ML070190094

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License Amendment Request 07-01, Revision to Technical Specifications to Support Steam Generator Replacement
ML070190094
Person / Time
Site: Salem, Diablo Canyon  PSEG icon.png
Issue date: 01/11/2007
From: Becker J R
Pacific Gas & Electric Co
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
DCL-07-002, LAR 07-01
Download: ML070190094 (101)
v • d • e


Text

Pacific Gas and Electric Companyo James R. Becker Diablo Canyon Power Plant Vice President P. 0. Box 56 Diablo Canyon Operations and Avila Beach, CA 93424 Station Director 805.545.3462 January 11, 2007 Fax: 805.545.4234 PG&E Letter DCL-07-002 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555-0001 Docket No. 50-275, OL-DPR-80 Docket No. 50-323, OL-DPR-82 Diablo Canyon Units 1 and 2 License Amendment Request 07-01 Revision to Technical Specifications to Support Steam Generator Replacement Dear Commissioners and Staff: In accordance with 10 CFR 50.90, enclosed is a License Amendment Request (LAR) for Facility Operating License Nos. DPR-80 and DPR-82 for Units 1 and 2 of the Diablo Canyon Power Plant (DCPP), respectively.

In the LAR, Pacific Gas and Electric Company (PG&E) proposes to revise the Technical Specifications (TS) to support replacement of the steam generators (SGs). Revisions are proposed to TS 3.3.2, "Engineered Safety Feature Actuation System (ESFAS) Instrumentation," TS 5.5.9, "Steam Generator (SG) Program," and TS 5.6.10, "Steam Generator (SG)Tube Inspection Report." The replacement SGs are to be installed during the Unit 2 fourteenth refueling outage (2R14), currently scheduled for February 2008, and the Unit 1 fifteenth refueling outage (1 R1 5), currently scheduled for January 2009.The changes to TS 3.3.2 revise the Nominal Trip Setpoint (NTSP) and Allowable Value (AV) and clarify the surveillance requirements associated with ESFAS Function 5.b, "Feedwater Isolation SG Water Level-High High (P-14)." The TS 3.3.2 changes are consistent with TS Task Force (TSTF) Standard TS Change Traveler TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," Revision 1. The setpoint methodology used to revise the TS 3.3.2 Function 5.b NTSP and AV is based on previously approved Westinghouse methodology and is equally or more conservative than the methodology accepted by the NRC in Regulatory Issue Summary 2006-17.The TS 5.5.9 and TS 5.6.10 changes are consistent with NRC-approved TSTF Traveler, TSTF-449, "Steam Generator Tube Integrity," Revision 4. The availability of this TS improvement was announced in the Federal Register on May 6, 2005, as part of the consolidated line item improvement process (CLIIP). TS revisions incorporating TSTF-449, Revision 4 changes, applicable to the existing (original)

A member of the STARS (Strategic Teaming and Resource Sharing) Alliance A DO Callaway 9 Comanche Peak

  • Diablo Canyon
  • Palo Verde

Enclosure 1 contains a description of the proposed changes, the supporting technical analyses, and the no significant hazards consideration determination.

Enclosures 2 and 3 contain marked-up and retyped TS pages, respectively.

Enclosure 4 provides marked-up TS Bases pages for information only. The TS Bases changes will be implemented pursuant to TS 5.5.14, "Technical Specifications Bases Control Program." Enclosure 5 contains the new commitments contained in the submittal.

Enclosures 6 and 8 contain non-proprietary and proprietary information related to the revised ESFAS setpoints, respectively.

Enclosure 8 contains information proprietary to Westinghouse Electric Company LLC ("Westinghouse").

Accordingly, Enclosure 7 includes a Westinghouse authorization Letter, CAW-06-2224, an accompanying affidavit, a Proprietary Information Notice, and a Copyright Notice. The affidavit is signed by Westinghouse, the owner of the information.

The affidavit sets forth the basis on which the Westinghouse proprietary information contained in Enclosure 8 may be withheld from public disclosure by the Commission, and it addresses with specificity the considerations listed in paragraph (b)(4) of 10 CFR 2.390 of the Commission's regulations.

PG&E requests that the Westinghouse proprietary information be withheld from public disclosure in accordance with 10 CFR 2.390.Correspondence with respect to the copyright or proprietary aspects of the application for withholding related to the Westinghouse proprietary information or the Westinghouse affidavit provided in Enclosure 7 should reference Westinghouse Letter CAW-06-2224 and be addressed to J. A. Gresham, Manager, Regulatory Compliance and Plant Licensing, Westinghouse Electric Company LLC, P.O. Box 355, Pittsburgh, Pennsylvania, 15230-0355.

PG&E has determined that this LAR does not involve a significant hazards consideration as determined per 10 CFR 50.92. Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment needs to be prepared in connection with the issuance of this amendment.

The changes in this LAR are not required to address an immediate safety concern.PG&E requests approval of this LAR no later than January 11, 2008, to support preparations for the SG replacement during 2R.14, which is currently scheduled to A member of the STARS (Strategic Teaming and Resource Sharing) Attiance Callaway 9 Comanche Peak 9 Diablo Canyon

  • PaloVerde e South Texas Project
  • Wolf Creek F!q8 Document Control Desk January 11,2007 Page 3 PG&E Letter DCL-07-002 begin in February 2008. PG&E requests the license amendment(s) be made effective upon NRC issuance, to be implemented for Unit 2 prior to entry into Mode 4 following 2R1 4 and to be implemented for Unit 1 prior to entry into Mode 4 following IR15.This communication contains new commitments to be implemented following NRC approval of the LAR. The commitments are contained in Enclosure 5.If you have any questions or require additional information, please contact Stan Ketelsen at 805-545-4720.

I state under penalty of perjury that the foregoing is true and correct.Executed on January 11,2007.Sincerely,'-ýV- \Th -'ýj James R. Becker Vice President

-Diablo Canyon Operations and Station Director kjse/4328 Enclosures cc: cc/enc: Edgar Bailey, DHS Terry W. Jackson Bruce S. Mallett Diablo Distribution Alan B. Wang A member of the STARS (Strategic Teaming and Resource Sharing) Alliance Callaway

  • Comanche Peak
  • Diablo Canyon
  • Palo Verde

1.0 DESCRIPTION

This enclosure is a request to amend Operating Licenses DPR-80 and DPR-82 for Units 1 and 2 of the Diablo Canyon Power Plant (DCPP), respectively.

The proposed changes would revise the following Technical Specifications (TS)in support of replacement steam generators (RSGs) to be installed in Unit 2 during the Unit 2 fourteenth refueling outage (2R14) currently scheduled for February 2008, and in Unit 1 during the Unit 1 fifteenth refueling outage (1 R1 5)currently scheduled for January 2009: " TS 3.3.2, "Engineered Safety Feature Actuation System (ESFAS)Instrumentation"* TS 5.5.9, "Steam Generator (SG) Program"" TS 5.6.10, "Steam Generator (SG) Tube Inspection Report"

2.0 PROPOSED CHANGE

The following proposed changes to the TS are included in this amendment application:

1. Table 3.3.2-1 lists ESFAS Functions and applicable Surveillance Requirements (SRs). New Notes (d) and (e) (below) are added to the bottom of Table 3.3.2-1 (TS page 3.3-31) and are applied to SRs 3.3.2.5 and 3.3.2.9 for Function 5.b, "Feedwater Isolation SG Water Level-High High (P-14)." Note (d) for TS Table 3.3.2-1: If the as-found channel setpoint is conservative with respect to the Allowable Value but outside its predefined as-found acceptance criteria band, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. If the as-found instrument channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable.

Footnote (a) does not apply to this function.Note (e) for TS Table 3.3.2-1: The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable.

Setpoints more conservative than the NTSP are 1 Enclosure 1 PG&E Letter DCL-07-002 acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures to confirm channel performance.

The methodologies used to determine the as-found and the as-left tolerance are specified in the Equipment Control Guidelines.

Footnote (a) does not apply to this function.These changes are needed to implement the TS Task Force (TSTF)Standard TS Change Traveler, TSTF-493, "Clarify Application of Setpoint Methodology for LSSS Functions," Revision 1, dated October 2, 2006, setpoint requirements for the Feedwater Isolation SG Water Level-High High (P-14) setpoint.2. TS 3.3.2, Table 3.3.2-1, Function 5.b currently specifies a Feedwater Isolation SG Water Level-High High (P-14) setpoint allowable value (AV) of less than or equal to 75.2 percent and a NTSP of 75.0 percent. These setpoints are changed to an AV of less than or equal to 90.2 percent and a NTSP of 90.0 percent.These changes are needed to reflect setpoint analyses for the TS 3.3.2, Table 3.3.2-1, ESFAS Function 5.b for the RSG's expanded narrow range (NR) level tap locations.

3. Consistent with the NRC-approved TSTF-449, "Steam Generator Tube Integrity," Revision 4, TS 5.5.9 and TS 5.6.10 are revised to delete the existing SG tube Alternate Repair Criteria (ARC), which do not apply to the RSGs, and TS 5.5.9 is revised to replace the inspection interval requirement associated with the existing Alloy 600 mill annealed tubes with an inspection interval requirement applicable to the RSG Alloy 690 thermally treated (Alloy 690TT) tubes. Specific changes to TS 5.5.9.b.1, 5.5.9.b.2, 5.5.9.c, 5.5.9.d, 5.5.9.d.2, 5.5.9.d.4, 5.5.9.d.5, 5.5.9.d.6, 5.6.10.a, 5.6.10.b, 5.6.10.c, 5.6.10.d, 5.6.10.e, 5.6.10.f, and 5.6.10.g are as follows: TS 5.5.9.b.1 sentence, "This includes retaining a safety factor of 3.0 against burst under normal steady state full power operation primary-to-secondary pressure differential and, except for flaws addressed through application of the alternate repair criteria discussed in Specification 5.5.9.c.1 and 5.5.9.c.3, a safety factor of 1.4 against burst applied to the design basis accident primary-to-secondary pressure differentials," is revised to, "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." 2 Enclosure 1 PG&E Letter DCL-07-002 The following TS 5.5.9.b.1 sentences are deleted: "When alternate repair criteria discussed in Specification 5.5.9.c.1 are applied to axially-oriented outside diameter stress corrosion cracking indications at tube support plate locations, the probability that one or more of these indications in a SG will burst under postulated main steam line break conditions shall be less than lx1 0-2,' and, "When alternate repair criteria discussed in Specification 5.5.9.c.3 are applied to axially-oriented primary water stress corrosion cracking indications at tube support plate locations, the probability that one or more of these indications in a SG will burst under postulated main steam line break conditions shall be less than lx1 0-2., The TS 5.5.9.b.2 sentence, "Except during a steam generator tube rupture, leakage from all sources, excluding the leakage attributed to the degradation described in Specification 5.5.9.c.1, 5.5.9.c.2, and 5.5.9.c.3, is also not to exceed 1 gallon per minute per SG," is revised to, "Except during a SG tube rupture, leakage is also not to exceed 1 gallon per minute per SG." TS 5.5.9.c is revised to delete the sentence, "The following alternate tube repair criteria may be applied as an alternative to the 40% depth based criteria:" TS 5.5.9.c.1, 5.5.9.c.2, and 5.5.9.c.3 are deleted.TS 5.5.9.d sentence, "In addition to meeting the requirements of d.1, d.2, d.3, d.4, d.5, and d.6 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection," is revised to, "In addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection." TS 5.5.9.d.2 is revised from, "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 SGs. No SG shall operate for more than 24 effective full power months or one refueling outage (whichever is less) without being inspected," to, "Inspect 100% of the tubes at sequential periods of 144, 108, 72, and, thereafter, 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outage nearest the end of the period. No SG shall operate for more than 72 effective full power months or three refueling outages (whichever is less) without being inspected." 3 Enclosure 1 PG&E Letter DCL-07-002 TS 5.5.9.d.4, 5.5.9.d.5, and 5.5.9.d.6 are deleted.TS 5.6.10 items "a. 1"," a.2", "a.3", "a.4", "a.5", "a.6", and "a.7" are re-lettered to be "a.", "b.", "c.", "d.", "e.", "C', and "g." respectively and "a." is removed from the first paragraph of TS 5.6.10.TS 5.6.10.b, 5.6.10.c, 5.6.10.d, 5.6.10.e, 5.6.10.f, and 5.6.10.g are deleted.This enclosure contains a description of the proposed changes, the supporting technical analyses, and the no significant hazards consideration determination.

Enclosures 2 and 3 contain marked-up and retyped TS pages, respectively.

Enclosure 4 provides marked-up TS Bases pages for information only. The TS Bases changes will be implemented pursuant to TS 5.5.14, "Technical Specifications Bases Control Program." Enclosure 5 lists the new commitments contained in this License Amendment Request (LAR). Enclosures 6 and 8 contain non-proprietary and proprietary information related to the revised ESFAS setpoints, respectively.

Enclosure 7 contains a Westinghouse authorization Letter, an accompanying affidavit, a Proprietary Information Notice, and a Copyright Notice for the proprietary information contained in Enclosure 8.The TS 5.5.9 and TS 5.6.10 changes are consistent with NRC-approved TSTF-449, Revision 4. The availability of this TS improvement was announced in the Federal Register on May 6, 2005, as part of the consolidated line item improvement process (CLIIP). TS revisions incorporating TSTF-449, Revision 4, changes applicable to DCPP's existing SGs were submitted to the NRC in DCPP LAR 06-04 by Pacific Gas &Electric Company (PG&E) Letter DCL-06-061 dated May 30, 2006, and supplemented in PG&E Letter DCL-06-130 dated November 22, 2006. PG&E expects to implement TS changes at DCPP consistent with TSTF-449, Revision 4, in early 2007. Therefore, the proposed changes to TS 5.5.9 and 5.6.10 are based on the proposed TS contained in PG&E Letter DCL-06-130.

3.0 BACKGROUND

DCPP currently has Westinghouse Model 51 SGs (referred to as the existing SGs) installed in both units. New Westinghouse Model Delta-54 RSGs will be installed in Unit 2 during 2R14, currently scheduled for February 2008, and in Unit 1 during 1 R1 5, currently scheduled for January 2009. Since the existing SGs and RSGs are similar, the SG replacement is being evaluated under 10 CFR 50.59.PG&E contracted with Westinghouse to perform the Nuclear Steam Supply System evaluations, the Final Safety Analysis Report (FSAR) Update Chapter 15 4 Enclosure 1 PG&E Letter DCL-07-002 safety analyses, and the setpoint calculations associated with the SG replacement.

These evaluations and analyses identified that a TS change to ESFAS Function 5.b is required due to the expanded NR level tap locations in the RSGs. Background information on the required TS changes described in Section 2.0 is contained below.3.1 TSTF-493, Revision 1, Changes NRC Regulatory Issue Summary (RIS) 2006-17, "NRC Staff Position on the Requirements of 10 CFR 50.36, 'Technical Specifications,'

Regarding Limiting Safety System Settings During Periodic Testing and Calibration of Instrument Channels," dated August 24, 2006, discusses the requirements of 10 CFR 50.36 related to Limiting Safety System Settings (LSSS) and provides an approach acceptable to the NRC to address LSSS issues.LSSS are settings for automatic protective devices related to those variables having significant safety functions.

RIS 2006-17 provides guidance on how to determine when as-found values are acceptable with respect to the NTSP and required actions to be taken when the as-found value is outside predefined acceptance limits or outside the AV. TSTF-493, Revision 1, incorporates this guidance by specifying the requirements for assessing whether an instrument channel is operable based on the as-found setpoint and describes the required actions before returning a channel to service. In addition, the NRC provided comments on TSTF-493, Revision 1, in a letter dated December 14, 2006. Since the SG replacement requires changes to the Feedwater Isolation SG Water Level-High High (P-14) ESFAS setpoint, the guidance of TSTF-493, Revision 1, and the NRC letter dated December 14, 2006, is applied to ESFAS Function 5.b, Feedwater Isolation SG Water Level-High High (P-14).TSTF-493, Revision 1, is currently under NRC review and is not expected to be made available under the CLIIP until the first quarter 2007. Based on guidance provided in RIS 2006-17, the current TSTF-493, Revision 1, is being implemented for the ESFAS function addressed in this LAR. The TSTF-493 changes will be made to the remaining applicable Reactor Trip System (RTS) and ESFAS functions in a separate LAR that will be submitted after TSTF-493 is approved by the NRC.3.2 Feedwater Isolation SG Water Level-High High (P-14) Setpoint TS 3.3.2, Table 3.3.2-1 Function 5.b, Feedwater Isolation SG Water Level-High High (P-14), requires three NR level channels per SG with an AV of less than or equal to 75.2 percent and a NTSP of 75 percent for the 5 Enclosure 1 PG&E Letter DCL-07-002 existing SGs. This function provides the isolation of feedwater for events that result in an excessive increase in feedwater flow.3.3 TS 5.5.9 and 5.6.10 Changes The background for the TS 5.5.9 and 5.6.10 changes in 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 4.3.4 ESFAS Functions The ESFAS consists of reactor protection systems that initiate plant safety systems when selected unit parameters exceed specific values, to prevent violation of the reactor core and reactor coolant system (RCS) design limits and to mitigate accidents.

The FSAR Update Chapter 15 analyses are used to determine limiting values for ESFAS Functions, called safety analysis limits (SALs). SALs ensure that the reactor core and RCS boundary Safety Limits are not exceeded.

Safety Limits are defined in 10 CFR 50.36 as "limits upon important process variables that are found to be necessary to reasonably protect the integrity of certain of the physical barriers that guard against the uncontrolled release of radioactivity." Limiting trip setpoints (LTSPs) are the limiting setting for the channel trip setpoints considering all credible instrument errors associated with the instrument channel. LTSPs are established as the limiting value to which a channel must be reset at the conclusion of periodic testing to ensure that the Safety Limit is not exceeded if a design basis event occurs before the next periodic surveillance.

The NTSP can be equal to the LTSP or be more conservative to provide margin. Since a physical instrument channel cannot be set to an exact value, an as-left calibration tolerance is established.

The as-found tolerance is based on the expected errors between calibrations and is factored into the trip setpoint calculation.

These tolerances are double-sided around the NTSP.3.5 DCPP Setpoint Methodology The current setpoint methodology for DCPP is contained in WCAP-1 1082, Revision 6, which was submitted in PG&E Letter DCL-03-1 11, "License Amendment Request 03-12, Revision to Technical Specifications 3.3.1,'RTS Instrumentation,'

and 3.3.2, 'ESFAS Instrumentation,"'

dated September 12, 2003. WCAP-1 1082, Revision 6 was approved by the NRC for DCPP by Amendment No. 178 to Facility Operating License 6 Enclosure 1 PG&E Letter DCL-07-002 No. DPR-80 and Amendment No. 180 to Facility Operating License No. DPR-82 in letter "Issuance of Amendment Re: Revised Technical Specifications

3.3.1 'Reactor

Trip System (RTS) Instrumentation' and 3.3.2, 'Engineered Safety Features Actuation System (ESFAS)Instrumentation' (TAC Nos. MC0893 and M0894)," dated December 2, 2004.The methodology for calculating the revised Feedwater Isolation SG Water Level-High High (P-14) ESFAS NTSP and AV is the same as previously described in WCAP-1 1082, Revision 6, and approved in the related NRC Safety Evaluation dated December 2, 2004. In the WCAP-1 1082 methodology, the calculation of setpoint uncertainties is comprised of process effects and instrument loop uncertainty.

The allowance for process effects accounts for non-instrument effects such as process pressure variation and mid-deck plate pressure loss. These process effects are treated as biases and are combined algebraically.

Instrumentation loop uncertainties address the accuracies of instruments, such as the transmitter and the rack, which are independent and random accuracies.

The instrumentation loop uncertainties are statistically combined using the square-root-of-the-sum-of-the-squares (SRSS)technique.

The process effects considered for the RSG include mid-deck plate differential pressure (DP), intermediate deck plate DP, feedring DP, lower deck plate and supports DP, downcomer subcooling, fluid velocity effects, process pressure variation, reference leg temperature variation, void fraction above the mid-deck plate, and steam carryunder to ensure they are appropriately accounted for in the determination of Process Measurement Accuracy (PMA).For the Feedwater Isolation SG Water Level-High High (P-14) function, the NTSP is derived from the maximum reliable indicated level (MRIL)versus the SAL which is normally used. The MRIL is calculated for the level instrumentation based on the SAL for the Feedwater Isolation SG Water Level-High High (P-14) function assumed in the safety analysis.The NTSP is calculated as the MRIL minus the total allowance for the Feedwater Isolation SG Water Level-High High (P-14) function.

The total allowance consists of the channel statistical allowance plus margin. The results of these calculations for the Feedwater Isolation SG Water Level-High High (P-14) function are shown in Table 1 contained in Enclosure

8.7 Enclosure

1 PG&E Letter DCL-07-002 3.6 FSAR Update Chapter 15 Safety Analyses for SG Replacement All FSAR Update Chapter 15 safety analyses for the RSGs have been performed using NRC-approved analytical methods to demonstrate compliance with applicable acceptance criteria and standards and are evaluated under 10 CFR 50.59. Since these analyses were performed under 10 CFR 50.59, NRC approval of these revised safety analyses is not requested and this information is provided for information only.Events that credit a particular SG water level NTSP for consequence mitigation are analyzed to determine the physical effect of the event transient conditions with respect to each of the PMA terms and the overall impact on setpoint uncertainty.

The limiting event and associated setpoint uncertainty are identified and acceptable allowable margins are confirmed with respect to the effects of transient conditions.

The SG water level NR span is different between the existing SGs and RSGs due an expanded NR span being incorporated as part of the RSG design. The existing SGs have an SG water level NR span of 144 inches, while the RSGs have an SG water level NR span of 212 inches. The revised SG water level NR span has been incorporated into the FSAR Update Chapter 15 safety analyses for the RSGs.The SG Water Level-Low Low function is credited in the analyses of the loss of normal feedwater, small steam line break outside containment (for mass and energy), and feedwater line break events. Although the current SG Water Level-Low Low function TS values represent lower water levels in the RSGs compared to the existing SGs, this is accommodated in the RSG design by the location of the lower NR tap, the configuration of the SG tube bundle, and the revised FSAR Update Chapter 15 safety analyses.

Therefore, the TS values for SG Water Level-Low Low NTSP and AV are unchanged for the RSGs and no TS changes are required for the SG Water Level-Low Low NTSP and AV.The Feedwater Isolation SG Water Level-High High (P-14) function is credited in the analysis of the Excessive Heat Removal due to Feedwater System Malfunctions event. A change in SG feedwater conditions resulting in an increase in feedwater flow could result in excessive heat removal from the RCS. The limiting feedwater flow increase scenario is the full opening of a main feedwater control valve due to a feedwater control system malfunction or an operator error. Excessive heat removal causes a decrease in moderator temperature that increases core reactivity and can lead to an increase in power. Any unplanned power level increase may result in fuel damage or excessive reactor system pressure.8 Enclosure 1 PG&E Letter DCL-07-002 The increased flow into the affected SG leads to a Feedwater Isolation SG Water Level-High High (P-14) actuation.

The Excessive Heat Removal due to Feedwater System Malfunctions analysis for the RSGs assumed the Feedwater Isolation SG Water Level-High-High actuation occurs at 100 percent SG NR level, which is the same as the analysis for the existing SGs. Reactor protection and safety systems are actuated to mitigate the transient.

The closing of the main feedwater isolation valve or a main feedwater pump trip prevents SG overfill.

The acceptance criteria are based on critical heat flux not being exceeded, peak linear heat generation rate not exceeding a value that would cause centerline melt, and pressure in the RCS and main steam system (MSS) being maintained below 110 percent of the respective design pressures.

The Excessive Heat Removal due to Feedwater System Malfunctions analysis results demonstrate that the minimum departure from nucleate boiling is maintained above the SAL, that the maximum core thermal power remains below a value that would'result in fuel centerline melting, and that the peak RCS and MSS pressures are not challenged for this event.Based on the setpoint analysis for the Feedwater Isolation SG Water Level-High High (P-14) setpoint, the MRIL is 98.8 percent span, the NTSP is 90.0 percent span, and the AV is less than or equal to 90.2 percent span. The NTSP and AV values are different from the current TS Table 3.3.2-1 Function 5.b NTSP of 75 percent and AV of less than or equal to 75.2 percent. Therefore, revision to the Table 3.3.2-1 Function 5.b NTSP and AV is required as a result of SG Replacement.

4.0 TECHNICAL

ANALYSIS 4.1 TSTF-493, Revision 1, Changes This amendment request implements the guidance of TSTF-493, Revision 1, and the guidance contained in the NRC letter dated December 14, 2006, for ESFAS Function 5.b, Feedwater Isolation SG Water Level-High High (P-14). The applicable ESFAS Table notes contained in TSTF-493, Revision 1, are added to the SRs for this function.The addition of the TSTF-493, Revision 1, ESFAS Table notes to the SRs for this function is consistent with the guidance in RIS 2006-17. The addition of the TSTF-493, Revision 1, ESFAS Table notes to the SRs for this function ensures that the SAL assumed in the limiting FSAR Update Chapter 15 analysis crediting this function is met.9 Enclosure 1 PG&E Letter DCL-07-002 New Note (e) requires that the methodologies used to determine the as-found and the as-left tolerance are specified in the Equipment Control Guidelines (ECGs). PG&E will include the methodologies used to determine the as-found and the as-left tolerance (including the as-found and as-left tolerance values) in the ECGs, which is a 10 CFR 50.59 controlled document.

This is consistent with the proposed TS Bases for SR 3.3.2.5 and SR 3.3.2.9. The TS Bases changes to implement TSTF-493, Revision 1, for this function are contained in Enclosure 4 for information only.As described in TSTF-493, Revision 1, the NRC has determined seven concepts that need to be addressed to ensure that the instrument channels will function as required.

The concepts and how the DCPP setpoint methodology and implementation of the setpoint methodology satisfy those concepts are identified below: 1. The [L TSP] must be calculated consistent with the plant-specific methodology.

The [LTSP] is the expected value for the trip. The as-left and as-found values may be less conservative than the [LTSP]by predefined tolerances (which were factored into the trip setpoint calculation).

The LTSP is calculated consistent with the DCPP plant-specific methodology.

For DCPP, the NTSPs contained in TS Table 3.3.2-1 are more conservative than the LTSP, since they contain additional margin beyond the LTSP. The NTSP is the expected value for the trip and the as-left and as-found values are predefined tolerances, factored into the trip setpoint calculation, which may be less conservative than the NTSP. PG&E will develop the LTSP (SAL adjusted by the channel uncertainty) for ESFAS Function 5.b, Feedwater Isolation SG Water Level-High High (P-14). The LTSP for this function will be included in the ECGs, which is a 10 CFR 50.59 controlled document.2. The as-found trip setpoint must be verified to be within predefined double-sided limits that are based on the actual expected errors between calibrations.

Finding the as-found trip setpoint outside these limits warrants additional evaluation and potential corrective action, as necessary, to ensure continued performance of the specified safety function.

Normally, the as-found tolerance will be equivalent to the errors verified during the surveillance (e.g., Reference Accuracy (RA), drift, and measurement and test equipment (M&TE) accuracy/errors).

The as-found trip setpoint is verified to be within predefined double-sided limits that are based on the actual expected errors 10 Enclosure 1 PG&E Letter DCL-07-002 between calibrations.

Additional evaluation and potential corrective action, as necessary, is performed if the as-found trip setpoint is found outside the limits. New Note (d) in Table 3.3.2-1 and the TS Bases changes implement these requirements for DCPP.3. The Nominal Trip Setpoint must be reset or left within the as-left tolerance at the end of every surveillance that requires setpoint verification.

The ability to reset the setpoint represents continued confidence that the channel can perform its intended safety function.The as-left tolerance may include the reference accuracy, M&TE accuracy and readability uncertainties.

The NTSP is reset or left within the as-left tolerance at the end of every surveillance that requires setpoint verification.

New Note (e) in Table 3.3.2-1 and the TS Bases changes implement these requirements for DCPP.4. The Nominal Trip Setpoint may be set more conservative than the L TSP. If the Nominal Trip Setpoint is set more conservative than the L TSP, the as-found and as-left tolerances will be maintained around the more conservative Nominal Trip Setpoint The instrument channel setpoint may be set more conservative than the NTSP. If the instrument channel setpoint is set more conservative than the NTSP, the as-found and as-left tolerances will be maintained around the more conservative instrument channel setpoint.

New Note (e) in Table 3.3.2-1 and the TS Bases changes implement these requirements for DCPP.5. The Allowable Value (defined as the least conservative as-found surveillance value) defines the maximum possible value for process measurement at which the Analytical Limit is protected.

The Allowable Value verifies that the Analytical Limit and Safety Limit are still protected at the time of the surveillance.

Since OPERABILITY of the instrument channel is determined at the time of the surveillance performance, the fact that the tested trip point occurred conservative to the Allowable Value ensures that at that point in time the channel would have functioned to protect the Analytical Limit and is OPERABLE.

With the implementation of these concepts, calculation of the Allowable Value using any of the ISA S67.04 Part II methods is acceptable.

The Allowable Value is documented in the Technical Specifications and is in accordance with the normal rules of the Improved Standard Technical Specifications and is consistent with current practices.

11 Enclosure 1 PG&E Letter DCL-07-002 For DCPP, the AV is contained in the TS (defined as the least conservative as-found surveillance value) and defines the upper or lower limit for the instrument setting, beyond which the instrument is inoperable.

6. For those Westinghouse NSSS plants whose plant-specific Technical Specifications contain Allowable Value and Nominal Trip Setpoint columns, the Nominal Trip Setpoint identified in the Technical Specifications is expected to be the [NTSP] for the channel.Since the DCPP TS contain AV and NTSP columns, the instrument channel setpoint identified in TS is the NTSP. For DCPP, the NTSP is the LSSS for the Feedwater Isolation SG Water Level-High High (P-14)function channel.7. When a channel's as-found value is conservative to the Allowable Value but the setpoint is outside the as-found tolerance, the channel may be degraded and may not conform to the assumptions in the design basis calculation.

Prior to returning the channel to service, there shall be a determination utilizing available information to ensure that the channel can perform as expected.

For example, this determination may include an evaluation of magnitude of change per unit time, response of instrument for reset, previous history, etc., to provide confidence that the channel will perform its specified safety function.

This determination, combined with resetting the trip setpoint to within the as-left tolerance, permits the channel to be returned to service.When a channel's as-found value is conservative to the AV but the setpoint is outside the as-found tolerance, new Note (d) in Table 3.3.2-1 and the TS Bases changes for the applicable SRs provide that, prior to returning the channel to service, there shall be a determination utilizing available information to ensure that the channel can perform as expected.PG&E has reviewed TSTF-493, Revision 1, and concludes that the justifications presented in the TSTF are applicable to ESFAS Function 5.b, Feedwater Isolation SG Water Level-High High (P-14) and justify incorporation of the notes and actions for this function.12 Enclosure 1 PG&E Letter DCL-07-002

4.2 Feedwater

Isolation SG Water Level-High Higqh (P-14) Setpoint The Excessive Heat Removal due to Feedwater System Malfunctions analysis for the RSGs assumed the high-high SG water level trip occurs at 100 percent SG NR level span, which is the same as the analysis for the existing SGs. For the SG Water Level-High High setpoint analysis associated with the ESFAS Function 5.b, Feedwater Isolation SG Water Level-High High (P-14), for the Excessive Heat Removal due to Feedwater System Malfunctions event, the rack drift, MRIL, channel statistical allowance, total allowance, and margin are shown in Table 1.The NTSP is calculated by subtracting the total allowance (channel statistical allowance plus margin) for the channel from the MRIL. The proposed SG Water Level-High High NTSP of 90 percent is conservative with available margin. The proposed AV of less than or equal to 90.2 percent results in a margin between the AV and the SAL that exceeds the channel statistical allowance for the channel.The setpoint methodology used to determine the AV and NTSP for the Feedwater Isolation SG Water Level-High High (P-14) setpoint, based on the current NRC-approved WCAP-1 1082, Revision 6, setpoint methodology for DCPP, is equally conservative or more conservative than the NRC acceptable setpoint method contained in RIS 2006-17. The as-found tolerance as defined by RIS 2006-17 is a combination of rack calibration accuracy, rack measurement and test equipment uncertainty, and rack drift. The DCPP setpoint methodology for the as-found tolerance excludes the rack calibration accuracy and is therefore more conservative.

Both the RIS 2006-17 setpoint methodology and the DCPP setpoint methodology calculate the as-left tolerance using the rack calibration accuracy and are, therefore, equivalent.

4.3 TSTF-449 Changes TS 5.5.9 and TS 5.6.10 are revised to delete the existing SG tube ARC and associated reporting requirements.

The existing TS 5.5.9.b.1 reference to the ARC, the TS 5.5.9.b.1 structural integrity performance criteria for Tube Support Plate Voltage-Based Repair Criteria and Axial Primary Water Stress Corrosion Cracking (PWSCC) Depth-Based Repair Criteria, the TS 5.5.9.b.2 Tube Support Plate Voltage-Based Repair Criteria, W* Repair Criteria, and Axial PWSCC Depth-Based Repair Criteria, the TS 5.5.9.d tube inspection requirements for the ARC, and the TS 5.6.10.b through 5.6.10.g ARC reporting criteria, are deleted since they are not applicable to the RSGs. The TS 5.5.9 ARC were based on the configuration of the existing SGs, including the Alloy 600 mill annealed tubes, tube support plate design, and tube expansion in the tubesheet 13 Enclosure 1 PG&E Letter DCL-07-002 region. The RSGs have a different configuration than assumed during the development of the ARC, and the ARC are not valid for the RSGs.Therefore, removal of the TS 5.5.9 and TS 5.6.10 ARC-related requirements for the existing SGs is required.

Removal of the ARC requirements for the existing SGs will ensure that for the RSGs, all tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40 percent of the nominal tube wall thickness will be plugged as required by TS 5.5.9.c and SG Tube Integrity TS SR 3.4.17.2.

With the TS 5.6.10 changes, all reporting requirements required by TSTF-449, Revision 4, will continue to be met.For the proposed TS 5.5.9.b.2, for any design basis accident other than a SG tube rupture, the primary-to-secondary accident induced leakage will not be allowed to exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG, and leakage cannot exceed 1 gpm per SG. Removal of the ARC will reduce the primary-to-secondary accident induced leakage limit in the faulted SG following a main steam line break (MSLB) accident from 10.5 gpm to 1 gpm. The FSAR Update MSLB radiological consequences analysis assumes accident induced leakage up to 10.5 gpm in the faulted SG. However, this 10.5 gpm accident induced leakage limit can only be applied to the ARC degradation described in TS 5.5.9.c.1, TS 5.5.9.c.2, and TS 5.5.9.c.3.

With removal of ARC for the RSGs, the MSLB accident induced leakage limit for SG tube degradation cannot exceed 1 gpm per SG based on TS 5.5.9.b.2.

The revision of the TS 5.5.9.d.2 tube inspection criteria is made as a result of a new SG tube material for the RSGs. The current TS 5.5.9.d.2 tube inspection requirements apply to the existing SGs, which have Alloy 600 mill annealed tubes. The RSGs contain Alloy 690 thermally treated tubes, which are more resistant to corrosion.

The current TS 5.5.9.d.2 tube inspection criteria are replaced with those applicable to Alloy 690 thermally treated tubes based on TSTF-449, Revision 4. With the revised tube inspection criteria, the TS 5.5.9 SG structural integrity, accident-induced leakage, and operational leakage performance criteria will continue to be met for the RSGs. Meeting the SG performance criteria provides reasonable assurance that the SG tubes will remain capable of maintaining reactor coolant pressure boundary integrity throughout each operating cycle and in the unlikely event of a design basis accident.

With the revised SG tube inspection period, the SGs will continue to meet the SG program defined by NEI 97-06, "Steam Generator Program Guidelines," which incorporates a balance of prevention, inspection, evaluation, repair, and leakage monitoring.

The safety function of the SGs is maintained by ensuring the integrity of the tubes.14 Enclosure 1 PG&E Letter DCL-07-002 To support the TS 5.5.9 and 5.6.10 changes, PG&E has reviewed the safety evaluation (SE) published in the Federal Register on March 2, 2005 (70 FR 10298), as part of the TSTF-449 CLIIP Notice for Comment. This included the NRC staff's SE, the information provided to support TSTF-449, and the changes associated with Revision 4 to TSTF-449.PG&E has concluded that the justifications presented in the TSTF-449 SE prepared by the NRC staff regarding inspection intervals for Alloy 690TT SG tubes are applicable to the DCPP RSGs, and justify incorporation of the Alloy 690TT inspection interval in the DCPP TS for the RSGs.CONCLUSION Implementation of TSTF-493, Revision 1, which revises and clarifies the surveillance requirements associated with the Feedwater Isolation SG Water Level-High High (P-14) setpoint, will ensure that the instrumentation is operable and will actuate as assumed in the accident analysis.The setpoint methodology used to determine the AV and NTSP for the Feedwater Isolation SG Water Level-High High (P-14) function specified in TS 3.3.2, Table 3.3.2-1, Function 5.b, is based on the current NRC-approved WCAP-1 1082, Revision 6, setpoint methodology for DCPP, and is equally conservative or more conservative than the NRC acceptable setpoint method contained in RIS 2006-17. The revised AV of less than or equal to 90.2 percent and the revised NTSP of 90.0 percent provide acceptable margin to protect the SAL when considering uncertainties.

With the proposed TS 5.5.9 and 5.6.10 changes, the TS 5.5.9 SG structural integrity, accident induced leakage, and operational leakage performance criteria will continue to be met for the RSGs. Meeting the SG performance criteria provides reasonable assurance that the SG tubes will remain capable of maintaining reactor coolant pressure boundary integrity throughout each operating cycle and in the unlikely event of a design basis accident.

The removal of the ARC for the existing SGs will ensure that all tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40 percent of the nominal tube wall thickness will be plugged as required by existing TS 5.5.9.c. With the revised SG tube inspection period, the SGs will continue to meet the SG program defined by NEI 97-06, "Steam Generator Program Guidelines," that incorporates a balance of prevention, inspection, evaluation, repair, and leakage monitoring.

15 Enclosure 1 PG&E Letter DCL-07-002

5.0 REGULATORY

ANALYSIS 5.1 No Significant Hazards Consideration PG&E has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of Amendment," as discussed below: 1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?

Response:

No.The revised engineered safety feature actuation system (ESFAS) steam generator (SG) Water Level-High High feedwater isolation Nominal Trip Setpoint and Allowable Value have been determined using the existing setpoint methodology approved for Diablo Canyon Power Plant. The setpoint analysis for the replacement steam generators (RSGs) accounts for the setpoint uncertainties specific to the RSG design. The revised Feedwater Isolation SG Water Level-High High (P-14) Nominal Trip Setpoint and Allowable Value are applied using a conservative surveillance requirement methodology.

The function of the ESFAS instrumentation is unchanged.

The Feedwater Isolation SG Water Level-High High (P-14) ESFAS instrumentation will continue to function in a manner consistent with the plant design basis and satisfy all the requirements of the safety analyses.The probability and consequences of accidents previously evaluated in the Final Safety Analysis Report (FSAR) Update are not adversely affected because the revised Feedwater Isolation SG Water Level-High High (P-14) Nominal Trip Setpoint and Allowable Value continue to assure a conservative plant response to high SG level, consistent with the safety analyses and licensing basis.The proposed changes revise and clarify the surveillance requirements for ESFAS Function 5.b, Feedwater Isolation SG Water Level-High High (P-14). These changes ensure that this function will actuate as assumed in the safety analyses.The proposed changes to TS 5.5.9 delete the alternate repair criteria (ARC) for the existing SGs, incorporate tube inspection periods applicable to Alloy 690 thermally treated tubes, and delete the TS 5.6.10 reporting requirements for ARC. The TS 5.5.9 SG structural integrity, accident 16 Enclosure 1 PG&E Letter DCL-07-002 induced leakage, and operational leakage performance criteria will continue to be met for the RSGs. Meeting the SG performance criteria provides reasonable assurance that the SG tubes will remain capable of maintaining reactor coolant pressure boundary integrity throughout each operating cycle and in the unlikely event of a design basis accident.Removal of the ARC for the existing SGs will ensure that all tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40 percent of the nominal tube wall thickness will be plugged as required by TS 5.5.9.c. With the revised SG tube inspection period, the SGs will continue to meet the SG program defined by NEI 97-06, "Steam Generator Program Guidelines," which incorporates a balance of prevention, inspection, evaluation, repair, and leakage monitoring.

Removal of the ARC will reduce the allowable accident induced leakage following a main steam line break accident.

The proposed changes do not have any impact on the accident induced leakage assumed in the other design basis accidents.

The changes do not have any impact on the allowable SG operational leakage, allowable reactor coolant system activity, or the allowable SG secondary activity.The proposed changes will not affect the probability of any accident initiators.

There will be no degradation in the performance of, or an increase in the number of challenges imposed on, safety-related equipment assumed to function during an accident.

There will be no change to accident mitigation performance.

The proposed changes will not alter any assumptions or change any mitigation actions in the radiological consequence evaluations in the FSAR Update.Therefore the proposed changes do not involve a significant increase in the probability or consequences of an accident previously evaluated.

2. Does the proposed change create the possibility of a new or different accident from any accident previously evaluated?

Response:

No.The proposed changes will not affect the normal method of plant operation or create new methods of plant operation related to the Feedwater Isolation SG Water Level-High High (P-14) ESFAS setpoints.

The proposed changes to the Feedwater Isolation SG Water Level-High High (P-14) instrumentation surveillance requirements will provide assurance that the plant will operate within the limits assumed in the safety analyses.The assumptions made in the setpoint analyses for the Feedwater 17 Enclosure 1 PG&E Letter DCL-07-002 Isolation SG Water Level-High High (P-14) ESFAS instrument do not create any new accidents, accident initiators, or failure mechanisms.

The proposed changes, which delete the TS 5.5.9 ARC for the existing SGs, incorporate tube inspection periods for Alloy 690 thermally treated tubes in TS 5.5.9, and delete the ARC reporting requirements in TS 5.6.10, will not introduce any adverse changes to the plant design basis or postulated accidents resulting from potential tube degradation.

The primary-to-secondary leakage that may be experienced during all plant conditions will be monitored to ensure it remains within current safety analysis assumptions.

The proposed changes do not adversely affect the method of operation of the SGs or the primary or secondary coolant controls and do not impact other plant systems or components.

Therefore, the proposed changes do not create the possibility of a new or different accident from any accident previously evaluated.

3. Does the proposed change involve a significant reduction in a margin of safety?Response:

No.The FSAR Update Excessive Heat Removal due to Feedwater System Malfunctions event credits the Feedwater Isolation SG Water Level-High High (P-14) ESFAS instrumentation.

The safety analysis limit assumed for the Feedwater Isolation SG Water Level-High High (P-14) ESFAS instrumentation for this event has not changed for the safety analyses for the RSGs. None of the acceptance criteria for Excessive Heat Removal due to Feedwater System Malfunctions event are changed as a result of the revised Feedwater Isolation SG Water Level-High High (P-14) Nominal Trip Setpoint and Allowable Value. The instrument surveillance requirement changes for the Feedwater Isolation SG Water Level-High High (P-14) function ensure that the instrumentation will actuate as assumed in the safety analysis.The safety function of the SGs is maintained by ensuring the integrity of the tubes. SG tube integrity is a function of the design, environment, and the physical condition of the SG tubes. The proposed changes, which delete the TS 5.5.9 ARCs for the existing SGs, incorporate tube inspection periods for Alloy 690 thermally treated tubes in TS 5.5.9, and delete the ARC reporting requirements in TS 5.6.10, do not adversely impact the SG tube design or operating environment.

SG tube integrity will continue to be maintained by implementing the SG Program to manage SG tube inspection, assessment, and repair. The requirements established by the 18 Enclosure 1 PG&E Letter DCL-07-002 SG program are consistent with those in the applicable design codes and standards.

Therefore, the proposed changes do not involve a significant reduction in a margin of safety.Based on the above evaluation, PG&E concludes that the proposed changes present no significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and accordingly, a finding of "no significant hazards consideration" is justified.

5.2 Applicable

Re-qulatory Requirements/Criteria General Design Criterion (GDC) 13 requires that instrumentation shall be provided to monitor variables and systems over their anticipated ranges for normal operation, for anticipated operational occurrences, and for accident conditions as appropriate to assure adequate safety, including those variables and systems that can affect the fission process, the integrity of the reactor core, the reactor coolant pressure boundary, and the containment and its associated systems.GDC-20 requires that the protection system(s) shall be designed (1) to initiate automatically the operation of appropriate systems including the reactivity control systems, to assure that specified acceptable fuel design limits are not exceeded as a result of anticipated operational occurrences and (2) to sense accident conditions and to initiate the operation of systems and components important to safety.GDC-21 requires that the protection system(s) shall be designed for high functional reliability and testability.

GDC-22 through GDC-25 and GDC-29 require various design attributes for the protection system(s), including independence, safe failure modes, separation from control systems, requirements for reactivity control malfunctions, and protection against anticipated operational occurrences.

10 CFR 50.36 contains the regulatory requirements related to the content of TS for the prevention of accidents and mitigation of consequences of such accidents.

Pursuant to 10 CFR 50.36, TS are required to include items in five specific categories related to station operation.

Specifically, those categories include: (1) safety limits, limiting safety system settings (LSSSs), and limiting control settings; (2) LCOs; (3) SRs; (4) design features; and (5) administrative controls.19 Enclosure 1 PG&E Letter DCL-07-002 10 CFR 50.36 does not specify the particular requirements to be included in a plant TS, however; 10 CFR 50.36(c)(2)(ii) sets forth four criteria to be used in determining whether a LCO is required to be included in the TS for a certain item. These criteria are as follows: 1. Installed instrumentation that is used to detect, and indicate in the control room, a significant abnormal degradation of the reactor coolant pressure boundary.2. A process variable, design feature, or operating restriction that is an initial condition of a design basis accident or transient analysis that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.3. A structure, system, or component (SSC) that is part of the primary success path and which functions or actuates to mitigate a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.4. A SSC which operating experience or probabilistic risk assessment has shown to be significant to public health and safety.Federal regulation 10 CFR 50.55a(h) requires that the protection systems meet IEEE 279-1971.

IEEE 279-1971 requires that protection circuits must be able to withstand both an input failure to the control system, which may then require the protection function actuation, and a single failure in the other channels providing the protection function actuation, and that a single failure will neither cause nor prevent the protection function actuation.

The changes proposed by this LAR will result in no changes to the ESFAS instrumentation design such that compliance with any of the regulatory requirements discussed above will be affected.

The proposed amendment will revise the Feedwater Isolation SG Water Level-High High (P-14) Nominal Trip Setpoint and Allowable Value to assure continued compliance with the above regulations.

The regulatory requirements applicable to SG integrity are discussed in Section 5.2 of TSTF-449, Revision 4. The proposed changes to TS 5.5.9 and 5.6.10 in this amendment request are in compliance with these requirements.

20 Enclosure 1 PG&E Letter DCL-07-002 In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.6.0 ENVIRONMENTAL CONSIDERATION PG&E has evaluated the proposed amendment and has determined that it does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure.

Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9).

Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

7.0 REFERENCES

7.1 References

1. NRC Regulatory Issue Summary 2006-17, "NRC Staff Position on the Requirements of 10 CFR 50.36, 'Technical Specifications,'

Regarding Limiting Safety System Settings During Periodic Testing and Calibration of Instrument Channels," dated August 24, 2006.2. Technical Specification Task Force (TSTF) Traveler TSTF-493, Revision 1, "Clarify Application of Setpoint Methodology for LSSS Functions," dated October 2, 2006.3. NRC Letter, "TSTF Traveler 493, Revision 1, 'Clarify Application of Setpoint Methodology for LSSS Functions' Docket No: PROJ0753, TAC MD3180 Docket No: PROJ0753, TAC #MD3180," dated December 14, 2006.4. WCAP-1 1082, Revision 6, "Westinghouse Setpoint Methodology for Protection Systems, Diablo Canyon Units 1 & 2, 24 Month Fuel Cycle Evaluation," (Proprietary) dated February 2003.5. NRC Letter, "Issuance of Amendment Re: Revised Technical Specifications

3.3.1 'Reactor

Trip System (RTS) Instrumentation' and 3.3.2, 'Engineered Safety Features Actuation System (ESFAS)21 Enclosure 1 PG&E Letter DCL-07-002 Instrumentation' (TAC Nos. MC0893 and TAC No. M0894)," dated December 2, 2004.6. NRC Notice for Comment: Notice of Opportunity to Comment on Model Safety Evaluation on Technical Specification Improvement to Modify Requirements Regarding the Addition of LCO 3.4.[17] on Steam Generator Tube Integrity Using the Consolidated Line Item Improvement Process, 70 FR 10298, March 2, 2005.7. Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler TSTF-449, Revision 4, "Steam Generator Tube Integrity," April 14, 2005.8. NRC Notice of Availability of Model Application:

Improvement to Modify Requirements Regarding Steam Generator Tube Integrity:

Using the Consolidated Line Item Improvement Process, 70 FR 24126, May 6, 2005.9. PG&E Letter DCL-06-061, License Amendment Request 06-04,"Application for TS Improvement Regarding SG Tube Integrity (TSTF-449)," May 30, 2006.10. PG&E Letter DCL-06-130, "Response to NRC Request for Additional Information Regarding License Amendment Request 06-04, 'Application for TS Improvement Regarding SG Tube Integrity (TSTF-449),"'

November 22, 2006.11. NEI 97-06, Revision 2, "Steam Generator Program Guidelines," May 2005.12. Union Electric Company, License Amendment Request ULNRC-05056, "TS Revisions Associated with the SG Replacement Project," dated September 17, 2004.13. NRC letter "Callaway Plant, Unit 1 -Issuance of Amendment Regarding the Steam Generator Replacement Project (TAC No.MC4437)," dated September 29, 2005.7.2 Precedent The changes revise and clarify the surveillance requirements associated with the revised setpoints to address current NRC issues with setpoints.

The same approach was used by Union Electric Company in LAR ULNRC-05056, "TS Revisions Associated with the SG Replacement 22 Enclosure 1 PG&E Letter DCL-07-002 Project," dated September 17, 2004, and approved by the NRC for Callaway Unit 1 in Amendment 168 to Facility Operating License No. NPF-30, dated September 29, 2005.23 Enclosure 2 PG&E Letter DCL-07-002 Proposed Technical Specification Changes (marked-up)

ESFAS Instrumentation

3.3.2 Table

3.3.2-1 (page 5 of 7)Engineered Safety feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL (a)SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT 5. Feedwater Isolation (continued)

b. SG Water 1,2G) 3 p~erSG J SR 3.3.2.1 <_ 7.5-,%Level-High SR 3.3.2.5 W() ,7, , High (P-14) SR 3.3.2.9 (1) (e)SR 3.3.2.10 c. Safety Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

Injection 6. Auxiliary Feedwater a. Manual 1,2,3 1 sw/pp N SR 3.3.2.13 NA NA b. Automatic 1,2,3 2 trains G SR 3.3.2.2 NA NA Actuation SR 3.3.2.4 Logic and SR 3.3.2.6 Actuation Relays (Solid State Protection System)c. Not used d.1SG Water 1,2,3 3 perSG D SR 3.3.2.1 _ 14.8% 15.0%Level-Low Low SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 (continued)(a) A channel is OPERABLE with an actual Trip Setpoint value outside its calibration tolerance band provided the Trip Setpoint value is conservative with respect to its associated Allowable Value and the channel is re-adjusted to within the established calibration tolerance band of the Nominal Trip Setpoint.

A Trip Setpoint may be set more conservative than the Nominal Trip Setpoint as necessary in response to plant conditions.(j) Except when all MFIVs, MFRVs, and associated bypass valves are closed and de-activated or isolated by a closed manual valve.I DIABLO CANYON -UNITS 1 & 2 dbccontent.dll

-R14 35 3.3-31 Unit 1 -Amendment No. 4-95, 4-7-3, 1-7-81 Unit 2 -Amendment No. 4-35, 1-7-5,-1-8 Technical Specification Inserts Table 3.3.2-1 Insert 1 If the as-found channel setpoint is conservative with respect to the Allowable Value but outside its predefined as-found acceptance criteria band, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. If the as-found instrument channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable.

Footnote (a) does not apply to this function.Insert 2 The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable.

Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures to confirm channel performance.

The methodologies used to determine the as-found and the as-left tolerance are specified in the Equipment Control Guidelines.

Footnote (a)does not apply to this function.

Programs and Manuals 5.5 5.5 Programs and Manuals (continued)

5.5.9 Steam

Generator (SG) Program K A Steam Generator Program shall be established and implemented to ensure that SG 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 SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging of tubes.Condition monitoring assessments shall be conducted during each outage during which the SG tubes are inspected or plugged to confirm that the performance criteria are being met.b. Performance criteria for SG tube integrity.

SG 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 f~ull power operation prima ry-to-seconda ry pressure differential and fexcept for flaw's"-f'-addressed through application of the alternate repair criteria discsein Specification 5.5.9. c. 1 a!nd 5.5.9. c.3, asftyar of 1.4 against burst applied to the design basis acci en 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.W/hen alternate repair criteria discussed in peciica-n 5.5.9.co.1 ared)applied to axially-oriented outside diameter stress corrosion cracking indications at tube support plate locations, the probability that one or more of these indications in a SG will burst under postulated main steam line break conditions shall be less than l1X10-2. I-(continued)

DIABLO CANYON -UNITS 1 & 2 5.0-10 Unit 1 -Amendment No.Unit 2 -Amendment No.

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued)

Sapplied to axial ly-oriented primary water stress corrosion cracking -

at tube support plate locations, the probability that one or Jmore of these- indications-in a- S-G will burs-t under postulated-main s-te-am...line break conditions shall be less than l1X10-,2.2. Accident induced leakage performance criterion:

The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and,.. r-leakage rate f an individual SG. Except during-a .rupture, leaka~~rom all source excluding te leakage attributed to e degradation described in Specification 5.5.9.c.1, 5.5.9.c.2, and 5.5.9.c.3, is also not to exceed 1 gallon per minute per SG.3. The operational LEAKAGE performance criterion is specified in LCO 3.4.13, "RCS Operational LEAKAGE." (continued)

DIABLO CANYON -UNITS 1 & 2 5.0-11 Unit 1 -Amendment No.Unit 2 -Amendment No.

Programs-andManuals-, 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Proqram (continued)

c. Provisions for SG tube repair criteria.Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged.The following alternate tube repair criteria-may be applied as an alternative to the .-40% depth based criteria: 1 .Tube Support Plate Voltage-Based Repair Criteria The tube support plate voltage-based repair criteria are used for the disposition of an alloy 600 steam generator tube for continued service that is experiencing predominantly axially oriented outside diameter stress corrosion cracking confined within the thickness of the tube support plates. At tube support plate intersections, the repair criteria is described below: a. Steam generator tubes, whose degradation is attributed to outside diameter stress corrosion cracking within the bounds of the tube support plate with bobbin voltages less than or equal to 2.0 volts, will be allowed to remain in service.b. Steam generator tubes, whose degradation is attributed to outside diameter stress corrosion cracking within the bounds of the tube support plate with a bobbin voltage greater than 2.0 volts, will be plugged, except as noted in 5.5.9.c.1.c below.c. Steam generator tubes, with indication of potential degradation attributed to outside diameter stress corrosion cracking within the bounds of the tube support plate with a bobbin voltage greater than 2.0 volts but less than or equal to the upper voltage repair limit (calculated according to the methodology in Generic Letter 95-05 as supplemented), may remain in service if a rotating pancake coil inspection or comparable inspection technique does not detect degradation.

Steam generator tubes, with indications of outside diameter stress corrosion cracking degradation with a bobbin voltage greater than the upper voltage repair limit will bebe plugged.d. Certain intersections as identified in PG&E Letter DCL-03-174,I dated December 19, 2003, will be excluded from application of the voltage-based repair criteria as it is determined that these intersections may collapse or deform following a postulated LOCA+ SSE event.(continued)

DIABLO CANYON -UNITS 1 & 2 5.0-12 Unit 1 -Amendment No.Unit 2 -Amendment No.

Programs and Manuals 5.5 5.5 Programs and Manuals R Q qtzm f (tS/G Pron mm (c.ntinueid_

e f. A tube which contains a tube support plate intersection with both an axial ODSCC indication and an axial PWSCC indication will be plugged.If an unscheduled mid-cycle inspection is performed, the following mid-cycle repair limits apply instead of the limits identified in 5.5.9.c.1.a, 5.5.9.c.1.b, and 5.5.9.c.1.c.

The mid-cycle repair limits are determined from the following equations:

K K>VSL VMURL =1.0 + NDE + Gr (CL -At)CL VMLRL = VMURL -(VuL- V (,) (CL -At)CL where: VURL -upper voltage repair limit VLRL = lower voltage repair limit VMURL = mid-cycle upper voltage repair limit based on time into cycle VMLRL = mid-cycle lower voltage repair limit based on VMURL and time into cycle At = length of time since last scheduled inspection during which VURL and VLRL were implemented CL = cycle length (the time between two scheduled steam generator inspections)

VSL = structural limit voltage Gr = average growth rate per cycle length NDE = 95% cumulative probability allowance for nondestructive examination uncertainty (i.e., a value of 20% has been approved by the NRC)Implementation of these mid-cycle repair limits should follow the same approach as in TS 5.5.9.c.1.a, 5.5.9.c.l.b, and 5.5.9.c.l.c.

[A-(continued)

DIABLO CANYON -UNITS 1 & 2 5.0-13 Unit 1 -Amendment No.Unit 2 -Amendment No.

Programs and Manuals 5.5 5.5 Programs and Manuals K 1K 5.5.9 Steam Genera 2.itor (SG) Program (continued)

W* Repair Criteria The W* repair criteria are used for disposition of an alloy 600 steam generator tube for continued service that is experiencing predominately axially oriented inside diameter stress corrosion cracking confined within the hot leg tubesheet, below the bottom of the WEXTEX transition (BWT). As used in this specification:

a. Bottom of WEXTEX Transition (BWT) is the highest point of contact between the tube and tubesheet at, or below the top-of-tubesheet as determined by eddy current testing.b. W* Length is the distance in the hot leg tubesheet below the BWT that precludes tube pull out in the event of the complete circumferential separation of the tube below the W* length. The W* length is conservatively set at an undegraded hot leg tube length of 5.2 inches for Zone A tubes and 7.0 inches for Zone B tubes. Information provided in WCAP-14797-P, Revision 2, defines the boundaries of Zone A and Zone B.K" IA c. Flexible W* Length is the W* length adjusted for any cracks found within the W* region. The Flexible W* Length is the total rotating pancake coil (RPC) inspected length as measured downward from the BWT, and includes NDE uncertainties and crack lengths within W* as adjusted for growth.d. W* Tube is a tube with degradation within or below the W* length that is left in service, and degraded within the limits specified in Specification 5.5.9.c.2.e.

1--1 (continued)

DIABLO CANYON -UNITS 1 & 2 5.0-14 Unit 1 -Amendment No.Unit 2 -Amendment No.

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Progqram (continued)

e. Within the hot leg tubesheet, the repair criteria is described below: 1. For tubes to which the W* criteria are applied, the length of non-degraded tube below BWT shall be greater than or equal to the W* length plus NDE uncertainties and crack growth for the operating cycle.2. Axial cracks in tubes returned to service using W* shall ha'Ve Lhle UpprI i Lip IJIUp b IeIo DVV I ILby aL IteaL Lhle NDE measurement uncertainty and crack growth allowance, such that at the end of the subsequent operating cycle the entire crack remains below the BWT.3. Resolvable, single axial indications (multiple indications must return to the null point between individual cracks)within the flexible W* length can be left in service.Alternate RPC coils or an ultrasonic test (UT) inspection can be used to demonstrate return to null point between multiple axial indications or the absence of circumferential involvement between axial indications.
4. Tubes with inclined axial indications less than 2.0 inches long (including the crack growth allowance) having inclination angles relative to the tube axis of < 45 degrees minus the NDE uncertainty, ANDECA, on the measurement of the crack angle can be left in service. Tubes with two or more parallel (overlapping elevation), inclined axial cracks shall be plugged. For application of the 2.0 inch limit, an inclined indication is an axial crack that is visually inclined on the RCP C-scan, such that an angular measurement is required, and the measured angle exceeds the measurement uncertainty of ANDECA.I I 5. Circumferential, volumetric, and axial indications with inclination angles greater than (45 degrees -ANDEcA)within the flexible W* length shall be plugged.I 6.Any type or combination of tube degradation below the flexible W* length is acceptable.(continued)

DIABLO CANYON -UNITS 1 & 2 5.0-15 Unit 1 -Amendment No.Unit 2 -Amendment No.

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued)

K 3. Axial Primary Water Stress Corrosion Cracking (PWSCC) Depth-Basec K I Repair Criteria The axial PWSCC depth-based repair criteria are used for disposition of axial PWSCC indications, or portions thereof, which are located within the thickness of dented tube support plates which exhibit a maximum depth greater than or equal to 40 percent of the initial tube wall thickness.

WCAP-1 5573, Revision 1, provides repair limits applicable to these intersections.

A tube which contains a tube support plate intersection with both an axial ODSCC indication and an axial PWSCC indication will be plugged. K d. Provisions for SG tube inspections.

Periodic SG 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 tupe-to-tubesheet weld at the tube outlet, and that may satisfy the applicable tubeR5-pair criteria.

The tube-to-tubesheet weld is not part of the tubeA/n addition to meeting the requirements of d.1, d.2,d.3 .an below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG 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 SG during the first refueling outage following SG replacement.

J 2. rInspect 100% of the tubes at sequential periods of 60 effective full power months. The first sequential period shall be considered to begin after the S.-,first inservice inspection of the SGs. No SG shall operate for more than 24 effective full power months or one refueling outage (whichever is less)Iwithout insJetd,," 3. If crack indications are found in any SG tube, then the next inspection for each SG 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)

DIABLO CANYON -UNITS 1 & 2 5.0-16 Unit 1 -Amendment No.Unit 2 -Amendment No.

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued) 4.Indications left in service as a result of application of the tube support plate voltage-based repair criteria in Specification 5.5.9.c.1 shall be inspected by bobbin coil probe every 24 effective full power months or one refueling outage, whichever is less.K Implementation of the steam generator tube support plate voltage-based repair criteria in Specification 5.5.9.c.1 requires a 100% bobbin coil inspection for hot-leg and cold-leg support plate intersections down to the lowest cold-leg tube support plate with known outside diameter stress corrosion cracking (ODSCC) indications.

The determination of the lowest cold-leg tube support plate intersection having ODSCC indications shall be based on the performance of at least a 20% random sampling of tubes inspected over their full length.5. Tubes identified as W* tubes having a previously identified indication within the flexible W* length shall be inspected using an RPC probe or equivalent for the full length of the W* region every 24 effective full power months or one refueling outage, whichever is less.Implementation of the W* repair criteria in Specification 5.5.9.c.2 requires a 100 percent RPC probe or equivalent inspection of the hot leg tubesheet Flexible W* Length, or 8 inches below the hot leg top of tubesheet, whichever is bounding.6. Inspection of dented tube support plate intersections will be performed in accordance with WCAP-15573, Revision 1, to implement axial PWSCC depth-based repair criteria in Specification 5.5.9.c.3.

The extent of required inspection is: LA-K a. 100 percent bobbin coil inspecti intersections.

b. Plus Point coil inspection of all TSP intersections.
c. Plus Point coil inspection of all service.r on of all tube support plate (TSP)bobbin coil indications at dented prior PWSCC indications left in/(continued)

DIABLO CANYON -UNITS 1 & 2 5.0-17 Unit 1 -Amendment No.Unit 2 -Amendment No.

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued)

[-a--11*-d. If bobbin coil is relied upon for detection of axial PWSCC in less than or equal to 2 volt dents, then on a SG basis perform Plus Point coil inspection of all TSP intersections having greater than 2 volt dents up to the highest TSP for which PWSCC has been detected in the prior two inspections or current inspection and 20% of greater than 2 volt dents at the next higher TSP. If a circumferential indication is detected in a dent of "x" volts in the prior two inspections or current inspection, Plus Point inspections will be conducted on 100% of dents greater than "x -0.3" volts up to the affected TSP elevation in the affected SG, plus 20% of dents greater than "x -0.3" volts at the next higher TSP. "x" is defined as the lowest dent voltage where a circumferential crack was detected.e. If bobbin coil is not relied upon for detection of axial PWSCC in less than or equal to 2 volt dents, then on a SG basis perform Plus Point coil inspection of all dented TSP intersections (no lower dent voltage threshold) up to the highest TSP for which PWSCC has been detected in the prior two inspections or current inspection and 20% of all dents at the next higher TSP.f. For any 20% dent sample, a minimum of 50 dents at the TSP elevation shall be inspected.

If the population of dents is less than 50 at the TSP elevation, then 100% of the dents at the TSP elevation shall be inspected.

e. Provisions for monitoring operational primary to secondary LEAKAGE.r r DIABLO CANYON -UNITS 1 & 2 5.0-18 Unit 1 -Amendment No.Unit 2 -Amendment No.

Technical Specification Inserts Section 5.5.9 Insert 1 Inspect 100% of the tubes at sequential periods of 144, 108, 72, and, thereafter, 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outage nearest the end of the period. No SG shall operate for more than 72 effective full power months or three refueling outages (whichever is less) without being inspected.

Programs and Manuals 5.5 THIS DIABLO CANYON -UNITS 1 & 2 5.0-19 Unit 1 -Amendment No.Unit 2 -Amendment No.

T t r e o6- &~ L Y e:k1 04- 1AA 1 ( "" , 4-hL3 Per wi( L'e re tj 0~e Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.10 Secondary Water Chemistry Progqram This program provides controls for monitoring secondary water chemistry to inhibit SG tube degradation.

The program shall include: a. Identification of a sampling schedule for the critical variables and control points for these variables;

b. Identification of the procedures used to measure the values of the critical variables;
c. Identification of process sampling points, which shall include monitoring the discharge of the condensate pumps for evidence of condenser in leakage;d. Procedures for the recording and management of data;e. Procedures defining corrective actions for all off control point chemistry conditions; and f. A procedure identifying the authority responsible for the interpretation of the data and the sequence and timing of administrative events, which is required to initiate corrective action.5.5.11 Ventilation Filter Testinq Proaram (VFTP)A program shall be established to implement the following required testing of Engineered Safety Feature (ESF) filter ventilation systems at the frequencies specified below and in accordance with Regulatory Guide 1.52, Revision 2, ANSI N510 1980, and ASTM D3803-1989.
a. Demonstrate for each of the ESF systems that an in-place test of the high efficiency particulate air (HEPA) filters shows a penetration and system bypass< 1.0% when tested in accordance with ANSI N510-1980 at the system flowrate specified below +/- 10% at least once per 24 months.ESF Ventilation System Control Room Auxiliary Building Fuel Handling Building Flowrate 2100 cfm 73,500 cfm 35,750 cfm b. Demonstrate for each of the ESF systems that an in-place test of the charcoal adsorber shows a penetration and system bypass < 1.0% when tested in accordance with ANSI N510-1980 at the system flowrate specified below +/- 10%at least once per 24 months.ESF Ventilation System Flowrate Control Room Auxiliary Building Fuel Handling Building 2100 cfm 73,500 cfm 35,750 cfm (continued) 5.0-20 Unit 1 -Amendment No. 4-35 142 Unit 2 -Amendment No. 1-35 142 DIABLO CANYON -UNITS 1 & 2
e. "Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Ventilation Filter Testing Program (VFTP) (continued)
c. Demonstrate for each of the ESF systems that a laboratory test of a sample of the charcoal absorber, when obtained as described in Regulatory Guide 1.52, Revision 2, shows the methyl iodide penetration less than the value specified below when tested in accordance with ASTM D3803-1989 at a temperature of 30 0 C and at the relative humidity specified below. Laboratory testing shall be completed at least once per 24 months and after every 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of charcoal operation.

ESF Ventilation System Penetration RH Control Room 2.5% 95%Auxiliary Building 15.0% 95%Fuel Handling Building 15.0% 95%d. Demonstrate for each of the ESF systems that the pressure drop across the combined HEPA filters and the charcoal adsorbers is less than the value specified below when tested in accordance with ANSI N510-1980 at the system flowrate specified below +/- 10% at least once per 24 months.ESF Ventilation System Delta P Flowrate Control Room 3.5 in. WG 2100 cfm Auxiliary Building 3.7 in. WG 73,500 cfm Fuel Handling Building 4.1 in. WG 35,750 cfm The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the VFTP test frequencies.

5.5.12 Explosive Gas and Storage Tank Radioactivity Monitoring Program This program provides controls for potentially explosive gas mixtures contained in the Waste Gas Holdup System, the quantity of radioactivity contained in gas storage tanks, and the quantity of radioactivity contained in temporary unprotected outdoor liquid storage tanks.The gaseous radioactivity quantities shall be determined following the methodology in Regulatory Guide 1.24 "Assumptions Used For Evaluating the Potential Radiological Consequences of a Pressurized Water Reactor Radioactive Gas Storage Tank Failure." The liquid radwaste quantities shall be maintained such that 10 CFR Part 20 limits are met.(continued)

DIABLO CANYON -UNITS 1 & 2 5.0-21 Unit 1 -Amendment No. 4-5 442,163 Unit 2 -Amendment No. 4-35 442,165 Programs and Manuals e.5.5 P-.~I -e e~ e 5.5 Programs and Manuals 5.5.12 Explosive Gas and Storage Tank Radioactivity Monitoring Program (continued)

The program shall include: a. The limits for concentrations of hydrogen and oxygen in the Waste Gas Holdup System and a surveillance program to ensure the limits are maintained.

Such limits shall be appropriate to the system's design criteria (i.e., whether or not the system is designed to withstand a hydrogen explosion);

b. A surveillance program to ensure that the quantity of radioactivity contained in each gas storage tank is less than the amount that would result in a whole body exposure of >_ 0.5 rem to any individual in an unrestricted area, in the event of an uncontrolled release of the tanks' contents; and c. A surveillance program to ensure that the quantity of radioactivity contained in temporary outdoor liquid radwaste tanks that are not surrounded by liners, dikes, or walls, capable of holding the tanks' contents and that do not have tank overflows and surrounding area drains connected to the Liquid Radwaste Treatment System is less than the amount that would result in concentrations less than the limits of 10 CFR 20, Appendix B, Table II, Column 2, at the nearest potable water supply and the nearest surface water supply in an unrestricted area, in the event of an uncontrolled release of the tanks' contents.The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Explosive Gas and Storage Tank Radioactivity Monitoring Program surveillance frequencies.

5.5.13 Diesel Fuel Oil Testing Program A diesel fuel oil testing program to implement required testing of both new fuel oil and stored fuel oil shall be established.

The program shall include sampling and testing requirements, and acceptance criteria, all in accordance with applicable ASTM Standards.

The purpose of the program is to establish the following:

a. Acceptability of new fuel oil for use prior to addition to storage tanks by determining that the fuel oil has: 1. an API gravity or an absolute specific gravity within limits, 2. a flash point and kinematic viscosity within limits for ASTM 2D fuel oil, and 3. a clear and bright appearance with proper color; or water and sediment content within limits.b. Other properties for ASTM 2D fuel oil are analyzed within 31 days following sampling and addition to storage tanks; and c. Total particulate concentration of the fuel oil is ___ 10 mg/I when tested every 31 days in accordance with ASTM D-2276, Method A.d. The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Diesel Fuel Oil Testing Program test frequencies.

DIABLO CANYON -UNITS 1 & 2 5.0-22 Unit 1 -Amendment No. 135 Unit 2 -Amendment No. 135 Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.14 Technical Specifications (TS) Bases Control Proqram This program provides a means for processing changes to the Bases of these Technical Specifications.

a. Changes to the Bases of the TS shall be made under appropriate administrative controls and reviews.b. Licensees may make changes to Bases without prior NRC approval provided the changes do not require either of the following:
1. a change in the TS incorporated in the license; or 2. a change to the updated FSAR or Bases that requires NRC approval pursuant to 10 CFR 50.59.c. The Bases Control Program shall contain provisions to ensure that the Bases are maintained consistent with the FSAR.d. Proposed changes that meet the criteria of Specification 5.5.14b above shall be reviewed and approved by the NRC prior to implementation.

Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71(e).5.5.15 Safety Function Determination Program (SFDP)This program ensures loss of safety function is detected and appropriate actions taken.Upon entry into LCO 3.0.6, an evaluation shall be made to determine if loss of safety function exists. Additionally, other appropriate actions may be taken as a result of the support system inoperability and corresponding exception to entering supported system Condition and Required Actions. This program implements the requirements of LCO 3.0.6. The SFDP shall contain the following:

a. Provisions for cross train checks to ensure a loss of the capability to perform the safety function assumed in the accident analysis does not go undetected;
b. Provisions for ensuring the plant is maintained in a safe condition if a loss of function condition exists;c. Provisions to ensure that an inoperable supported system's Completion Time is not inappropriately extended as a result of multiple support system inoperabilities; and d. Other appropriate limitations and remedial or compensatory actions.A loss of safety function exists when, assuming no concurrent single failure, a safety function assumed in the accident analysis cannot be performed.

For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and: a. A required system redundant to the system(s) supported by the inoperable support system is also inoperable; or l Y JO, (continued)

DIABLO CANYON -UNITS 1 & 2 5.0-23 Unit 1 -Amendment No. 4-35, 145 Unit 2 -Amendment No. 4,35, 144 rograms and Manuals 5.5 5.5 Programs and Manuals 5.5.15 Safety Function Determination Program (SFDP) (continued)

b. A required system redundant to the system(s) in turn supported by the inoperable supported system is also inoperable; or c. A required system redundant to the support system(s) for the supported systems (a) and (b) above is also inoperable.

The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered.5.5.16 Containment Leakage Rate Testing Program a. A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions.

This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program, dated September 1995." The ten-year interval between performance of the integrated leakage rate (Type A) test, beginning May 4, 1994, for Unit 1 and April 30, 1993, for Unit 2, has been extended to 15 years.b. The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 47 psig.c. The maximum allowable containment leakage rate, La, at Pa, shall be 0.10% of containment air weight per day.d. Leakage rate acceptance criteria are: 1. Containment overall leakage rate acceptance criterion is < 1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are < 0.60 La for the Type B and Type C tests and < 0.75 La for Type A tests;2. Air lock testing acceptance criteria are: a) Overall air lock leakage rate is < 0.05 La when tested at _> Pa.b) For each door, leakage rate is < 0.01 La when pressurized to > 10 psig.e. The provisions of SR 3.0.2 do not apply to the test frequencies specified in the Containment Leakage Rate Testing Program.f. The provisions of SR 3.0.3 are applicable to the Containment Leakage Rate Testing Program.(continued)

DIABLO CANYON -UNITS 1 & 2 5.0-24 Unit 1 -Amendment No. 445, 45, 172 Unit 2 -Amendment No. 4-35, 4-50, 174 Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.17 Battery Monitoring and Maintenance Program This Program provides for restoration and maintenance, based on the recommendations of IEEE Standard 450, "IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented Lead-Acid Batteries for Stationary Applications," or of the battery manufacturer, of the following:

a. Actions to restore battery cells with float voltage < 2.13 V, and b. Actions to equalize and test battery cells that have been discovered with electrolyte level below the top of the plates.DIABLO CANYON -UNITS 1 & 2 5.0-24a Unit 1 -Amendment No. 172 Unit 2 -Amendment No. 174 Reporting Requirements 5.6 5.0 ADMINISTRATIVE CONTROLS 5.6 Reporting Requirements The following reports shall be submitted in accordance with 10 CFR 50.4.5.6.1 Not Used 5.6.2 Annual Radiological Environmental Operatinq Report--------------------------------

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

A single submittal may be made for a multiple unit station. The submittal should combine sections common to all units at the station.The Annual Radiological Environmental Operating Report covering the operation of the unit during the previous calendar year shall be submitted by May 1 of each year. The report shall include summaries, interpretations, and analyses of trends of the results of the radiological environmental monitoring program for the reporting period. The material provided shall be consistent with the objectives outlined in the Offsite Dose Calculation Manual (ODCM), and in 10 CFR 50, Appendix I, Sections IV.B.2, IV.B.3, and IV.C.The Annual Radiological Environmental Operating Report shall include the results of analyses of all radiological environmental samples and of all environmental radiation measurements taken during the period pursuant to the locations specified in the table and figures in the ODCM, as well as summarized and tabulated results of these analyses and measurements in a format similar to the table in the Radiological Assessment Branch Technical Position, Revision 1, November 1979. In the event that some individual results are not available for inclusion with the report, the report shall be submitted noting and explaining the reasons for the missing results. The missing data shall be submitted in a supplementary report as soon as possible.(continued)

DIABLO CANYON -UNITS 1 & 2 5.0-25, Unit 1 -Amendment No. 4--&, 180 Unit 2 -Amendment No. 4-&5,182 TReporting Requirements e- e5.6 5.6 Reporting Requirements (continued)

5.6.3 Radioactive

Effluent Release Report--------------------------------------------

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

A single submittal may be made for a multiple unit station. The submittal shall combine sections common to all units at the station; however, for units with separate radwaste systems, the submittal shall specify the releases of radioactive material from each unit.The Radioactive Effluent Release Report covering the operation of the unit during the previous year shall be submitted prior to May 1 of each year in accordance with 10 CFR 50.36a. The report shall include a summary of the quantities of radioactive liquid and gaseous effluents and solid waste released from the unit. The material provided shall be consistent with the objectives outlined in the ODCM and Process Control Program and in conformance with 10 CFR 50.36a and 10 CFR 50, Appendix I, Section IV.B.1.5.6.4 Not Used 5.6.5 CORE OPERATING LIMITS REPORT (COLR)a. Core operating limits shall be established prior to each reload cycle, or prior to any remaining portion of a reload cycle, and shall be documented in the COLR for the following:

1. Shutdown Bank Insertion Limits for Specification 3.1.5, 2. Control Bank Insertion Limits for Specification 3.1.6, 3. Axial Flux Difference for Specification 3.2.3, 4. Heat Flux Hot Channel Factor, K(Z) and W(Z) -FQ(z) (FQRTP Specification 3.2.1), 5. RCS Flow Rate and Nuclear Enthalpy Rise Hot Channel Factor -FAN (FRTPAH and PFAH for Specification 3.2.2), 6. SHUTDOWN MARGIN values in Specifications 3.1.1, 3.1.4, 3.1.5, 3.1.6, and 3.1.8, 7. Moderator Temperature Coefficient limits in Specification 3.1.3, and 8. Refueling Boron Concentration limits in Specification 3.9.1.(continued)

DIABLO CANYON -UNITS 1 & 2 5.0-26 Unit 1 -Amendment No. 4-35,180 Unit 2 -Amendment No. 4-35,182 Tke reare- t~o )e Reporting Requirements P.4 105.6 5.6 Reporting Requirements 5.6.5 CORE OPERATING LIMITS REPORT (COLR) (continued)

b. The analytical methods used to determine the core operating limits shall be those previously reviewed and approved by the NRC, specifically those described in the following documents:
1. WCAP-1 0216-P-A, Revision 1A, Relaxation of Constant Axial Offset Control FQ Surveillance Technical Specification, February 1994 (Westinghouse Proprietary), 2. WCAP-9272-P-A, Westinghouse Reload Safety Evaluation Methodology, July 1985 (Westinghouse Proprietary), 3. WCAP-8385, Power Distribution Control and Load Following Procedures, September 1974 (Westinghouse Proprietary), 4. WCAP-10054-P-A, Westinghouse Small Break LOCA ECCS Evaluation Model Using the NOTRUMP Code, August 1985. (Westinghouse Proprietary), and 5. WCAP-10054-P-A, Addendum 2, Revision 1, "Addendum to the Westinghouse Small Break ECCS Evaluation Model Using the NOTRUMP Code: Safety Injection Into the Broken Loop and COSI Condensation Model," July 1997 (Westinghouse Proprietary), and 6. WCAP-12945-P-A, Westinghouse Code Qualification Document for Best-Estimate Loss of Coolant Analysis, June 1996. (Westinghouse Proprietary).
c. The core operating limits shall be determined such that all applicable limits (e.g., fuel thermal mechanical limits, core thermal hydraulic limits, Emergency Core Cooling Systems (ECCS) limits, nuclear limits such as SDM, transient analysis limits, and accident analysis limits) of the safety analysis are met.d. The COLR, including any midcycle revisions or supplements, shall be provided upon issuance for each reload cycle to the NRC.(continued)

DIABLO CANYON -UNITS 1 & 2 5.0-27 Unit 1 -Amendment No. 4-35 136 Unit 2 -Amendment No. 1-35 136 are'1 6" 4;3 .Reporting Requirements e re 5.6 5.6 Reporting Requirements (continued)

5.6.6 Reactor

Coolant System (RCS) PRESSURE AND TEMPERATURE LIMITS REPORT (PTLR)a. RCS pressure and temperature limits for heat up, cooldown, low temperature operation, criticality, hydrostatic testing, Low Temperature Overpressure Protection (LTOP) arming, and PORV lift settings as well as heatup and cooldown rates shall be established and documented in the PTLR for the following:

1. Specification 3.4.3, "RCS Pressure and Temperature (P/T) Limits," and 2. Specification 3.4.12, "Low Temperature Overpressure Protection (LTOP)System." (continued)

DIeBLO CAeON -T 1 5.0-27 DIABLO CANYON -UNITS 1 & 2 5.0-27a Unit 1 -Amendment No. 136 Unit 2 -Amendment No. 136 rIr'e A Irreýe re e re/Reporting Requirements 5.6 I 5.6 Reporting Requirements

5.6.6 Reactor

Coolant System (RCS) PRESSURE AND TEMPERATURE LIMITS REPORT (PTLR) (continued)

b. The analytical methods used to determine the RCS pressure and temperature and LTOP limits shall be those previously reviewed and approved by the NRC, specifically those described in the following documents:
1. WCAP 14040-NP-A, "Methodology Used to Develop Cold Overpressure Mitigating System Setpoints and RCS Heatup and Cooldown Limit Curves." 2. Chapter 6.0 of WCAP-1 5958, "Analysis of Capsule V from Pacific Gas and Electric Company Diablo Canyon Unit 1 Reactor Vessel Radiation Surveillance Program." c. The PTLR shall be provided to the NRC upon issuance for each reactor vessel fluence period and for any revision or supplement thereto.5.6.7 Not Used 5.6.8 PAM Report When a report is required by Condition B or F of LCO 3.3.3, "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.5.6.9 Not Used (continued)

I DIABLO CANYON -UNITS 1 & 2 5.0-28 Unit 1 -Amendment No. 4-35,41-6,170 Unit 2 -Amendment No. 4-3,4-68,171 Reporting Requirements 5.6 5.6 Reporting Requirements (continued) 5.6.10 Steam Generator (SG) Tube Inspection Report 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 5.5.9, Steam Generator (SG) Program. The report shall include:&.. 7 The scope of inspections performed on each SG, Active degradation mechanisms found, c.7 Nondestructive examination techniques utilized for each degradation mechanism, Location, orientation (if linear), and measured sizes (if available) of service induced indications, Number of tubes plugged during the inspection outage for each active degradation mechanism, A..0%/.*.,A Total number and percentage of tubes plugged to date, and/7' .The results of condition monitoring, including the results of tube pulls and in-situ testing.b. For implementation of the tube support plate voltage-based repair criteria in Specification 5.5.9.c.1, notify the NRC prior to the initial entry into MODE 4 should any of the following arise: 1. If ODSCC indications are identified that extend beyond the confines of the tube support plate.k_11 DIABLO CANYON -UNITS 1 & 2 5.0-29 Unit 1 -Amendment No. ,-35, 4182, Unit 2 -Amendment No. ,14 Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.1 0 Steam Generator (SG) Tube Inspection Report (continued)

c. The results of the inspection of W* tubes shall be submitted within 90 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with Specification 5.5.9, Steam Generator (SG) Program. This report shall include: 1. Identification of W* tube indications and indications that do not meet W*requirements and were plugged, including the following information:

the number of indications, the locations of the indications (relative to the BWT and TTS), the orientation (axial, circumferential, volumetric, inclined), the radial position of the tube within the tubesheet, the W* Zone of the tube, the severity of each indication (estimated depth), the side of the tube in which the indication initiated (inside or outside diameter), the W* inspection distance measured with respect to the BWT or TTS (whichever is lower), the length of axial indications, the angle of, inclination of clearly skewed axial cracks (if applicable), verification that the upper crack tip of W* indications returned to service in the prior cycle remain below the BWT by at least the 95% confidence NDE uncertainty on locating the crack tip relative to the BWT, updated 95% growth rate for use in operational assessment, the cumulative number of indications detected in the tubesheet region as a function of elevation within the tubesheet, and the condition monitoring and operational assessment main steamline break leak rate for each indication and each SG in accordance with the leak rate methodology described in PG&E Letter DCL-05-018, dated March 11, 2005, as supplemented by PG&E Letter DCL-05-090, dated August 25, 2005.2. Assessment of whether the results were consistent with expectations and, if not consistent, a description of the proposed corrective action.d. The aggregate calculated steam line break leakage from application of all alternate .repair criteria and non-alternate repair criteria shall be submitted within 90 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with Specification 5.5.9, Steam Generator (SG)Program.e. For implementation of tube support plate voltage-based repair criteria in Specification 5.5.9.c.1, a report shall be submitted within 90 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5.5.9, Steam Generator (SG) Program. The report shall include the information described in Section 6b of Attachment 1 of\ NRPC Generic Letter 95-05.(continued)

DIABLO CANYON -UNITS 1 & 2 5.0-30 Unit 1 -Amendment No. -,4-,-182, Unit 2 -Amendment No. 9 ,A-4-,4 6 Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.10 Steam Generator (SG) Tube Inspection Report (continued)

f. For implementation of the repair criteria for axial PWSCC at dented TSPs, the results of the condition monitoring and operational assessments will be submitted within 120 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with Specification 5.5.9, Steam Generator (SG) Program. The report will include: 1. Tabulations of indications found in the inspection, tubes plugged, and tubes left in service under the ARC.2. Growth rate distributions for indications found in the inspection and growth rate distributions used to establish the tube repair limits.3. Plus Point confirmation rates for bobbin detected indications when bobbin is relied upon for detection of axial PWSCC in less than or equal to 2 volt dents.4. For condition monitoring, an evaluation of any indications that satisfy burst margin requirements based on the Westinghouse burst pressure model, but do not satisfy burst margin requirements based on the combined ANL ligament tearing and throughwall burst pressure model.(continued)

I...,,,e.DIABLO CANYON -UNITS 1 & 2 5.0-30a Unit 1 -Amendment No. 4-9,5,,-451-2,4-82, Unit 2 -Amendment No. 135,1-54,1-52,484, Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.10 Steam Generator (SG) Tube Inspection Report (continued)

5. Performance evaluation of the operational assessment methodology for predicting flaw distributions as a function of flaw size.6. Evaluation results of number and size of previously reported versus new -PWSCC indications found in the inspection, and the potential need to account for new indications in the operational assessment burst evaluation.
7. Identification of mixed mode (axial PWSCC and circumferential) indications found in the inspection and an evaluation of the mixed mode indications for potential impact on the axial indication burst pressures or leakage.8. Any corrective actions found necessary in the event that condition monitoring requirements are not met.g. For implementation of the probability of prior cycle detection (POPCD) method, for the voltage-based repair criteria at tube support plate intersections, if the end-of-cycle conditional main steamline break burst probability, the projected main steamline break leak rate, or the number of indications are underpredicted by the previous cycle operational assessment, the following shall be submitted within 90 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with Specification 5.5.9, Steam Generator (SG) Program: 1. The assessment of the probable causes for the underpredications, proposed corrective actions, and any recommended changes to probability of detection or growth methodology indicated by potential methods assessments.
2. An assessment of the potential need to revise the alternate repair criteria analysis methods if: the burst probability is underpredicted by more than 0.001 (i.e., 10% of the reporting threshold) or an order of magnitude; or the leak rate is underpredicted by more than 0.5 gpm or an order of magnitude.
3. An assessment of the potential need to increase the number of predicted low voltage indications at the beginning of cycle if the total number of as-found indications in any SG are underestimated by greater than 15%or by greater than 150 indications.

DIABLO CANYON -UNITS 1 & 2 5.0-30b Unit 1 -Amendment No. 495,4-54,452,4-7,4-82, Unit 2 -Amendment No 442-,484.

e T" h-e r aAHigh Radiation Area rt4. 5.7 5.0 ADMINISTRATIVE CONTROLS 5.7 High Radiation Area As provided in paragraph 20.1601(c) of 10 CFR Part 20, the following controls shall be applied to high radiation areas in place of the controls required by paragraph 20.1601(a) and (b) of 10 CFR Part 20: 5.7.1 High Radiation Areas with Dose Rates Not Exceeding 1.0 rem/hour at 30 Centimeters from the Radiation Source or from any Surface Penetrated by the Radiation:

a. Each entryway to such an area shall be barricaded and conspicuously posted as a high radiation area. Such barricades may be opened as necessary to permit entry or exit of personnel or equipment.
b. Access to, and activities in, each such area shall be controlled by means of Radiation Work Permit (RWP) or equivalent that includes specification of radiation dose rates in the immediate work area(s) and other appropriate radiation protection equipment and measures.c. Individuals qualified in radiation protection procedures and personnel continuously escorted by such individuals may be exempted from the requirement for an RWP or equivalent while performing their assigned duties provided that they are otherwise following plant radiation protection procedures for entry to, exit from, and work in such areas.d. Each individual or group entering such an area shall possess: 1. A radiation monitoring device that continuously displays radiation dose rates in the area; or 2. A radiation monitoring device that continuously integrates the radiation dose rates in the area and alarms when the device's dose alarm setpoint is reached, with an appropriate alarm setpoint, or 3. A radiation monitoring device that continuously transmits dose rate and cumulative dose information to a remote receiver monitored by radiation protection personnel responsible for controlling personnel radiation exposure within the area, or 4. A self-reading dosimeter (e.g., pocket ionization chamber or electronic dosimeter) and, (i) Be under the surveillance, as specified in the RWP or equivalent, while in the area, of an individual qualified in radiation protection procedures, equipped with a radiation monitoring device that continuously displays radiation dose rates in the area; who is responsible for controlling personnel exposure within the area, or (continued)

DIABLO CANYON -UNITS 1 & 2 5.0-31 Unit 1 -Amendment No. 135 Unit 2 -Amendment No. 135 Tker ore ko , "High Radiation Area P e5.7 5.7 High Radiation Area 5.7.1 High Radiation Areas with Dose Rates Not Exceeding 1.0 rem/hour at 30 Centimeters from the Radiation Source or from any Surface Penetrated by the Radiation (continued)(ii) Be under the surveillance as specified in the RWP or equivalent, while in the area, by means of closed circuit television, of personnel qualified in radiation protection procedures, responsible for controlling personnel radiation exposure in the area, and with the means to communicate with individuals in the area who are covered by such surveillance.

e. Except for individuals qualified in radiation protection procedures or personnel continuously escorted by such individuals, entry into such areas shall be made only after dose rates in the area have been determined and entry personnel are knowledgeable of them.5.7.2 High Radiation Areas with Dose Rates Greater than 1.0 rem/hour at 30 Centimeters from the Radiation Source or from any Surface Penetrated by the Radiation, but less than 500 rads/hour at 1 Meter from the Radiation Source or from any Surface Penetrated by the Radiation:
a. Each entryway to such an area shall be conspicuously posted as a high radiation area and shall be provided with a locked or continuously guarded door or gate that prevents unauthorized entry, and, in addition: 1. All such door and gate keys shall be maintained under the administrative control of the shift manager, radiation protection manager, or his or her designee.2. Doors and gates shall remain locked except during periods of personnel or equipment entry or exit.b. Access to, and activities in, each such area shall be controlled by means of an RWP or equivalent that includes specification of radiation dose rates in the immediate work area(s) and other appropriate radiation protection equipment and measures.c. Individuals qualified in radiation protection procedures may be exempted from the requirement for an RWP or equivalent while performing radiation surveys in such areas provided that they are otherwise following plant radiation protection procedures for entry to, exit from, and work in such areas.d. Each individual or group entering such an area shall possess: 1. A radiation monitoring device that continuously integrates the radiation dose rates in the area and alarms when the device's dose alarm setpoint is reached, with an appropriate alarm setpoint, or (continued)

DIABLO CANYON -UNITS 1 & 2 5.0-32 Unit 1 -Amendment No. 435 142 Unit 2 -Amendment No. 435 142 e, 5 -High Radiation Area e ,5.7 5.7 High Radiation Area 5.7.2 High Radiation Areas with Dose Rates Greater than 1.0 rem/hour at 30 Centimeters from the Radiation Source or from any Surface Penetrated by the Radiation, but less than 500 rads/hour at 1 Meter from the Radiation Source or from any Surface Penetrated by the Radiation (continued)

2. A radiation monitoring device that continuously transmits dose rate and cumulative dose information to a remote receiver monitored by radiation protection personnel responsible for controlling personnel radiation exposure within the area with the means to communicate with and control every individual in the area, or 3. A self-reading dosimeter (e.g., pocket ionization chamber or electronic dosimeter) and, (i) Be under the surveillance, as specified in the RWP or equivalent, while in the area, of an individual qualified in radiation protection procedures, equipped with a radiation monitoring device that continuously displays radiation dose rates in the area; who is responsible for controlling personnel exposure within the area, or (ii) Be under the surveillance as specified in the RWP or equivalent, while in the area, by means of closed circuit television, of personnel qualified in radiation protection procedures, responsible for controlling personnel radiation exposure in the area, and with the means to communicate with and control every individual in the area, or 4. In those cases where options (2) and (3), above, are impractical or determined to be inconsistent with the "As Low As is Reasonably Achievable" principle, a radiation monitoring device that continuously displays radiation dose rates in the area.e. Except for individuals qualified in radiation protection procedures or personnel continuously escorted by such individuals, entry into such areas shall be made only after dose rates in the area have been determined and entry personnel are knowledgeable of them.f. Such individual areas that are within a larger area, such as PWR containment, where no enclosure exists for the purpose of locking and where no enclosure can reasonably be constructed around the individual area need not be controlled by a locked door or gate nor continuously guarded, but shall be barricaded, conspicuously posted, and a clearly visible flashing light shall be activated at the area as a warning device.DIABLO CANYON -UNITS 1 & 2 5.0-33 Unit 1 -Amendment No. 135 Unit 2 -Amendment No. 135 Enclosure 3 PG&E Letter DCL-07-002 Proposed Technical Specification Changes (retyped)Remove Page Insert Page 3.3-31 5.0-10 5.0-11 5.0-12 5.0-13 5.0-14 5.0-15 5.0-16 5.0-17 5.0-18 5.0-19 5.0-20*5.0-21 *5.0-22*5.0-23*5.0-24*5.0-24a*5.0-25*5.0-26*5.0-27*5.0-27a*5.0-28*5.0-29 5.0-30 5.0-30a 5.0-30b 5.0-31*5.0-32*5.0-33*3.3-31 5.0-10 5.0-11 5.0-12*5.0-13*5.0-14*5.0-15*5.0-16*5.0-17*5.0-18*5.0-19*5.0-20*5.0-21 *5.0-22*5.0-23 5.0-24*5.0-25*5.-0-26** There are no changes to this page. Page will be renumbered during implementation due to deletion of section 5.0 pages. These pages do not have new amendment numbers added since they are not changed.

ESFAS Instrumentation

3.3.2 Table

3.3.2-1 (page 5 of 7)Engineered Safety feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL (a)SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT 5. Feedwater Isolation (continued)

b. SG Water 1,20) 3 per SG J SR 3.3.2.1 < 90.2% 90.0%Level-High SR 3.3.2.5 (d)(e)High (P-14) SR 3.3.2.9 (d)(e)SR 3.3.2.10 c. Safety Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

Injection 6. Auxiliary Feedwater a. Manual 1,2,3 1 sw/pp N SR 3.3.2.13 NA NA b. Automatic 1,2,3 2 trains G SR 3.3.2.2 NA NA Actuation SR 3.3.2.4 Logic and SR 3.3.2.6 Actuation Relays (Solid State Protection System)c. Not used d.1SG Water 1,2,3 3 perSG D SR 3.3.2.1 _ 14.8% 15.0%Level-Low Low S R 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 (continued)(a) A channel is OPERABLE with an actual Trip Setpoint value outside its calibration tolerance band provided the Trip Setpoint value is conservative with respect to its associated Allowable Value and the channel is re-adjusted to within the established calibration tolerance band of the Nominal Trip Setpoint.

A Trip Setpoint may be set more conservative than the Nominal Trip Setpoint as necessary in response to plant conditions.(j) Except when all MFIVs, MFRVs, and associated bypass valves are closed and de-activated or isolated by a closed manual valve.(d) If the as-found channel setpoint is conservative with respect to the Allowable Value but outside its predefined as-found acceptance criteria band, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service. If the as-found instrument channel setpoint is not conservative with respect to the Allowable Value, the channel shall be declared inoperable.

Footnote (a) does not apply to this function.(e) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Nominal Trip Setpoint (NTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable.

Setpoints more conservative than the NTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures to confirm channel performance.

The methodologies used to determine the as-found and the as-left tolerance are specified in the Equipment Control Guidelines.

Footnote (a) does not apply to this function.DIABLO CANYON -UNITS 1 & 2 35 3.3-31 Unit 1 -Amendment No. 4-35, 4-73, 4-78, Unit 2 -Amendment No. 4-35, 4-75, 4-80, Programs and Manuals 5.5 5.5 Programs and Manuals (continued)

5.5.9 Steam

Generator (SG) Tube Inspection Proqram A Steam Generator Program shall be established and implemented to ensure that SG 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 SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging of tubes.Condition monitoring assessments shall be conducted during each outage during which the SG tubes are inspected or plugged to confirm that the performance criteria are being met.b. Performance criteria for SG tube integrity.

SG 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.2. Accident induced leakage performance criterion:

The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG. Except during a SG tube rupture, leakage is also not to exceed 1 gallon per minute per SG.-1-I (continued)

DIABLO CANYON -UNITS 1 & 2 5.0-10 Unit 1 -Amendment No.Unit 2 -Amendment No.

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Tube Inspection Program (continued)

3. The operational LEAKAGE performance criterion is specified in LCO 3.4.13, "RCS Operational LEAKAGE." c. Provisions for SG tube repair criteria.Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged.d. Provisions for SG tube inspections.

Periodic SG 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 addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG 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 SG during the first refueling outage following SG replacement.
2. Inspect 100% of the tubes at sequential periods of 144, 108, 72, and, thereafter, 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outage nearest the end of the period. No SG shall operate for more than 72 effective full power months or three refueling outages*(whichever is less) without being inspected.
3. If crack indications are found in any SG tube, then the next inspection for each SG 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.e. Provisions for monitoring operational primary to secondary LEAKAGE.(continued)

DIABLO CANYON -UNITS 1 & 2 5.0-11 Unit 1 -Amendment No.Unit 2 -Amendment No.

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.10 Secondary Water Chemistry Program This program provides controls for monitoring secondary water chemistry to inhibit SG tube degradation.

The program shall include: a. Identification of a sampling schedule for the critical variables and control points for these variables;

b. Identification of the procedures used to measure the values of the critical variables;
c. Identification of process sampling points, which shall include monitoring the discharge of the condensate pumps for evidence of condenser in leakage;d. Procedures for the recording and management of data;e. Procedures defining corrective actions for all off control point chemistry conditions; and f. A procedure identifying the authority responsible for the interpretation of the data and the sequence and timing of administrative events, which is required to initiate corrective action.5.5.11 Ventilation Filter Testing Program (VFTP)A program shall be established to implement the following required testing of Engineered Safety Feature (ESF) filter ventilation systems at the frequencies specified below and in accordance with Regulatory Guide 1.52, Revision 2, ANSI N510 1980, and ASTM D3803-1989.
a. Demonstrate for each of the ESF systems that an in-place test of the high efficiency particulate air (HEPA) filters shows a penetration and system bypass< 1.0% when tested in accordance with ANSI N510-1980 at the system flowrate specified below +/- 10% at least once per 24 months.ESF Ventilation System Flowrate Control Room 2100 cfm Auxiliary Building 73,500 cfm Fuel Handling Building 35,750 cfm b. Demonstrate for each of the ESF systems that an in-place test of the charcoal adsorber shows a penetration and system bypass < 1.0% when tested in accordance with ANSI N510-1980 at the system flowrate specified below +/- 10%at least once per 24 months.ESF Ventilation System Flowrate Control Room 2100 cfm Auxiliary Building 73,500 cfm Fuel Handling Building 35,750 cfm (continued)

DIABLO CANYON -UNITS 1 & 2 5.0-12 Unit 1 -Amendment No. 4-35 142 Unit 2 -Amendment No. 4-35 142 Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Ventilation Filter Testinq Program (VFTP) (continued)

c. Demonstrate for each of the ESF systems that a laboratory test of a sample of the charcoal absorber, when obtained as described in Regulatory Guide 1.52, Revision 2, shows the methyl iodide penetration less than the value specified below when tested in accordance with ASTM D3803-1989 at a temperature of 300C and at the relative humidity specified below. Laboratory testing shall be completed at least once per 24 months and after every 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of charcoal operation.

ESF Ventilation System Penetration RH Control Room 2.5% 95%Auxiliary Building 15.0% 95%Fuel Handling Building 15.0% 95%d. Demonstrate for each of the ESF systems that the pressure drop across the combined HEPA filters and the charcoal adsorbers is less than the value specified below when tested in accordance with ANSI N510-1980 at the system flowrate specified below +/- 10% at least once per 24 months.ESF Ventilation System Delta P Flowrate Control Room 3.5 in. WG 2100 cfm Auxiliary Building 3.7 in. WG 73,500 cfm Fuel Handling Building 4.1 in. WG 35,750 cfm The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the VFTP test frequencies.

5.5.12 Explosive Gas and Storage Tank Radioactivity Monitoring Program This program provides controls for potentially explosive gas mixtures contained in the Waste Gas Holdup System, the quantity of radioactivity contained in gas storage tanks, and the quantity of radioactivity contained in temporary unprotected outdoor liquid storage tanks.The gaseous radioactivity quantities shall be determined following the methodology in Regulatory Guide 1.24 "Assumptions Used For Evaluating the Potential Radiological Consequences of a Pressurized Water Reactor Radioactive Gas Storage Tank Failure." The liquid radwaste quantities shall be maintained such that 10 CFR Part 20 limits are met.(continued)

DIABLO CANYON -UNITS 1 & 2 5.0-13 Unit 1 -Amendment No. 4-35 442,163 Unit 2 -Amendment No. 4-35 442,165 Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.12 Explosive Gas and Storage Tank Radioactivity Monitoring Program (continued)

The program shall include: a. The limits for concentrations of hydrogen and oxygen in the Waste Gas Holdup System and a surveillance program to ensure the limits are maintained.

Such limits shall be appropriate to the system's design criteria (i.e., whether or not the system is designed to withstand a hydrogen explosion);

b. A surveillance program to ensure that the quantity of radioactivity contained in each gas storage tank is less than the amount that would result in a whole body exposure of > 0.5 rem to any individual in an unrestricted area, in the event of an uncontrolled release of the tanks' contents; and c. A surveillance program to ensure that the quantity of radioactivity contained in temporary outdoor liquid radwaste tanks that are not surrounded by liners, dikes, or walls, capable of holding the tanks' contents and that do not have tank overflows and surrounding area drains connected to the Liquid Radwaste Treatment System is less than the amount that would result in concentrations less than the limits of 10 CFR 20, Appendix B, Table II, Column 2, at the nearest potable water supply and the nearest surface water supply in an unrestricted area, in the event of an uncontrolled release of the tanks' contents.The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Explosive Gas and Storage Tank Radioactivity Monitoring Program surveillance frequencies.

5.5.13 Diesel Fuel Oil Testing Program A diesel fuel oil testing program to implement required testing of both new fuel oil and stored fuel oil shall be established.

The program shall include sampling and testing requirements, and acceptance criteria, all in accordance with applicable ASTM Standards.

The purpose of the program is to establish the following:

a. Acceptability of new fuel oil for use prior to addition to storage tanks by determining that the fuel oil has: 1. an API gravity or an absolute specific gravity within limits, 2. a flash point and kinematic viscosity within limits for ASTM 2D fuel oil, and 3. a clear and bright appearance with proper color; or water and sediment content within limits.b. Other properties for ASTM 2D fuel oil are analyzed within 31 days following sampling and addition to storage tanks; and c. Total particulate concentration of the fuel oil is < 10 mg/I when tested every 31 days in accordance with ASTM D-2276, Method A.* d. The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Diesel Fuel Oil Testing Program test frequencies.(continued)

DIABLO CANYON -UNITS 1 & 2 5.0-14 Unit 1 -Amendment No. 135 Unit 2 -Amendment No. 135 Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.14 Technical Specifications (TS) Bases Control Program This program provides a means for processing changes to the Bases of these Technical Specifications.

a. Changes to the Bases of the TS shall be made under appropriate administrative controls and reviews.b. Licensees may make changes to Bases without prior NRC approval provided the changes do not require either of the following:
1. a change in the TS incorporated in the license; or 2. a change to the updated FSAR or Bases that requires NRC approval pursuant to 10 CFR 50.59.c. The Bases Control Program shall contain provisions to ensure that the Bases are maintained consistent with the FSAR.d. Proposed changes that meet the criteria of Specification 5.5.14b above shall be reviewed and approved by the NRC prior to implementation.

Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71(e).5.5.15 Safety Function Determination Program (SFDP)This program ensures loss of safety function is detected and appropriate actions taken.Upon entry into LCO 3.0.6, an evaluation shall be made to determine if loss of safety function exists. Additionally, other appropriate actions may be taken as a result of the support system inoperability and corresponding exception to entering supported system Condition and Required Actions. This program implements the requirements of LCO 3.0.6. The SFDP shall contain the following:

a. Provisions for cross train checks to ensure a loss of the capability to perform the safety function assumed in the accident analysis does not go undetected;
b. Provisions for ensuring the plant is maintained in a safe condition if a loss of function condition exists;c. Provisions to ensure that an inoperable supported system's Completion Time is not inappropriately extended as a result of multiple support system inoperabilities; and d. Other appropriate limitations and remedial or compensatory actions.A loss of safety function exists when, assuming no concurrent single failure, a safety function assumed in the accident analysis cannot be performed.

For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and: a. A required system redundant to the system(s) supported by the inoperable support system is also inoperable; or (continued)

DIABLO CANYON -UNITS 1 & 2 5.0-15 Unit 1 -Amendment No. 4-35, 145 Unit 2 -Amendment No. 4-35,144 Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.15 Safety Function Determination Program (SFDP) (continued)

b. A required system redundant to the system(s) in turn supported by the inoperable supported system is also inoperable; or c. A required system redundant to the support system(s) for the supported systems (a) and (b) above is also inoperable.

The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered.5.5.16 Containment Leakage Rate Testing Program a. A program shall be established to implement the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions.

This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program, dated September 1995." The ten-year interval between performance of the integrated leakage rate (Type A) test, beginning May 4, 1994, for Unit 1 and April 30, 1993, for Unit 2, has been extended to 15 years.b. The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 47 psig.c. The maximum allowable containment leakage rate, La, at Pa, shall be 0.10% of containment air weight per day.d. Leakage rate acceptance criteria are: 1. Containment overall leakage rate acceptance criterion is < 1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are < 0.60 La for the Type B and Type C tests and _< 0.75 La for Type A tests;2. Air lock testing acceptance criteria are: a) Overall air lock leakage rate is < 0.05 La when tested at > Pa.b) For each door, leakage rate is < 0.01 La when pressurized to > 10 psig.e. The provisions of SR 3.0.2 do not apply to the test frequencies specified in the Containment Leakage Rate Testing Program.f. The provisions of SR 3.0.3 are applicable to the Containment Leakage Rate Testing Program.(continued)

DIABLO CANYON -UNITS 1 & 2 5.0-16 Unit 1 -Amendment No. 41-5, 1-50, 172 Unit 2 -Amendment No. 435, 1-50, 174 Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.17 Battery Monitoring and Maintenance Program This Program provides for restoration and maintenance, based on the recommendations of IEEE Standard 450, "IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented Lead-Acid Batteries for Stationary Applications," or of the battery manufacturer, of the following:

a. Actions to restore battery cells with float voltage < 2.13 V, and b. Actions to equalize and test battery cells that have been discovered with electrolyte level below the top of the plates.DIABLO CANYON -UNITS 1 & 2 5.0-17 Unit 1 -Amendment No. 172 Unit 2 -Amendment No. 174 Reporting Requirements 5.6 5.0 ADMINISTRATIVE CONTROLS 5.6 Reporting Requirements The following reports shall be submitted in accordance with 10 CFR 50.4.5.6.1 Not Used 5.6.2 Annual Radiological Environmental Operatinq Report---------------------------

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

A single submittal may be made for a multiple unit station. The submittal should combine sections common to all units at the station.The Annual Radiological Environmental Operating Report covering the operation of the unit during the previous calendar year shall be submitted by May 1 of each year. The report shall include summaries, interpretations, and analyses of trends of the results of the radiological environmental monitoring program for the reporting period. The material provided shall be consistent with the objectives outlined in the Offsite Dose Calculation Manual (ODCM), and in 10 CFR 50, Appendix I, Sections IV.B.2, IV.B.3, and IV.C.The Annual Radiological Environmental Operating Report shall include the results of analyses of all radiological environmental samples and of all environmental radiation measurements taken during the period pursuant to the locations specified in the table and figures in the ODCM, as well as summarized and tabulated results of these analyses and measurements in a format similar to the table in the Radiological Assessment Branch Technical Position, Revision 1, November 1979. In the event that some individual results are not available for inclusion with the report, the report shall be submitted noting and explaining the reasons for the missing results. The missing data shall be submitted in a supplementary report as soon as poss~ible.

I (continued)

DIABLO CANYON -UNITS 1 & 2 5.0-18 Unit 1 -Amendment No. 4-35, 180 Unit 2 -Amendment No. 4--5, 182 Reporting Requirements 5.6 5.6 Reporting Requirements (continued)

5.6.3 Radioactive

Effluent Release Report-------------------------

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

A single submittal may be made for a multiple unit station. The submittal shall combine sections common to all units at the station; however, for units with separate radwaste systems, the submittal shall specify the releases of radioactive material from each unit.The Radioactive Effluent Release Report covering the operation of the unit during the previous year shall be submitted prior to May 1 of each year in accordance with 10 CFR 50.36a. The report shall include a summary of the quantities of radioactive liquid and gaseous effluents and solid waste released from the unit. The material provided shall be consistent with the objectives outlined in the ODCM and Process Control Program and in conformance with 10 CFR 50.36a and 10 CFR 50, Appendix I, Section IV.B.1.5.6.4 Not Used 5.6.5 CORE OPERATING LIMITS REPORT (COLR)a. Core operating limits shall be established prior to each reload cycle, or prior to any remaining portion of a reload cycle, and shall be documented in the COLR for the following:

1. Shutdown Bank Insertion Limits for Specification 3.1.5, 2. Control Bank Insertion Limits for Specification 3.1.6, 3. Axial Flux Difference for Specification 3.2.3, 4. Heat Flux Hot Channel Factor, K(Z) and W(Z) -FQ(z) (FQRTP Specification 3.2.1), 5. RCS Flow Rate and Nuclear Enthalpy Rise Hot Channel Factor -FAN (FRTPAH and PFAH for Specification 3.2.2), 6. SHUTDOWN MARGIN values in Specifications 3.1.1, 3.1.4, 3.1.5, 3.1.6, and 3.1.8, 7. Moderator Temperature Coefficient limits in Specification 3.1.3, and 8. Refueling Boron Concentration limits in Specification 3.9.1.(continued)

DIABLO CANYON -UNITS 1 & 2 5.0-19 Unit 1 -Amendment No. 4-1,180 Unit 2 -Amendment No. 4-3.5,182 Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.5 CORE OPERATING LIMITS REPORT (COLR) (continued)

b. The analytical methods used to determine the core operating limits shall be those previously reviewed and approved by the NRC, specifically those described in the following documents:
1. WCAP-1 0216-P-A, Revision 1A, Relaxation of Constant Axial Offset Control FQ Surveillance Technical Specification, February 1994 (Westinghouse Proprietary), 2. WCAP-9272-P-A, Westinghouse Reload Safety Evaluation Methodology, July 1985 (Westinghouse Proprietary), 3. WCAP-8385, Power Distribution Control and Load Following Procedures, September 1974 (Westinghouse Proprietary), 4. WCAP-10054-P-A, Westinghouse Small Break LOCA ECCS Evaluation Model Using the NOTRUMP Code, August 1985. (Westinghouse Proprietary), and 5. WCAP-10054-P-A, Addendum 2, Revision 1, "Addendum to the Westinghouse Small Break ECCS Evaluation Model Using the NOTRUMP Code: Safety Injection Into the Broken Loop and COSI Condensation Model," July 1997 (Westinghouse Proprietary), and 6. WCAP-12945-P-A, Westinghouse Code Qualification Document for Best-Estimate Loss of Coolant Analysis, June 1996. (Westinghouse Proprietary).
c. The core operating limits shall be determined such that all applicable limits (e.g., fuel thermal mechanical limits, core thermal hydraulic limits, Emergency Core Cooling Systems (ECCS) limits, huclear limits such as SDM, transient analysis limits, and accident analysis limits) of the safety analysis are met.d. The COLR, including any midcycle revisions or supplements, shall be provided upon issuance for each reload cycle to the NRC.(continued)

DIABLO CANYON -UNITS 1 & 2 5.0-20 Unit 1 -Amendment No. 435 136 Unit 2 -Amendment No. 4-5 136 Reporting Requirements 5.6 5.6 Reporting Requirements (continued)

5.6.6 Reactor

Coolant System (RCS) PRESSURE AND TEMPERATURE LIMITS REPORT (PTLR)a. RCS pressure and temperature limits for heat up, cooldown, low temperature operation, criticality, hydrostatic testing, Low Temperature Overpressure Protection (LTOP) arming, and PORV lift settings as well as heatup and cooldown rates shall be established and documented in the PTLR for the following:

1. Specification 3.4.3, "RCS Pressure and Temperature (P/T) Limits," and 2. Specification 3.4.12, "Low Temperature Overpressure Protection (LTOP)System." (continued)

DIABLO CANYON,- UNITS 1 & 2 5.0-21 Unit 1 -Amendment No. 136 Unit 2 -Amendment No. 136 Reporting Requirements 5.6 5.6 Reporting Requirements

5.6.6 Reactor

Coolant System (RCS) PRESSURE AND TEMPERATURE LIMITS REPORT (PTLR) (continued)

b. The analytical methods used to determine the RCS pressure and temperature and LTOP limits shall be those previously reviewed and approved by the NRC, specifically those described in the following documents:
1. WCAP 14040-NP-A, "Methodology Used to Develop Cold Overpressure Mitigating System Setpoints and RCS Heatup and Cooldown Limit Curves." 2. Chapter 6.0 of WCAP-1 5958, "Analysis of Capsule V from Pacific Gas and Electric Company Diablo Canyon Unit 1 Reactor Vessel Radiation Surveillance Program." c. The PTLR shall be provided to the NRC upon issuance for each reactor vessel fluence period and for any revision or supplement thereto.5.6.7 Not Used 5.6.8 PAM Report When a report is required by Condition B or F of LCO 3.3.3, "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.5.6.9 Not Used I (continued)

DIABLO CANYON -UNITS 1 & 2 5.0-22 Unit 1 -Amendment No. 435,468,170 Unit 2 -Amendment No. 4-35,1-46,171 Reporting Requirements 5.6 5.6 Reporting Requirements (continued) 5.6.10 Steam Generator (SG) Tube Inspection Report A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with Specification 5.5.9, Steam Generator (SG) Program. The report shall include: a. The scope of inspections performed on each SG, b. Active degradation mechanisms found, c. Nondestructive examination techniques utilized for each degradation mechanism, d. Location, orientation (if linear), and measured sizes (if available) of service induced indications, e. Number of tubes plugged during the inspection outage for each active degradation mechanism, f. Total number and percentage of tubes plugged to date, and g. The results of condition monitoring, including the results of tube pulls and in-situ testing.dI DIABLO CANYON -UNITS 1 & 2 5.0-23 Unit 1 -Amendment No.Unit 2 -Amendment No.

High Radiation Area 5.7 5.0 ADMINISTRATIVE CONTROLS 5.7 High Radiation Area As provided in paragraph 20.1601(c) of 10 CFR Part 20, the following controls shall be applied to high radiation areas in place of the controls required by paragraph 20.1601(a) and (b) of 10 CFR Part 20: 5.7.1 High Radiation Areas with Dose Rates Not Exceeding 1.0 rem/hour at 30 Centimeters from the Radiation Source or from any Surface Penetrated by the Radiation:

a. Each entryway to such an area shall be barricaded and conspicuously posted as a high radiation area. Such barricades may be opened as necessary to permit entry or exit of personnel or equipment.
b. Access to, and activities in, each such area shall be controlled by means of Radiation Work Permit (RWP) or equivalent that includes specification of radiation dose rates in the immediate work area(s) and other appropriate radiation protection equipment and measures.c. Individuals qualified in radiation protection procedures and personnel continuously escorted by such individuals may be exempted from the requirement for an RWP or equivalent while performing their assigned duties provided that they are otherwise following plant radiation protection procedures for entry to, exit from, and work in such areas.d. Each individual or group entering such an area shall possess: 1. A radiation monitoring device that continuously displays radiation dose rates in the area; or 2. A radiation monitoring device that continuously integrates the radiation dose rates in the area and alarms when the device's dose alarm setpoint is reached, with an appropriate alarm setpoint, or 3. A radiation monitoring device that continuously transmits dose rate and cumulative dose information to a remote receiver monitored by radiation protection personnel responsible for controlling personnel radiation exposure within the area, or 4. A self-reading dosimeter (e.g., pocket ionization chamber or electronic dosimeter) and, (i) Be under the surveillance, as specified in the RWP or equivalent, while in the area, of an individual qualified in radiation protection procedures, equipped with a radiation monitoring device that continuously displays radiation dose rates in the area; who is responsible for controlling personnel exposure within the area, or (continued)

DIABLO CANYON -UNITS 1 & 2 5.0-24 Unit 1 -Amendment No. 135 Unit 2 -Amendment No. 135 High Radiation Area 5.7 5.7 High Radiation Area 5.7.1 Hicqh Radiation Areas with Dose Rates Not Exceeding 1.0 rem/hour at 30 Centimeters from the Radiation Source or from any Surface Penetrated by the Radiation (continued)(ii) Be under the surveillance as specified in the RWP or equivalent, while in the area, by means of closed circuit television, of personnel qualified in radiation protection procedures, responsible for controlling personnel radiation exposure in the area, and with the means to communicate with individuals in the area who are covered by such surveillance.

e. Except for individuals qualified in radiation protection procedures or personnel continuously escorted by such individuals, entry into such areas shall be made only after dose rates in the area have been determined and entry personnel are knowledgeable of them.5.7.2 High Radiation Areas with Dose Rates Greater than 1.0 rem/hour at 30 Centimeters from the Radiation Source or from any Surface Penetrated by the Radiation, but less than 500 rads/hour at 1 Meter from the Radiation Source or from any Surface Penetrated by the Radiation:
a. Each entryway to such an area shall be conspicuously posted as a high radiation area and shall be provided with a locked or continuously guarded door or gate that prevents unauthorized entry, and, in addition: 1. All such door and gate keys shall be maintained under the administrative control of the shift manager, radiation protection manager, or his or her designee.2. Doors and gates shall remain locked except during periods of personnel or equipment entry or exit.b. Access to, and activities in, each such area shall be controlled by means of an RWP or equivalent that includes specification of radiation dose rates in the immediate work area(s) and other appropriate radiation protection equipment and measures.c. Individuals qualified in radiation protection procedures may be exempted from the requirement for an RWP or equivalent while performing radiation surveys in such areas provided that they are otherwise following plant radiation protection procedures for entry to, exit from, and work in such areas.d. Each individual or group entering such an area shall possess: 1. A radiation monitoring device that continuously integrates the radiation dose rates in the area and alarms when the device's dose alarm setpoint is reached, with an appropriate alarm setpoint, or (continued)

DIABLO CANYON -UNITS 1 & 2 5.0-25 Unit 1 -Amendment No. 4-5 142 Unit 2 -Amendment No. -35 142 High Radiation Area 5.7 5.7 High Radiation Area 5.7.2 High Radiation Areas with Dose Rates Greater than 1.0 rem/hour at 30 Centimeters from the Radiation Source or from any Surface Penetrated by the Radiation, but less than 500 rads/hour at 1 Meter from the Radiation Source or from any Surface Penetrated by the Radiation (continued)

2. A radiation monitoring device that continuously transmits dose rate and cumulative dose information to a remote receiver monitored by radiation protection personnel responsible for controlling personnel radiation exposure within the area with the means to communicate with and control every individual in the area, or 3. A self-reading dosimeter (e.g., pocket ionization chamber or electronic dosimeter) and, (i) Be under the surveillance, as specified in the RWP or equivalent, while in the area, of an individual qualified in radiation protection procedures, equipped with a radiation monitoring device that continuously displays radiation dose rates in the area; who is responsible for controlling personnel exposure within the area, or (ii) Be under the surveillance as specified in the RWP or equivalent, while in the area, by means of closed circuit television, of personnel qualified in radiation protection procedures, responsible for controlling personnel radiation exposure in the area, and with the means to communicate with and control every individual in the area, or 4. In those cases where options (2) and (3), above, are impractical or determined to be inconsistent with the "As Low As is Reasonably Achievable" principle, a radiation monitoring device that continuously displays radiation dose rates in the area.e. Except for individuals qualified in radiation protection procedures or personnel continuously escorted by such individuals, entry into such areas shall be made only after dose rates in the area have been determined and entry personnel are knowledgeable of them.f. Such individual areas that are within a larger area, such as PWR containment, where no enclosure exists for the purpose of locking and where no enclosure can reasonably be constructed around the individual area need not be controlled by a locked door or gate nor continuously guarded, but shall be barricaded, conspicuously posted, and a clearly visible flashing light shall be activated at the area as a warning device.DIABLO CANYON -UNITS 1 & 2 5.0-26 Unit 1 -Amendment No. 135 Unit 2 -Amendment No. 135 Enclosure 4 PG&E Letter DCL-07-002 Proposed Technical Specification Bases Changes (for information only)

ESFAS Instrumentation B 3.3.2 B 3.3 INSTRUMENTATION B 3.3.2 Engineered Safety Feature Actuation System (ESFAS) Instrumentation BASES BACKGROUND The ESFAS initiates necessary safety systems, based on the values of selected unit parameters, to protect against violating core design limits and the Reactor Coolant System (RCS) pressure boundary, and to mitigate accidents.

S -- -"ESFAS instrumentation is segmented into three distinct but interconnected modules as identified below:* Field transmitters or process sensors and instrumentation:

provide a measurable electronic signal based on the physical characteristics of the parameter being measured;" Signal processing equipment including digital protection system, field contacts, and protection channel sets: provide signal conditioning, bistable setpoint comparison, process algorithm actuation, compatible electrical signal output to protection system devices, and control board/control room/miscellaneous indications; and Solid State Protection System (SSPS) including input, logic, and output bays: initiates the proper unit shutdown or engineered safety feature (ESF) actuation in accordance with the defined logic and based on the bistable outputs from the signal process control and protection system. The residual heat removal pump trip or refueling water storage tank level-low signal is not processed by the SSPS. The associated relays are located in the residual heat removal pumps control system.Field Transmitters or Sensors To meet the design demands for redundancy and reliability, more than one, and often as many as four, field transmitters or sensors are used to measure unit parameters.

In many cases, field transmitters or sensors that input to the ESFAS are shared with the Reactor Trip System (RTS). In some cases, the same channels also provide control system inputs. To account for calibration tolerances and instrument drift, which are assumed to occur between calibrations, statistical allowances are provided in the Trip Setpoint and Allowable Values.The OPERABILITY of each transmitter or sensor can be evaluated when its "as found" calibration data are compared against its documented acceptance criteria.(continued)

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-R4 66 ESFAS Instrumentation B 3.3.2 BASES BACKGROUND (continued) 3 TriD SetDoints and Allowable Values The Trip Setpoints are the nominal values at which the bistables are set. Any bistable is considered to be properly adjusted when the "as left" value is within the two-sided tolerance band for calibration accuracy.The Trip Setpoints used in the bistables are based on the analytical limits stated in Reference

2. The selection of these Trip Setpoints is such that adequate protection is provided when all sensor and processing time delays are taken into account. To allow for calibration tolerances, instrumentation uncertainties, instrument drift, and severe environment errors for those ESFAS channels that must function in harsh environments as defined by 10 CFR 50.49 (Ref. 5), the Trip Setpoints and Allowable Values specified in Table 3.3.2-1 in the accompanying LCO are conservatively adjusted with respect to the analytical limits. A detailed description of the methodology used to calculate the Trip Setpoints, including their explicit uncertainties, is provided in WCAP-1 1082, Rev. 6, "Westinghouse Setpoint Methodology for Protection Systems Diablo Canyon Units 1 & 2, 24 Month Fuel Cycle Evaluation," February 2003 (Ref. 12), calculation J J-54 Rev 15 (Ref. 13) and calculation J-110 Rev 5 (Ref. 14).w Interlock setpoints are nominal values provided in the PLS (Westinghouse Precautions Limitations and Setpoints) and their allowable values are Dcalculated in Calculation J-110 Rev. 5 (Ref. 14). .The actual nominal Trip Setpoint entered into the bistable is more conservative than that specified by the Allowable Value to account for Rack Drift and Rack Measuring and Test Equipment uncertainties.

The calibration tolerance, after conversion, should correspond to the rack comparator setting accuracy defined in the latest setpoint study. tOne example of such a change in measurement error is drift during the surveillance interval.

If the measured setpoint does not exceed the Allowable j Value, the bistable is considered OPERABLE.RRack drift in excess of e Allowable Value exhibits the behavior that the rack has not met its allowance.

Since there is a small statistical chance that this will happen, an infrequent excessive drift is expected.

Rack or sensor drift in excess of the allowance that is more than occasional may be indicative of more serious problems and warrants further investigation.(continued) 1]I I DIABLO CANYON -UNITS 1 & 2 doccontent.dll

-R4 Revision 4 68 ESFAS Instrumentation B 3.3.2 BASES BACKGROUND Trip Setpoints and Allowable Values (continued)

Setpoints in accordance with the Allowable Value ensure that the consequences of Design Basis Accidents (DBAs) will be acceptable, providing the unit is operated from within the LCOs at the onset of the Certain channels can be tested on line to verify that the signal processing equipment and setpoint accuracy is within the specified allowance requirements for Reference

2. Once a designated channel is taken out of service for testing, a simulated signal is injected in place of the field instrument signal. The process equipment for the channel in test is then tested, verified, and calibrated.

SRs for the channels are specified in the SR section.The Trip Setpoints and Allowable Values listed in Table 3.3.2-1 are based on the methodology described in Reference 12, 13, and 14, which incorporates all of the known uncertainties applicable for each channel. The magnitudes of these uncertainties are factored into the determination of each Trip Setpoint.

In the event a channel's setpoint is found nonconservative with respect to the specified Trip Setpoint, but more conservative than the Allowable Value, the setpoint must be adjusted consistent with the Trip Setpoint value. When a channel's Trip Setpoint is nonconservative with respect to the Allowable Value, declare the channel inoperable and apply the applicable ACTION statement until the channel is returned to OPERABLE status with its Setpoint adjusted consistent with the Trip Setpoint value. All field sensors and signal processing equipment for these channels are assumed to operate within the allowances of these uncertainty magnitudes.

The ESFAS Trip Setpoints may be administratively redefined in the conservative direction for several reasons including startup, testing, process error accountability, or even a conservative response for equipment malfunction or inoperability.

ESFAS functions are not historically redefined at the beginning of each cycle for purposes of startup or testing as several reactor Trip functions are. However, calibration to within the defined calibration tolerance of an administratively redefined, conservative Trip Setpoint is acceptable.

Redefinition at full power conditions for these functions is expected and acceptable.(continued)

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-R4 69 ESFAS Instrumentation B 3.3.2 BASES BACKGROUND Solid State Protection System (continued)

The SLAVE RELAY TEST interval is 24 months. The test frequency is based on relay reliability assessments presented in WCAP-1 3878,"Reliability Assessment of Potter and Brumfield MDR Series Relays," WCAP-1 3900, "Extension of Slave Relay Surveillance Test Intervals," and WCAP-14117, "Reliability Assessment of Potter and Brumfield MDR Series Relay." These reliability assessments are relay specific and apply only to Potter and Brumfield MDR series relays which are the only relays used in the ESF actuation system. Note that for normally energized applications, the relays may have to be replaced periodically in accordance with the guidance given in WCAP-1 3878 for MDR relays.APPLICABLE Each of the analyzed accidents can be detected by one or more SAFETY ESFAS Functions.

One of the ESFAS Functions is the primary ANALYSES, LCO, actuation signal for that accident.

An ESFAS Function may be the and primary actuation signal for more than one type of accident.

An APPLICABILITY ESFAS Function may also be a secondary, or backup, actuation signal for one or more other accidents.

Functions such as manual initiation, not specifically credited in the accident safety analysis, are qualitatively credited in the safety analysis and the NRC staff approved licensing basis for the unit. These Functions may provide protection for S-tse- ---1_ conditions that do not require dynamic transient analysis to demonstrate Function performance.

These Functions may also serve as backups to Functions that were credited in the accident analysis (Ref. 3).The LCO requires all instrumentation performing an ESFAS Function to be OPERABLE.

ailure of any instrument renders the affected channel(s) inoperable and reduces the reliability of the affected Functions.

The LCO generally requires OPERABILITY of four or three channels in each instrumentation function and two channels in each logic and manual initiation function.

The two-out-of-three and the two-out-of-four configurations allow one channel to be tripped, cut-out or bypassed during maintenance or testing without causing an ESFAS initiation.

Two logic or manual initiation channels are required to ensure no single random failure disables the ESFAS.(continued)

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-R4 Revision 4 71 ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.2.2 SR 3.3.2.2 is the performance of an ACTUATION LOGIC TEST. The SSPS is tested every 92 days on a STAGGERED TEST BASIS, using the semiautomatic tester. The train being tested is placed in the bypass condition, thus preventing inadvertent actuation.

Through the semiautomatic tester, all possible logic combinations, with and without applicable permissives, are tested for each protection function.

In addition, the master relay coil is pulse tested for continuity.

This verifies that the logic modules are OPERABLE and that there is an intact voltage signal path to the master relay coils. The Frequency of every 92 days on a STAGGERED TEST BASIS is justified in Reference 18.SR 3.3.2.3 -Not used SR 3.3.2.4 SR 3.3.2.4 is the performance of a MASTER RELAY TEST. The MASTER RELAY TEST is the energizing of the master relay, verifying contact operation and a low voltage continuity check of the slave relay coil. Upon master relay contact operation, a low voltage is injected to the slave relay coil. This voltage is insufficient to pick up the slave relay, but large enough to demonstrate signal path continuity.

This test is performed every 92 days on a STAGGERED TEST BASIS. The time allowed for the testing (4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />) is justified in Reference

8. The frequency of 92 days on a STAGGERED TEST BASIS is justified in Reference 18.SR 3.3.2.5 SR 3.3.2.5 is the performance of a COT.A COT is performed on each required channel to ensure the entire channel will perform the intended Function.

Setpoints must be found within the Allowable Values specified in Table 3.3.2-1.7-The difference between the current "as found" values and the previous test "as left" values must be consistent with the drift allowance used in the setpoint methodology.

The setpoint shall be left set consistent with the assumptions of the current unit specific setpoint methodology.

The "as found" and "as left" values must also be recorded and reviewed for consistency with the assumptions of the surveillance interval extension analysis (Ref. 8) when applicable.

I T~he Frequency of 184 days is justified in Reference 18.(continued)

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-R4 Revision 4 111 ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.2.6 SR 3.3.2.6 is the performance of a SLAVE RELAY TEST. The SLAVE RELAY TEST is the energizing of the slave relays. Contact operation is verified in one of two ways. Actuation equipment that may be operated in the design mitigation MODE is either allowed to function, or is placed in a condition where the relay contact operation can be verified without operation of the equipment.

Actuation equipment that may not be operated in the design mitigation MODE is prevented from operation by the SLAVE RELAY TEST circuit. For this latter case, contact operation is verified by a continuity check of the circuit containing the slave relay. This test is performed every 24 months.The Frequency is adequate, based on operating experience, considering relay reliability and operating history data (Ref. 7)SR 3.3.2.7 -Not used SR 3.3.2.8 SR 3.3.2.8 is the performance of a TADOT. This test is a check of the Manual Actuation Functions (except AFW; see SR 3.3.2.13).

It is performed every 24 months. Each Manual Actuation Function is tested up to, and including, the master relay coils. In some instances, the test includes actuation of the end device (i.e., pump starts, valve cycles, etc.). The Frequency is adequate, based on industry operating experience and is consistent with the typical refueling cycle. The SR is modified by a Note that excludes verification of setpoints during the TADOT for manual initiation Functions.

The manual initiation Functions have no associated setpoints.

SR 3.3.2.9 SR 3.3.2.9 is the performance of a CHANNEL CALIBRATION.

A CHANNEL CALIBRATION is performed every 24 months, or approximately at every refueling.

CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to measured parameter within the necessary range and accuracy.CHANNEL CALIBRATIONS must be performed consistent with the assumptions of the unit specific setpoint methodology.

The difference between the current "as-found" values and the previous test "as-left" values must be consistent with the drift allowance used in the setpoint methodology.(continued)

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-R4 Revision 4 112 ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE SR 3.3.2.9 (continued)

REQUIREMENTS Whenever an RTD is replaced in Function 6.d., the next required CHANNEL CALIBRATION of the RTDs is accomplished by an inplace cross calibration that compares the other sensing elements with the recently installed sensing element.The Frequency of 24 months is based on the assumption of an 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint methodology.

This SR is modified by a Note stating that this test should include verification that the time constants are adjusted to the prescribed values where applicable.

S R 3.3.2. 10 This SR ensures the individual channel ESF RESPONSE TIMES are less than or equal to the maximum values assumed in the accident analysis.

RESPONSE TIME testing acceptance criteria and the individual Functions requiring RESPONSE TIME Verification are included in ECG 38.2. Individual component response times are not modeled in the analyses.

The analyses model the overall or total elapsed time, from the point at which the parameter exceeds the Trip Setpoint value at the sensor, to the point at which the equipment in both trains reaches the required functional state (e.g., pumps at rated discharge pressure, valves in full open or closed position).

For channels that include dynamic transfer functions (e.g., lag, lead/lag, rate/lag, etc.), the response time test may be performed with the transfer functions set to one with the resulting measured response time compared to the appropriate FSAR response time. Alternately, the response time test can be performed with the time constants set to their nominal value provided the required response time is analytically calculated assuming the time constants are set at their nominal values.The response time may be measured by a series of overlapping tests such that the entire response time is measured.Response time may be verified by actual response time tests in any series of sequential, overlapping or total channel measurements, or by the summation of allocated sensor response times with actual response time tests on the remainder of the channel. Allocations for sensor response times may be obtained from: 1) historical records based on acceptable response time tests (hydraulic, noise, or power interrupt tests), 2) inplace, onsite, or offsite (e.g., vendor) test measurements, or 3) utilizing vendor engineering specifications.

WCAP-13632-P-A, revision 2, "elimination of Pressure sensor (continued)

DIABLO CANYON -UNITS 1 & 2 Revision 4 doccontent.dll

-R4 113 ESFAS Instrumentation B 3.3.2 BASES REFERENCES (continued)

9. WCAP-1 3878, "Reliability of Potter & Brumfield MDR Relays", June 1994.10. WCAP-14117, "Reliability Assessment of Potter and Brumfield MDR Series Relays." 11. WCAP-13632-P-A, Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements," January 1996.12. WCAP-1 1082, Revision 6, "Westinghouse Setpoint Methodology for Protection Systems, Diablo Canyon Units 1 and 2, 24 Month Fuel Cycle Evaluation," February 2003.13. Calculation J-54, "Nominal Setpoint Calculation for Selected PLS Setpoints." 14. J-1 10, "24 Month Fuel Cycle Allowable Value Determination/

Documentation and ITDP Uncertainty Sensitivity." 15. License Amendment 61/60, May 23, 1991.16. WCAP-14036-P-A, Revision 1, "Elimination of Periodic Protection Channel Response Time Tests," October 1998.17. WCAP-14333-P-A, Revision 1, "Probabilistic Risk Analysis of the RPS and ESFAS Test Times and Completion Times," October 1998.18.WCAP-15376-P-A, Revision 1, "Risk-Informed Assessment of the RTS and ESFAS Surveillance Test Intervals and Reactor Trip Breaker Test and Completion Times," March 2003./9, > C,,r fit5z), 5s- (.)DIABLO CANYON -UNITS 1 & 2 doccontent.dll

-R4 116 Revision 4 Technical Specification Bases Inserts Sections B 3.3.2 Insert 1 For Function 5.b in TS Table 3.3.2-1, this is achieved by specifying limiting safety system settings (LSSS) in terms of parameters directly monitored by the ESFAS, as well as specifying LCOs on other system parameters and equipment performance.

The next five paragraphs currently apply only to Function 5.b in TS Table 3.3.2-1.Technical Specifications are required by 10 CFR 50.36 to contain LSSS defined by the regulation as "...settings for automatic protective devices.., so chosen that automatic protective action will correct the abnormal situation before a Safety Limit (SL) is exceeded." The Analytical Limit is the limit of the process variable at which a safety action is initiated, as established by the safety analysis, to ensure that a SL is not exceeded.

Any automatic protection action that occurs on reaching the Analytical Limit therefore ensures that the SL is not exceeded.

However, in practice, the actual settings for automatic protective devices must be chosen to be more conservative than the Analytical Limit to account for instrument loop uncertainties related to the setting at which the automatic protective action would actually occur.The Nominal Trip Setpoint (NTSP) is a predetermined setting for a protective device chosen to ensure automatic actuation prior to the process variable reaching the Analytical Limit and thus ensuring that the SL would not be exceeded.

As such, the NTSP accounts for uncertainties in setting the device (e.g., calibration), uncertainties in how the device might actually perform (e.g., repeatability), changes in the point of action of the device over time (e.g., drift during surveillance intervals), and any other factors which may influence its actual performance (e.g., harsh accident environments).

In this manner, the NTSP ensures that SLs are not exceeded.

As such, the NTSP meets the definition of an LSSS (Ref. 19). If the setting of the protective device does not protect a reactor core or RCS pressure boundary Safety Limit, the NTSP is not an LSSS.Technical Specifications contain values related to the OPERABILITY of equipment required for safe operation of the facility.

OPERABLE is defined in Technical Specifications as "... being capable of performing its safety functions(s)." Use of the NTSP to define OPERABILITY in Technical Specifications would be an overly restrictive requirement if it were applied as an OPERABILITY limit for the "as-found" value of a protective device setting during a surveillance.

This would result in Technical Specification compliance problems as well as reports and corrective actions required by the rule which are not necessary to ensure safety. For example, an automatic protective device with a setting that has been found to be different from the NTSP due to some drift of the setting may still be OPERABLE since drift is to be expected.

This expected drift would have been specifically accounted for in the setpoint methodology for calculating the NTSP and thus the automatic protective action would still have ensured that the SL would not be exceeded with the "as-found" setting of the protective Technical Specification Bases Inserts (continued) device. Therefore, the device would still be OPERABLE since it would have performed its safety function and the only corrective action required would be to reset the device to the NTSP to account for further drift during the next surveillance interval.Use of the NTSP to define "as-found" OPERABILITY under the expected circumstances described above would result in actions required by both the rule and Technical Specifications that are clearly not warranted.

However, there is also some point beyond which the device would have not been able to perform its function due, for example, to greater than expected drift. This value needs to be specified in the Technical Specifications in order to define OPERABILITY of the devices and is designated as the Allowable Value which is the least conservative value of the as-found setpoint that a channel can have during testing. The methodologies for calculating the as-left and as-found tolerances will be maintained in the Equipment Control Guidelines.

The Allowable Value specified in Table 3.3.2-1 is the least conservative value of the as-found setpoint that channel can have when tested, such that a channel is OPERABLE if the as-found setpoint is conservative with respect to the Allowable Value during the CHANNEL OPERATIONAL TEST (COT). As such, the Allowable Value differs from the NTSP by an amount greater than or equal to the expected instrument channel uncertainties, such as drift, during the surveillance interval.

In this manner, the actual setting of the device will ensure that an SL is not exceeded at any given point of time as long as the device has not drifted beyond that expected during the surveillance interval.Note that, although the channel is "OPERABLE" under these circumstances, the NTSP must be left adjusted to a value within the as-left tolerance, in accordance with uncertainty.assumptions stated in the referenced setpoint methodology (as-left criteria), and confirmed to be operating within the statistical allowances of the uncertainty terms assigned (as-found criteria).

If the actual setting of the device is found to be non-conservative with respect to the Allowable Value, the device would be considered inoperable from a technical specification perspective.

This requires corrective action including those actions required by 10 CFR 50.36 when automatic protective devices do not function as required.Insert 2 For Function 5.b in TS Table 3.3.2-1, a detailed description of the methodology used to calculate the Trip Setpoint, including its explicit uncertainty, is provided in WCAP-1 1082, Rev. (x) (Ref. 12) and calculation J-110 Rev. (x) (Ref. 14), which incorporate all of the known uncertainties applicable to each channel.Insert 3 For Function 5.b in TS Table 3.3.2-1, the magnitudes of these uncertainties are factored into the determination of the NTSP and corresponding Allowable Value.

Technical Specification Bases Inserts (continued)

Insert 4 For Function 5.b in TS Table 3.3.2-1, the Allowable Value serves as the Technical Specification OPERABILITY limit for purposes of the COT.Insert 5 For Function 5.b in TS Table 3.3.2-1, note that, although a channel is OPERABLE under these circumstances, the setpoint must be left adjusted to within the established as-left criteria and confirmed to be operating within the statistical allowances of the uncertainty terms assigned.Insert 6 For Function 5.b in Table 3.3.2-1, note that the Allowable Value is the least conservative value of the as-found setpoint that a channel can have during a periodic CHANNEL CALIBRATION or COT that requires trip setpoint verification.

Insert 7 For Function 5.b in TS Table 3.3.2-1, however, qualitatively credited or backup functions are not LSSS for reactor fuel/cladding or RCS pressure boundary Safety Limits.Insert 8 For Function 5.b in Table 3.3.2-1, a channel is OPERABLE with an NTSP value outside its calibration tolerance band provided the trip setpoint "as-found" value is conservative with respect to its associated Allowable Value and provided the NTSP "as-left" value is adjusted to a value within the calibration tolerance band of the NTSP. A trip setpoint may be set more conservative than the NTSP as necessary in response to plant conditions.

Insert 9 The next two paragraphs currently apply only to Function 5.b in TS Table 3.3.2-1.SR 3.3.2.5 for Function 5.b is modified by two notes as identified in Table 3.3.2-1.Function 5.b is an LSSS for protection system instrument channels that protect reactor core or RCS pressure boundary Safety Limits. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. For digital channel components, the as-found tolerance may be identical to the as-left tolerance since drift may not be an expected error. In these cases a channel as-found value outside the as-left condition may be cause for component assessment.

Technical Specification Bases Inserts (continued)

Evaluation of instrument performance will verify that the instrument will continue to behave in accordance with design-basis assumptions.

The purpose of the assessment is to ensure confidence in the instrument performance prior to returning the instrument to service. These channels will also be identified in the Corrective Action Program.Entry into the Corrective Action Program will ensure required review and documentation of the condition for continued OPERABILITY.

The second Note requires that the as-left setting for the instrument be returned to within the as-left tolerance of the NTSP. Where a setpoint more conservative than the NTSP is used in the plant surveillance procedures, the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint.

This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained.

If the as-left instrument setting cannot be returned to a setting within the as-left tolerance, then the instrument channel shall be declared inoperable.

The second Note also requires that the NTSP and the methodologies for calculating the as-left and the as-found tolerances be in the Equipment Control Guidelines.

Insert 10 The next two paragraphs currently apply only to Function 5.b in TS Table 3.3.2-1.SR 3.3.2.9 for Function 5.b is modified by two notes as identified in Table 3.3.2-1.Function 5.b is an LSSS for protection system instrument channels that protect reactor core or RCS pressure boundary Safety Limits. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. For digital channel components, the as-found tolerance may be identical to the as-left tolerance since drift may not be an expected error. In these cases a channel as-found value outside the as-left condition may be cause for component assessment.

Evaluation of instrument performance will verify that the instrument will continue to behave in accordance with design-basis assumptions.

The purpose of the assessment is to ensure confidence in the instrument performance prior to returning the instrument to service. These channels will also be identified in the Corrective Action Program.Entry into the Corrective Action Program will ensure required review and documentation of the condition for continued OPERABILITY.

The second Note requires that the as-left setting for the instrument be returned to within the as-left tolerance of the NTSP. Where a setpoint more conservative than the NTSP is used in the plant surveillance procedures, the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint.

This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained.

If the as-left instrument setting cannot be returned to a setting within the as-left tolerance, then the instrument channel shall be declared inoperable.

The second Note also requires that the NTSP and the methodologies for calculating the as-left and the as-found tolerances be in the Equipment Control Guidelines.

Steam Generator (SG) Tube Integrity B 3.4.17 BASES LCO Structural integrity requires that the primary membrane stress intensity (continued) in a tube not exceed the yield strength for all ASME Code,Section III, Servicel 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 (a) that the primary to secondary LEAKAGE caused by a design basis accident, other than a SGTR, is within the accident analysis assumptions, and (b) , at the primary to secondarv LEAKAGE will not exceed 1 gpm per SG (except for specific types of degradation at specific locations where the NRC has approved greater accident induced leakage) to ensure that the potential for induced leakage during severe accidents will be maintained at a level that will not increase risk. The accident analysis for the SLB event assumes that accident induced leakage does not exceed 10.5 0.75a .gptotalunderaccidentcirn in each intact SG.io the faulted f SG in the SLB event, 10.5 gpm is the accident induced leakage limit, of exwhich no more than 1 gpm can come from sources not aicry Lexempted bthe NRC from thi 1 m limit.'The accident ana.yses for events other than SGTR and SLB assume that leakage does not exceed 0.75 gpm total under accident conditions, equally partitioned among the four SGs (approximately 0.19 gpm from each SG). 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 SG tube conditions during plant operation.

The limit on operational LEAKAGE is contained in LCO 3.4.13, "RCS Operational LEAKAGE," and limits primary to secondary LEAKAGE through any one SG 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.

APPLICABILITY Steam generator tube integrity is challenged when the pressure differential across the tubes is large. Large differential pressures across SG 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.(continued)

Enclosure 5 PG&E Letter DCL-07-002 Regulatory Commitments

1. The TSTF-493 changes will be made to the remaining applicable RTS and ESFAS functions in a separate LAR that will be submitted after TSTF-493 is approved by the NRC.2. PG&E will develop the LTSP (SAL adjusted by the channel uncertainty) for ESFAS Function 5.b, Feedwater Isolation SG Water Level-High High (P-14).The LTSP for this function will be included in the ECGs, which is a 10 CFR 50.59 controlled document.3. PG&E will include the methodologies used to determine the as-found and the as-left tolerance (including the as-found and as-left tolerance values) in the ECGs, which is a 10 CFR 50.59 controlled document.

Enclosure 6 PG&E Letter DCL-07-002 Table 1 Feedwater Isolation SG Water Level-High High (P-14)a,c Process Pressure Variation Reference Leg Temperature Fluid Velocity Downcomer Subcooling Mid-deck Plate DP Intermediate Deck Plate DP Feedring DP Dynamic Losses Primary Element Accuracy Sensor Calibration Accuracy Sensor Reference Accuracy Sensor Measurement

& Test Equipment Accuracy Sensor Pressure Effects Sensor Temperature Effects Sensor Drift Environmental Allowance Seismic Effects Systematic Pressure Effect Drift Bias Rack Calibration Accuracy Rack Measurement

& Test Equipment Accuracy Rack Temperature Effect Rack Drift MRIL Total Allowance (TA)Channel Statistical Allowance (CSA)Marain Enclosure 7 PG&E Letter DCL-07-002 Westinghouse authorization letter, accompanying affidavit, Proprietary Information Notice, and a Copyright Notice for the proprietary information contained in Enclosure 8

W estinghouse Westinghouse Electric Compny Nuclear Services P.O. Box 355 Pittsburgh, Pennsylvania 152300355 USA U.S. Nuclear Regulatory Commission Directtel:

(412) 374-4643 Document Control Desk Direct fax: (412) 374-4011 Washington, DC 20555-0001 e-mail: greshaja@westinghouse.com Our ref: CAW-06-2224 December 18, 2006 APPLICATION FOR WITHHOLDING PROPRIETARY INFORMATION FROM PUBLIC DISCLOSURE

Subject:

Table I Feedwater Isolation SG Water Level-High High (P-14) Contained in PG&E License Amendment Request 06-07 and Application for Withholding Proprietary Information from Public Disclosure The proprietary information for which withholding is being requested in the above-referenced report is further identified in Affidavit CAW-06-2224 signed by the owner of the proprietary information, Westinghouse Electric Company LLC. The affidavit, which accompanies this letter, sets forth the basis on which the information may be withheld from public disclosure by the Commission and addresses with specificity the considerations listed in paragraph (bX4) of 10 CFR Section 2.390 of the Commission's regulations.

Accordingly, this letter authorizes the utilization of the accompanying affidavit by Pacific Gas and Electric.Correspondence with respect to the proprietary aspects of the application for withholding or the Westinghouse affidavit should reference this letter, CAW-06-2224, and should be addressed to J. A. Gresham, Manager, Regulatory Compliance and Plant Licensing, Westinghouse Electric Company LLC, P.O. Box 355, Pittsburgh, Pennsylvania 15230-0355.

Very truly yours,.J. A. Gresham, Manager Regulatory Compliance and Plant Licensing Enclosures cc: Jon Thompson (NRC)

CAW-06-2224 AFFIDAVIT COMMONWEALTH OF PENNSYLVANIA:

ss COUNTY OF ALLEGHENY:

Before me, the undersigned authority, personally appeared J. A. Gresham, who, being by me duly sworn according to law, deposes and says that he is authorized to execute this Affidavit on behalf of Westinghouse Electric Company LLC (Westinghouse), and that the averments of fact set forth in this Affidavit are true and correct to the best of his knowledge, information, and belief:/ J. A. Gresham, Manager Regulatory Compliance and Plant Licensing Sworn to and subscribed before me this d/f' day of December, 2006 Notary Public Noatan Sharon L. Ro0, Notary Public Monroeville Boro, Allegheny County My Commission Expires January 29,2007 Member. Pennsylvania Associabon Of Notaries 2 2 CAW-06-2224 (1) 1 am Manager, Regulatory Compliance and Plant Licensing, in Nuclear Services, Westinghouse Electric Company LLC (Westinghouse), and as such, I have been specifically delegated the function of reviewing the proprietary information sought to be withheld from public disclosure in connection with nuclear power plant licensing and rule making proceedings, and ain authorized to apply for its withholding on behalf of Westinghouse.

(2) 1 am making this Affidavit in conformance with the provisions of 10 CFR Section 2.390 of the Commission's regulations and in conjunction with the Westinghouse "Application for Withholding" accompanying this Affidavit.

(3) 1 have personal knowledge of the criteria and procedures utilized by Westinghouse in designating information as a trade secret, privileged or as confidential commercial or financial information.

(4) Pursuant to the provisions of paragraph (b)(4) of Section 2.390 of the Commission's regulations, the following is furnished for consideration by the Commission in determining whether the information.

sought to be withheld from public disclosure should be withheld.(i) The information sought to be withheld from public disclosure is owned and has been held in confidence by Westinghouse.(ii) The information is of a type customarily held in confidence by Westinghouse and not customarily disclosed to the public. Westinghouse has a rational basis for determining the types of information customarily held in confidence by it and, in that connection, utilizes a system to determine when and whether to hold certain types of information in confidence.

The application of that system and the substance of that system constitutes Westinghouse policy and provides the rational basis required.Under that system, information is held in confidence if it falls in one or more of several types, the release of which might result in the loss of an existing or potential competitive advantage, as follows: (a) The information reveals the distinguishing aspects of a process (or component, structure, tool, method, etc.) where prevention of its use by any of Westinghouse's competitors without license from Westinghouse constitutes a competitive economic advantage over other companies.

3 CAW-06-2224 (b) It consists of supporting data, including test data, relative to a process (or component, structure, tool, method, etc.), the application of which data secures a competitive economic advantage, e.g., by optimization or improved marketability.(c) Its use by a competitor would reduce his expenditure of resources or improve his competitive position in the design, manufacture, shipment, installation, assurance of quality, or licensing a similar product.(d) It reveals cost or price information, production capacities, budget levels, or commercial strategies of Westinghouse, its customers or suppliers.(e) It reveals aspects of past, present, or future Westinghouse or customer funded development plans and programs of potential commercial value to Westinghouse.(f) It contains patentable ideas, for which patent protection may be desirable.

There are sound policy reasons behind the Westinghouse system which include the following: (a) The use of such information by Westinghouse gives Westinghouse a competitive advantage over its competitors.

It is, therefore, withheld from disclosure to protect the Westinghouse competitive position.(b) It is information that is marketable in many ways. The extent to which such information is available to competitors diminishes the Westinghouse ability to sell products and services involving the use of the information.(c) Use by our competitor would put Westinghouse at a competitive disadvantage by reducing his expenditure of resources at our expense.(d) Each component of proprietary information pertinent to a particular competitive advantage is potentially as valuable as the total competitive advantage.

If competitors acquire components of proprietary information, any one component may be the key to the entire puzzle, thereby depriving Westinghouse of a competitive advantage.

4 CAW-06-2224 (e) Unrestricted disclosure would jeopardize the position of prominence of Westinghouse in the world market, and thereby give a market advantage to the competition of those countries.(f) The Westinghouse capacity to invest corporate assets in research and development depends upon the success in obtaining and maintaining a competitive advantage.(iii) The information is being transmitted to the Commission in confidence and, under the provisions of 10 CFR Section 2.390, it is to be received in confidence by the Commission.(iv) The information sought to be protected is not available in public sources or available information has not been previously employed in the same original manner or method to the best of our knowledge and belief.(v) The proprietary information sought to be withheld in this submittal is that which is appropriately marked in Table I Feedwater Isolation SG Water Level-High High (P-14)Contained in PG&E License Amendment Request 06-07 for Diablo Canyon Units I and 2, being transmitted by Pacific Gas & Electric letter and Application for Withholding Proprietary Information from Public Disclosure, to the Document Control Desk. The proprietary information as submitted for use by Westinghouse Electric Company LLC for Diablo Canyon Units 1 and 2 is expected to be applicable for other submittals in response to certain NRC requests for information on steam generator water level.This information is part of that which will enable Westinghouse to: (a) Provide information in support of a plant license submittal.

Further this information has substantial commercial value as follows: (a) Westinghouse plans to sell the use of similar information to its customers for purposes of meeting NRC requirements for licensing documentation.(b) Westinghouse can sell support and justification for the use of plant-specific steam generator water level calculations.

5 CAW-06-2224 Public disclosure of this proprietary information is likely to cause substantial harm to the competitive position of Westinghouse because it would enhance the ability of competitors to provide similar calculations, evaluations, analyses and licensing defense services for commercial power reactors without commensurate expenses.

Also, public disclosure of the information would enable others to use the information to meet NRC requirements for licensing documentation without purchasing the right to use the information.

The development of the technology described in part by the information is the result of applying the results of many years of experience in an intensive Westinghouse effort and the expenditure of a considerable sum of money.In order for competitors of Westinghouse to duplicate this information, similar technical programs would have to be performed and a significant manpower effort, having the requisite talent and experience, would have to be expended.Further the deponent sayeth not.

PROPRIETARY INFORMATION NOTICE Transmitted herewith are proprietary and/or non-proprietary versions of documents furnished to the NRC in connection with requests for generic and/or plant-specific review and approval.In order to conform to the requirements of 10 CFR 2.390 of the Commission's regulations concerning the protection of proprietary information so submitted to the NRC, the information which is proprietary in the proprietary versions is contained within brackets, and where the proprietary information has been deleted in the non-proprietary versions, only the brackets remain (the information that was contained within the brackets in the proprietary versions having been deleted).

The justification for claiming the information so designated as proprietary is indicated in both versions by means of lower case letters (a) through (f)located as a superscript immediately following the brackets enclosing each item of information being identified as proprietary or in the margin opposite such information.

These lower case letters refer to the types of information Westinghouse customarily holds in confidence identified in Sections (4XiiXa)through (4XiiXf) of the affidavit accompanying this transmittal pursuant to 10 CFR 2.390(bX)1).

COPYRIGHT NOTICE The reports transmitted herewith each bear a Westinghouse copyright notice. The NRC is permitted to make the number of copies of the information contained in these reports which are necessary for its internal use in connection with generic and plant-specific reviews and approvals as well as the issuance, denial, amendment, transfer, renewal, modification, suspension, revocation, or violation of a license, permit, order, or regulation subject to the requirements of 10 CFR 2.390 regarding restrictions on public disclosure to the extent such information has been identified as proprietary by Westinghouse, copyright protection notwithstanding.

With respect to the non-proprietary versions of these reports, the NRC is permitted to make the number of copies beyond those necessary for its internal use which are necessary in order to have one copy available for public viewing in the appropriate docket files in the public document room in Washington, DC and in local public document rooms as may be required by NRC regulations if the number of copies submitted is insufficient for this purpose. Copies made by the NRC must include the copyright notice in all instances and the proprietary notice if the original was identified as proprietary.

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