an OTSG tube that should have been plugged or repaired has tube integrity, an evaluation must be completed that demonstrates that the OTSG performance criteria will continue to be met until the next refueling outage or OTSG tube inspection.

The tube integrity determination is based on the estimated condition of the tube at the time the situation is discovered and the estimated growth of the degradation prior to the next OTSG tube inspection.

If it is determined that tube integrity is not being maintained, Condition B applies.

(continued)

Crystal River Unit 3 B 3.4-79 Revision No.

OTSG Tube Integrity B 3.4.16 BASES ACTIONS A.1 and A.2 (continued)

A Completion Time of 7 days is sufficient to complete the evaluation while minimizing the risk of plant operation with an OTSG tube that may not have tube integrity.

If the evaluation determines that the affected tube(s) have tube integrity, Required Action A.2 allows plant operation to continue until the next refueling outage or OTSG inspection provided the inspection interval continues to be supported by an operational assessment that reflects the affected tubes.

However, the affected tube(s) must be plugged or repaired prior to entering MODE 4 following the next refueling outage or OTSG inspection.

This Completion Time is acceptable since operation until the next inspection is supported by the operational assessment.

B.1 and B.2 If the Required Actions and associated Completion Times of Condition A are not met or if OTSG tube integrity is not being maintained, the reactor must be brought to MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

The allowed Completion Times are reasonable, based on operating experience, to reach the desired plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.4.16.1 REQUIREMENTS During shutdown periods the OTSGs are inspected as required by this SR and the Steam Generator Program.

NEI 97-06, Steam Generator Program Guidelines (Ref.

1),

and its referenced EPRI Guidelines, establish the content of the Steam Generator Program.

Use of the Steam Generator Program ensures that the inspection is appropriate and consistent with accepted industry practices.

During OTSG inspections a condition monitoring assessment of the OTSG tubes is performed.

The condition monitoring assessment determines the "as found" condition of the OTSG tubes.

The purpose of the condition monitoring assessment is to ensure that the OTSG performance criteria have been met for the previous operating period.

(continued)

Crystal River Unit 3 B 3.4-80 Revision No.

OTSG Tube Integrity B 3.4.16 BASES SURVEILLANCE SR 3.4.16.1 (continued)

REQUIREMENTS The Steam Generator Program determines the scope of the inspection and the methods used to determine whether the tubes contain flaws satisfying the tube repair criteria.

Inspection scope (i.e., which tubes or areas of tubing within the OTSG are to be inspected) is a function of existing and potential degradation locations.

The Steam Generator Program also specifies the inspection methods to be used to find potential degradation.

Inspection methods are a function of degradation morphology, non-destructive examination (NDE) technique capabilities, and inspection locations.

The Steam Generator Program defines the Frequency of SR 3.4.16.1.

The Frequency is determined by the operational assessment and other limits in the OTSG examination guidelines (Ref.

6).

The Steam Generator Program uses information on existing degradations and growth rates to determine an inspection Frequency that provides reasonable assurance that the tubing will meet the OTSG performance criteria at the next scheduled inspection.

In addition, Specification 5.6.2.10 contains prescriptive requirements concerning inspection intervals to provide added assurance that the OTSG performance criteria will be met between scheduled inspections.

SR 3.4.16.2 During an OTSG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is repaired or removed from service by plugging.

The tube repair criteria delineated in Specification 5.6.2.10 are intended to ensure that tubes accepted for continued service satisfy the OTSG performance criteria with allowance for error in the flaw size measurement and for future flaw growth.

In addition, the tube repair criteria, in conjunction with other elements of the Steam Generator Program, ensure that the OTSG performance criteria will continue to be met until the next inspection of the subject tube(s).

Reference 1 provides guidance for performing operational assessments to verify that the tubes remaining in service will continue to meet the OTSG performance criteria.

Steam generator tube repairs are only performed using approved repair methods as described in the Steam Generator Program.

(continued)

Crystal River Unit 3 B 3.4-81 Revision No.

OTSG Tube Integrity B 3.4.16 BASES SURVEILLANCE SR 3.4.16.2 (continued)

REQUIREMENTS The Frequency of prior to entering MODE 4 following a OTSG inspection ensures that the Surveillance has been completed and all tubes meeting the repair criteria are plugged or repaired prior to subjecting the OTSG tubes to significant primary to secondary pressure differential.

REFERENCES

1.

NEI 97-06, "Steam Generator Program Guidelines."

2.

10 CFR 50 Appendix A, GDC 19.

3.

10 CFR 50.67.

4.

ASME Boiler and Pressure Vessel Code,Section III, Subsection NB.

5.

Draft Regulatory Guide 1.121, "Basis for Plugging Degraded Steam Generator Tubes," August 1976.

6.

EPRI, "Pressurized Water Reactor Steam Generator Examination Guidelines."

Crystal River Unit 3 B 3.4-82 Revision No.

v t e Letter Sequence Response to RAI
TAC:MD0074, (Open)
Initiation Acceptance... Administration Questions Answers 21 December 2006 Results Approval... Other: ML071580373
MONTHYEAR2006-12-21 [Table View]

3F1206-02, License Amendment Request 264, Revision 1: Application to Modify Improved Technical Specifications Regarding Steam Generator Tube Integrity and Response to Request for Additional Information

Text

Subject:

References:

Dear Sir:

References:

1.0 INTRODUCTION

2.0 DESCRIPTION

3.0 BACKGROUND

5.0 TECHNICAL ANALYSIS

6.0 REGULATORY ANALYSIS

10.0 REFERENCES

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3F1206-02, License Amendment Request 264, Revision 1: Application to Modify Improved Technical Specifications Regarding Steam Generator Tube Integrity and Response to Request for Additional Information

Text

Subject:

References:

Dear Sir:

References:

1.0 INTRODUCTION

2.0 DESCRIPTION

3.0 BACKGROUND

5.0 TECHNICAL ANALYSIS

6.0 REGULATORY ANALYSIS

10.0 REFERENCES

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