NOC-AE-04001685, License Amendment Request, Proposed One-time Revision to the Technical Specifications Regarding Standby Diesel Generator 22 Mode Change Limitations

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License Amendment Request, Proposed One-time Revision to the Technical Specifications Regarding Standby Diesel Generator 22 Mode Change Limitations
ML040760069
Person / Time
Site: South Texas STP Nuclear Operating Company icon.png
Issue date: 03/04/2004
From: Jordan T
South Texas
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
NOC-AE-04001685
Download: ML040760069 (34)
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Text

Nuclear Operating Company sT w ____

South Tows Psmed Ekul GneaftinS Staton P. Bo 289 Wd~ffiis Tas 77483 March 4, 2004 NOC-AE-04001685 10CFR50.90 U. S. Nuclear Regulatory Commission Attention: Document Control Desk One White Flint North 11555 Rockville Pike Rockville, MD 20852 South Texas Project Unit 2 Docket No. STN 50-499 License Amendment Request Proposed One-time Revision to the Technical Specifications Regarding Standby Diesel Generator 22 Mode Change Limitations

Reference:

Letter from T. J. Jordan to NRC Document Control Desk dated February 3, 2003, "Proposed Revision to the Technical Specifications Regarding Mode Change Limitations Using the Consolidated Line Item Improvement Process" (NOC-AE-04001668).

STP Nuclear Operating Company (STPNOC) submits the attached proposed amendment to South Texas Project Unit 2 Operating License NPF-80. The proposed amendment would allow STP Unit 2 to change modes with Standby Diesel Generator (SDG) 22 inoperable. This is a one-time change that would expire 14 days after entering MODE 4 on restart from the STP Unit 2 Spring 2004 refueling outage (2RE10).

In the referenced letter, STPNOC submitted a license amendment request proposing to revise the Technical Specifications mode change limitations in Specifications 3.0.4 and 4.0.4 consistent with NRC-approved Industry/Technical Specification Task Force (TSTF) Traveler number TSTF-359, "Increase Flexibility in Mode Restraints." In accordance with the CLIIP and TSTF-359 guidance, STPNOC proposed the addition of provisions that would exclude the use of the Specification 3.0.4.b risk evaluation from selected equipment. Standby Diesel Generators (Specification 3.8.1.1) are among the excluded equipment.

The attached license amendment request proposes removing the Technical Specification 3.0.4.b mode change limitation in Specification 3.8.1.1 as it would apply to inoperable Standby Diesel Generator (SDG) 22. This proposed TS revision request represents a risk-informed licensing change.

The proposed change meets the criteria of Regulatory Guide (RG) 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," and RG 1.177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking:

Technical Specifications."

STI: 31701547

NOC-AE-04001685 Page 2 of 3 The NRC issued Amendments 148 and 149 to the STP Unit 2 Operating License to approve an extension to the SDG 22 allowed outage time (AOT) so that Unit 2 could continue to operate while corrective maintenance and testing were performed on SDG 22. The duration of the AOT extension allows Unit 2 to operate up to its Spring 2004 refueling outage (2RE10).

This submittal addresses two contingencies associated with operating Unit 2 with SDG 22 inoperable for an extended time:

1. Permit restart of Unit 2 should forced shutdown occur prior to 2RE10
2. Permit restart from 2RE1O with SDG 22 inoperable with up to 14 days to restore the SDG to operable status STPNOC requests approval of the proposed amendment by April 5, 2004 and requests 30 days for implementation of the amendment after it is approved.

The STPNOC Plant Operations Review Committee has reviewed and concurred with the proposed change to the Technical Specifications.

In accordance with 10 CFR 50.91 (b), STPNOC is notifying the State of Texas of this license amendment request by providing a copy of this letter and its attachments.

If there are any questions regarding the proposed amendment, please contact Mr. S. M. Head at (361) 972-7136 or me at (361) 972-7902 I declare under penalty of perjury that the foregoing is true and correct.

Executed on /tA4a 4+o -0*

ordan Vice President, Engineering & Technical Services awh/

Attachments:

1. Description of Changes and Safety Evaluation
2. Annotated Technical Specification Page
3. Retyped Technical Specification Page

NOC-AE-04001685 Page 3 of 3 cc:

(paper copy) (electronic copy)

Bruce S. Mallett A. H. Gutterman, Esquire Regional Administrator, Region IV Morgan, Lewis & Bockius LLP U. S. Nuclear Regulatory Commission 611 Ryan Plaza Drive, Suite 400 L. D. Blaylock Arlington, Texas 76011-8064 City Public Service U. S. Nuclear Regulatory Commission David H. Jaffe Attention: Document Control Desk U. S. Nuclear Regulatory Commission One White Flint North 11555 Rockville Pike R. L. Balcom Rockville, MD 20852 Texas Genco, LP Richard A. Ratliff A. Ramirez Bureau of Radiation Control City of Austin Texas Department of Health 1100 West 49th Street C. A. Johnson Austin, TX 78756-3189 AEP Texas Central Company Jeffrey Cruz Jon C. Wood U. S. Nuclear Regulatory Commission Matthews & Branscomb P. 0. Box 289, Mail Code: MN1 16 Wadsworth, TX 77483 C. M. Canady City of Austin Electric Utility Department 721 Barton Springs Road Austin, TX 78704

NOC-AE-04001685 Attachment I Attachment 1 Description of Changes and Safety Evaluation

NOC-AE-04001685 Attachment I Page I of 24 Description of Changes and Safety Evaluation 1.0 Description The proposed amendment is a contingency change that would modify Technical Specification (TS) requirements to relax the mode change limitations in Specifications 3.0.4 and 4.0.4 with respect to inoperable Standby Diesel Generator (SDG) 22. The proposed changes are an STP plant-specific follow-up to the Nuclear Regulatory Commission (NRC) approved Industry/Technical Specification Task Force (TSTF) change TSTF-359, Revision 8, as modified by the notice in the Federal Register published on April 4, 2003 (incorporated into TSTF-359, Revision 9, which was approved by the NRC on May 12, 2003). That Federal Register Notice announced the availability of this TS improvement through the Consolidated Line Item Improvement Process (CLIIP). STPNOC submitted a proposed license amendment to adopt the CLIIP by letter dated February 3, 2004 (NOC-AE-4001668).

In accordance with the CLIIP and TSTF-359 guidance, STPNOC proposed in the February 3, 2004 letter the addition of provisions that would exclude the use of the Specification 3.0.4.b risk evaluation from selected equipment. Standby Diesel Generators (Specification 3.8.1.1) are among the excluded equipment.

The NRC issued Amendments 148 and 149 to the STP Unit 2 Operating License approving an extension to the SDG 22 allowed outage time (AOT) so that Unit 2 could continue to operate while corrective maintenance and testing are performed on SDG 22. The duration of the AOT extension allows Unit 2 to operate up to its Spring 2004 refueling outage (2RE 10).

This submittal addresses two contingencies associated with operating Unit 2 with SDG 22 inoperable for an extended time:

1. Permit restart of Unit 2 should a forced shutdown occur prior to 2RE10
2. Permit restart from 2RE1O with SDG 22 inoperable with up to 14 days to restore the SDG to operable status This is a one-time change that would expire 14 days after entering MODE 4 on restart from the STP Unit 2 Spring 2004 refueling outage (2RE I0).

This application represents what STPNOC regards as a reasonably conservative representation of the two contingencies. STPNOC would expect to supplement this application with the specific requirements and conditions should either of the contingent situations be realized.

STPNOC expects the maintenance of SDG 22 to be complete before the end of 2RE 10.

However, unexpected emergent conditions could arise such that STPNOC would not be able to restore SDG 22 to operable status before the currently scheduled end of 2REIO.

The STP Technical Specifications (TS) do not allow entry into MODE 4 or higher with an inoperable SDG. In this application, STPNOC proposes to revise the TS to permit

NOC-AE-04001685 Attachment 1 Page 2 of 24 mode changes with SDG 22 inoperable to allow restart from 2RE10. Completion of restoration to operable status, including testing, would be completed within 14 days of entering MODE 4 on restart from the outage, which is the current TS allowed outage time (AOT).

This submittal does not address SDG surveillance testing that is normally required to be performed during shutdown and which is typically performed prior to restart from an outage.

Note 11 to TS Surveillance Requirement 4.8.1.1.2 states:

(11) Credit may be taken for events that satisfy any of these Surveillance Requirements.

Note 11 was added in Amendment 85/72 to the STP Unit I and Unit 2 Operating Licenses when the SDG allowed outage time was extended to 14 days. In response to an NRC question in a letter dated August 28, 1995 (ST-HL-AE-5141), STP described the purpose of the note:

This footnote is intended to allow surveillance credit for events, either planned or unplanned, that satisfy the surveillance requirements of the Technical Specification.

These events may include the performance of the surveillance tests during the special test exception, performance of the surveillance testing during shutdown, or an actuation of the system due to a valid signal that fulfills the surveillance testing requirements. This footnote is part of the current Technical Specification NUREG 1431, Rev. 1 standard wording. This footnote will not have any impact on the normal performance of surveillance requirement testing.

The STP TS do not prohibit performing the SDG shutdown surveillance tests in other modes and Note 11 allows testing in other modes to be credited to meet the surveillance requirements.

For both contingencies, during the modes of applicability of TS 3.8.1.1, STPNOC would continue to apply the same Configuration Risk Management Program (CRMP) and compensatory actions that were committed to for the approval of Unit 2 Amendments 148 and 149, including the availability of the non-safety diesel generators (NDGs).

Although the acceptance criteria are not applicable for one-time changes such as this, the change proposed in this application meets the criteria of Regulatory Guide (RG) 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis" and RG 1.177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications."

NOC-AE-04001685 Attachment I Page 3 of 24 2.0 Description of Change The February 3, 2004 license amendment request (NOC-AE-04001668) addresses the TS format changes required for implementation of TSTF-359. This application is focused on the evaluation of the changes that are necessary to relax the TS requirements to allow mode changes with an inoperable SDG. It assumes the TSTF-359 changes will be approved as submitted.

The proposed change would remove the exception to TS 3.0.4.b proposed in letter dated February 3, 2004 for SDG 22 by revising TS 3.8.1.1 ACTION i to state:

i. Specification 3.0.4.b is not applicable for Standby Diesel Generators, except as follows: Specification 3.0.4.b is applicable to Standby Diesel Generator 22 until 14 days after entering MODE 4 from restart from the Unit 2 Spring 2004 refueling outage.

Application of the revised ACTION i to SDG 22 subsequent to a forced shutdown prior to 2RE 10 would allow restart, mode changes, and continued operation up to the expiration of the AOT approved for SDG 22 in Unit 2 Amendment 149. Application of the revised ACTION i to SDG 22 for restart from 2REIO would permit restart, mode changes, and continued operation up to the expiration of the current TS AOT of 14 days since the extended AOT approved in Amendment 149 would have expired. Both applications are based on an acceptable risk assessment of the plant configuration.

Because this is a one-time change, the provisions of the TS will revert to the original TS 3.8.1.1 requirement that TS 3.0.4.b does not apply to SDGs 14 days after MODE 4 is entered on restart from 2REIO (assuming approval of the February 3, 2004 license amendment request).

3.0 Background

3.1 Electrical Power Systems On-site AC Sources Description STP UFSAR Section 8.3.1.1.4 provides an overview of the on-site AC sources (standby diesel generators, SBDGs):

Onsite Standby Power Supply and ESF Power Distribution: The Onsite Standby Power Supply Systems of Units I and 2 each consist of three independent, physically separated, SBDGs supplying power to three associated load groups designated Train A, Train B, and Train C. Each load group consists of a 4.16 kV ESF bus and the electrical loads connected to that bus. The Onsite Standby Power Supply Systems of Units I and 2 operate independently of each other. Each SBDG and load group of a particular unit is also physically separated and electrically independent from the other two SBDGs and their load groups. Each train (i.e., Load Group) is independent but is not totally redundant; two trains are necessary to mitigate the consequences of a design basis accident (DBA). Qualification of all Class I E electrical equipment which is a part of the

NOC-AE-04001685 Attachment I Page 4 of 24 Onsite Standby Power Supply and ESF Power Distribution System is discussed in Sections 3.10 and 3.11.

Each SBDG is located in a separate room of the Diesel Generator Building (DGB), which is a seismic Category I structure (described in Section 3.8.4).

Each 4.16 kV ESF bus is provided with switching that permits energization of the bus by five alternative sources:

1. The respective unit auxiliary transformer
2. No. I standby transformer
3. No. 2 standby transformer
4. Standby diesel generator
5. 138 kV emergency transformer Each SBDG is automatically started in the event of loss of offsite power (LOOP) or safety injection (SI) signal, as described in Section 8.3.1.1.4.4, and the required Class IE loads connected to that ESF bus are automatically connected in a predetermined time sequence. Each SBDG is ready to accept load within 10 seconds after the start signal.

The SBDGs are not used for peaking and therefore the design complies with Branch Technical Position (BTP) Instrumentation and Controls System Branch (ICSB) 8.

3.2 Technical Specification Requirements The limiting condition for operation for the SDGs is described in TS 3.8.1.1. In accordance with TS 3.8.1.1.b, the allowed outage time for one inoperable SDG is 14 days. If the inoperable SDG is not restored within the allowed outage time (AOT), the plant must be shut down. Additionally, the TS do not permit changing mode (e.g., restart of the unit) with an inoperable SDG.

As described in the Technical Evaluation below, STPNOC believes that STP has sufficient redundancy and defense-in-depth to justify allowing the plant to change modes with SDG 22 inoperable provided that the risk is managed in accordance with 10CFR50.65(a)(4) and its implementation guidance, NRC Regulatory Guide 1.182, "Assessing and Managing Risks Before Maintenance Activities at Nuclear Power Plants." The management of the risk will include application of the STPNOC CRMP and the compensatory actions described in the application for the SDG 22 AOT extension that was approved in Amendment 149 to the Unit 2 Operating License.

NOC-AE-04001 685 Attachment I Page 5 of 24 4.0 Technical Evaluation 4.1 Electrical Power Systems AC Sources Safety Analysis Basis The initial conditions of DBA and transient analyses in the UFSAR, Chapter 6 and Chapter 15, assume ESF systems are OPERABLE. The AC electrical power sources are designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to ESF systems so that the fuel, Reactor Coolant System (RCS), and containment design limits are not exceeded.

The OPERABILITY of the AC electrical power sources is consistent with the initial assumptions of the accident analyses and is based upon meeting the design basis of the unit. In Modes 1, 2, 3, and 4, this results in maintaining at least two trains of the onsite or one train of the offsite AC sources OPERABLE during accident conditions in the event of:

a. An assumed loss of all offsite powver or all onsite AC power; and
b. A worst case single failure.

The allowed outage time of 14 days in TS 3.8. 1.l.b includes a combination of deterministic and risk-informed bases justified by the redundancy of the plant design and the extremely low probability of an event that cannot be mitigated by one operable ESF train.

For SDG 22, the allowed outage time was extended to 113 days on a one-time basis by application of the same combination of risk-informed and deterministic bases as for the 14-day AOT, coupled with additional compensatory actions, including availability of non-safety diesel generators.

4.2 Deterministic Evaluation (Defense in Depth and Safety Margins)

The deterministic evaluation performed for extending the SDG 22 AOT as approved in Amendment 149 is equally applicable to this submittal. It is summarized below.

When one SDG is inoperable, design-basis accident (DBA) AC power requirements can be met with the two operable SDGs, assuming no single failure.

In addition, the deterministic component of the basis for the AOT provides assurance that the plant retains a substantial capability to mitigate design-basis events with the reduced capability that results from postulating a DBA and a single failure while the plant is in the AOT, or from postulating an accident (with no single failure) in the 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> allowed by TS 3.8.1.1.d for inoperability of required equipment in one of the other trains. This evaluation shows that a single operable ESF train can mitigate (at a reduced capacity in certain cases) the design-basis accidents except for a large break LOCA where the break is located in the RCS loop associated with the operating train of safety injection. Because postulation of these events is beyond the design basis of the plant, in some cases the deterministic analyses apply less conservative acceptance criteria than those required of

NOC-AE-04001685 Attachment I Page 6 of 24 design basis analyses. These capabilities are described in detail in STP's license amendment application to extend the SDG AOT to 14 days, which was approved in Amendments 85/72 to the STP Operating Licenses.

Spent Fuel Pool Cooling SDG 22 is one of the two SDGs that provide emergency power for the two 100%

trains of Spent Fuel Pool Cooling (SFPC). In the event of a loss of off-site power with one of these two SDGs inoperable and a single failure of the other SDG, the heat-up rate of the SFP will be slow enough such that restoration of off-site power would be expected before boiling would occur in the SFP. In addition, as discussed in Section 7.0, the NDGs and a cross-connect capability are available to provide emergency power to SFPC.

Based on these evaluations, STPNOC has concluded that the proposed change maintains the same defense-in-depth and safety margins that were determined to be acceptable in the review and approval for extending the original AOT to 14 days (Amendment 85 to the Unit I and Amendment 72 to the Unit 2 Operating Licenses) and for approval of the extension of the Unit 2 SDG 22 AOT (Amendment 149 to the Unit 2 Operating License).

4.3 Risk Assessment Although the proposed change is a one-time change and the RG 1.1 74 and RG 1.177 acceptance criteria are not directly applicable, STPNOC conservatively evaluated the proposed change against those criteria. Risk is managed for the duration of a SDG AOT by applying the STP Configuration Risk Management Program, which implements the requirements of 10 CFR 50.65(a)(4) and its implementation guidance, NRC Regulatory Guide 1.182, "Assessing and Managing Risks Before Maintenance Activities at Nuclear Power Plants."

Risk-informed considerations for the proposed change consist of:

  • Maintaining defense-in-depth (discussed in Section 4.2).

Modifying the PRA to model Mode 3 operation of the plant.

Quantifying the PRA to determine the change in core damage frequency (CDF) and large early release frequency (LERF) that result from allowing changing mode with an inoperable SDG.

Performing a limited evaluation of Mode 4 operation using selected elements from the PRA.

  • Continuation of the STP configuration risk management program to control performance of other risk significant tasks during the SDG maintenance, and
  • Consideration of specific compensatory measures to minimize risk.

The risk impact of the proposed change has been evaluated and found to be acceptable and is within acceptable limits of current regulatory guidance.

NOC-AE-04001685 Attachment I Page 7 of 24 4.3.1 RG 1.174 Evaluation The proposed change has been evaluated in accordance RG 1.174 by applying the "three-tier" approach.

Tier I - PRA Capability and Calculation of Risk Insights Tier 2 - Avoidance of Risk-Significant Plant Configurations Tier 3 - Risk-Informed Configuration Risk Management 4.3.1.1 Tier I - PRA Capability and Calculation of Risk Insights 4.3.1.1.1 PRA Capability The STP PRA is a full-scope, at-power (Plant MODE I and MODE 2)

Level I / 2 PRA that incorporates internal events, inclusive of fires/floods, and external events (seismic, fire, flood). STP's PRA features a seismic PRA, flood/fire PRA (including spatial interactions analysis), human reliability analysis, and detailed common cause modeling. The model is quantified using the RISKMAN software code that has met station and industry software quality assurance requirements. The PRA is maintained and updated under a PRA configuration control program in accordance with station procedures. The station's PRA program and associated processes are governed by procedure. Periodic reviews and updates, if necessary, are performed for plant changes (including as a minimum, performance data, procedures, and plant modifications) by qualified personnel with independent reviews and approvals. The STP PRA has undergone a recent industry Peer Review.

Additional details regarding the STP PRA capability were provided in a letter dated December 20, 2003 (NOC-AE-03001653) in support of an emergency TS change for a one-time extension of the AOT for SDG 22 that was approved in Amendment 149 to the STP Unit 2 Operating License.

The PRA has been modified to support I OCFR50.65.a(4) evaluations while the plant is in Mode 3. The modifications consisted of removing selected initiating events that are not applicable to Mode 3 operation from the set of initiating events considered. Mode 4 is considered separately as described below.

4.3.1.1.2 Calculation of Risk Insights Regulatory Guide (RG) 1.174 describes a general approach to risk-informed regulatory decision-making and contains different acceptance criteria using changes in core damage frequency and large early release frequency. The results of the risk analysis performed for the proposed change meet the acceptance criteria contained in RG 1.174 as shown below.

NOC-AE-04001 685 Attachment I Page 8 of 24 RG 1.177 provides more specific guidance for changes to the Technical Specifications.

Method of Analysis:

This evaluation looks at the risk associated with shutdown operation and the transition to power operation for transitioning from shutdown states, Modes 3 and 4, to power states, Modes I and 2 for Standby Diesel Generator (SDG) 22.

In order to support the proposed technical specification change, this analysis compares the risk associated with fourteen days of SDG 22 unavailability at power with the risk associated with operation at Modes 3 and 4 followed by a return to power operation.

Assumptions

  • The PRA model can be modified and exercised to demonstrate the risk associated with Mode 3 operation.
  • Mode 4 core damage risk can be estimated using RHR, AFW, and SG heat removal system models and evaluating the likelihood of loss of core cooling. The occurrence of other initiating events and the associated core damage frequencies are similar to calculated for Mode 3.
  • In Mode 4, one or two RHR pumps are assumed to be initially operating.
  • No other planned maintenance is being performed.
  • The frequency of a loss of offsite power in Mode 4 or Mode 3 is not affected by the plant state, only the conditions in the offsite distribution system.
  • No changes in the Zero Maintenance PRA model CRMPREV4 are necessary to perform this assessment.
  • All assumptions in the STP PRA remain unchanged.

NOC-AE-04001 685 Attachment I Page 9 of 24 Analvsis Zero Maintenance Assessment The Zero Maintenance Core Damage Frequency (CDF) (per year) and Large Early Release Frequency (LERF) (per year) for the various support system states is:

tPower ZERO peryear) CDF LERF ABRUN 7.21E-06 3.98E-07 BCRUN 7.30E-06 4.07E-07 ACRUN 7.22E-06 3.99E-07 Average 7.25E-06 4.01E-07 The CDF and LERF (per year) for the various support system states with SDG 22 out of service is:

Power DGB (peryear) CDF LERF BRUN 2.79E-05 1.93E-06 BCRUN 2.82E-05 1.95E-06 CRUN 2.89E-05 2.01E-06 verage 2.83E-05 1.96E-06 The incremental conditional core damage probability (ICCDP) and incremental conditional large early release probability (ICLERP) is calculated by subtracting Zero Maintenance CDF or LERF from the CDF or LERF with SDG 22 out of service, dividing by the number of hours in a year, and multiplying by the expected AOT (14 days). The ICCDP and the ICLERP associated with fourteen days of diesel generator unavailability at power for the various support systems states is:

AtPower DGB (14 Days) ICCDP ICLERP ABRUN 7.92E-07 5.86E-08 BCRUN 8.01E-07 5.91E-08 ACRUN 8.31E-07 6.16E-08 Average 8.08E-07 5.98E-08 These results are the At-Power Comparison Case for the Mode Three and Four evaluations and are summarized in Table 2.

NOC-AE-0400 1685 Attachment I Page 10 of 24 Mode 2 Assessment Using early industry experience, there could potentially be a slight increase in the likelihood of occurrence of a plant trip during startup when the generator breaker first closes or when feedwater control is on the feedwater control bypass valves. In 1990 during synchronization to the grid, an undervoltage condition at the 13.8kV switchgear tripped the reactor coolant pumps and caused a plant trip from 15% powver (LER 90-014). Plant procedures for startup were modified to prevent recurrence. All other STP initiating events that occurred with reactor powver less than 40% were not influenced by the plant power level. Recent industry experience and STP specific history indicate better operator training, more comprehensive procedures, and better control systems have reduced the likelihood of a transient-induced plant trip at low power. The trip that occurred at STP is included in the transient initiating event frequencies used to quantify the at-power model. No changes to initiating event frequencies due to transitioning through Mode 2 are included in this evaluation.

Mode 3 Assessment The PRA was modified to simulate a Mode 3 PRA by removing the initiating events that can only occur at power from the model quantification batch files and modifying the rules associated with Top Event RT which models the reactor trip function to indicate guaranteed success of this function. Table I identifies the initiating events used to quantify the Mode 3 plant condition.

In Mode 3, the zero maintenance CDF and LERF are:

Mode 3 ZERO (per year) CDF LERF XBRUN 6.84E-06 3.85E-07 BCRUN 6.93E-06 3.94E-07 LCRUN 6.85E-06 3.86E-07 The CDF and LERF (per year) for the various support system states with SDG 22 out of service in Mode 3 is:

Mode 3 DGB (per year) CDF LERF ABRUN 2.54E-05 1.73E-06 BCRUN 2.57E-05 1.75E-06 ACRUN 2.64E-05 1.81 E-06 Average 2.58E-05 1.76E-06 The increase in risk due to the transition from Mode 3 to Mode I is calculated by subtracting the Mode 3 result from the Mode I results.

NOC-AE-04001 685 Attachment I Page I I of 24 Table 2 presents the results for combinations of SDG 22 and support system states for transitioning from Mode 3 to Mode 1. As can be seen in Table 2, the increase in risk as measured by the ACDF and ALERF due to the change in plant status from Mode 3 to Mode I is small. The increase is due entirely to the addition of transient initiators and the reactor trip function to the plant damage matrix when the plant is producing power. For a fourteen-day SDG outage, the ICCDP is approximately 8.lE-08 and the ICLERP is approximately 7.1 E-09. Both of these values are well below the limits established in Regulatory Guide 1.177 for permanent changes to plant technical specifications.

Mode 4 Assessment STP does not currently have a model for Mode 4 operation; however, limited evaluations of potential changes in core damage probability are possible. In order to prevent core damage, reactor decay heat must be removed. In Mode 4, this is typically accomplished using the residual heat removal (RHR) system. The RHR system at South Texas consists of three independent trains, each train containing an RHR pump, an RHR heat exchanger, two normally closed MOVs in the pump suction from the reactor coolant system hot leg, and the piping and valves necessary to deliver the flow to the reactor coolant system cold legs. If the RHR system is unavailable or fails, the steam generators are capable of removing decay heat using the auxiliary feedwater motor-driven pumps and the steam generator PORVs. For purposes of analysis, flow from the turbine-driven AFW pump is not credited. Failure of both forms of decay heat removal would require some form of primary feed and bleed using the safety injection pumps, the pressurizer PORVs, and long-term recirculation cooling of the containment sump.

With the exception of loss of RHR, the set of initiators applicable to Mode 4 operation are similar to the set of initiators discussed in the Mode 3 evaluation and no adjustment is made for the frequency of the Mode 4 initiating events.

If one of the listed initiating events were to occur in Mode 4, the CDF and LERF presented for the Mode 3 results would bound the results for Mode 4 CDF and LERF.

NOC-AE-04001685 Attachment I Page 12 of 24 For the loss of RHR initiating event, the system failure frequencies under various boundary conditions are presented below:

AFW - Motor Driven 3 Motors 2 Motors 2.21E-05 8.06E-05 SIG PORV 3 S/Gs 2 SIGs 2.96E-04 2.29E-03 HHSI 3 Trains 2 Trains 2.51 E-05 1.17E-04 Si Common 3 Trains 2 Trains 3.01E-06 7.76E-06 Pressurizer Feed and 2 of 2 1 .26E-02 In Mode 4, one RHR train is typically operating to remove core decay heat.

Shortly after a plant shutdown two RHR trains may be operating initially. The likelihood of failure of the RHR function with two trains initially operating is

- 2.4E-05 per hour (Reference 1). With three trains of AFW and the associated steam generator PORVs, three trains of high head safety injection (HHSI), three trains of SI Common, and pressurizer feed and bleed available, the likelihood of core damage is estimated to be:

Core Damage = RHR Fails AND (AFW OR SG PORVs Fail) AND (HHSI OR SI Common OR Feed and Bleed Fails)

The Conditional Core Damage Probability (CCDP) is:

CCDP = 2.4E-05/hr

  • 24 hrs/day
  • 14 days
  • 4.02E-06 = 3.2E-08 The total CCDP for Mode 4 can be estimated by summing the Mode 3 CCDP for 14 days of SDG outage and the CCDP presented above.

Mode 4 CCDP = 7.3E-07 + 3.2E-08 = 7.6E-07 As a sensitivity case, with one diesel generator unavailable and a loss of offsite power, two RHR pumps, two AFW pumps, and two steam generators are available to remove core decay heat.

The CCDP for this condition is:

CCDP = 2.4E-05/hr

  • 24 hrs/day
  • 14 days
  • 3.01 E-05 = 2.4E-07

NOC-AE-04001685 Attachment I Page 13 of 24 The likelihood of a loss of offsite power (LOOP) for a fourteen-day AOT from the STP PRA model (Reference 2) is determined by adding the initiating event frequencies of the two modeled LOOPs (loss of 345kV and Loss of All Offsite Power), dividing by 8760 hours0.101 days <br />2.433 hours <br />0.0145 weeks <br />0.00333 months <br /> and multiplying by 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />s/day and 14 days. The LOOP initiating event probability for a loss of otTsite power during a fourteen-day period is:

ILOOP = (LOSP + LOSPX)!8760

  • 24
  • 14 ILOOP = (3.58E-02 + 1.99E-02)/8760
  • 24
  • 14 = 2.1 E-03 The CCDP for Loss of RHR following a LOOP is the product of the two results, or:

CCDP = 2.4E-07

  • 2. IE-03 = 5.2E-10 This result is small in relation to the CCDP for Loss of RHR without a LOOP.

Conclusion The incremental conditional core damage probability (ICCDP) at power for a fourteen-day outage of SDG 22 is approximately 8.1 E-07 and the incremental conditional large early release probability (ICLERP) is approximately 6.OE-08 (See Table 2). The equivalent values for Mode 3 and Mode 4 are:

ICCDP ICLERP Mode 3 7.3 E-07 5.3E-08 Mode 4 7.6E-07 5.3E-08 The increase in risk from Mode 4 or Mode 3 to Mode 1, approximately 8E-08 for ICCDP and 7E-09 for ICLERP, is not risk significant in comparison to the limits described in Regulatory Guide 1.177 for permanent changes to the plant technical specifications.

The risk associated with operation in Mode 3 or 4 and in transitioning from Mode 4 or Mode 3 to power with SDG 22 non-functional is less than the risk associated with a standard SDG EAOT at power. The change in risk, however, is very small and would satisfy the requirements for a permanent plant technical specification change in accordance with the guidance provided in RG 1.177.

NOC-AE-0400 1685 Attachment I Page 14 of 24 Plant compensatory measures that are not included in the results include:

  • The capability to transfer power from one unit's diesel generators to the other unit's Class I E 4kV buses
  • The non-safety diesel generators currently available in the plant switchyard. With credit for the NDGs, the calculated delta risks would be substantially lower, and the potential increase in risk due to transitioning from shutdown to power operation would be correspondingly less.
  • The cross-tie capability among the affected units Class IE 4kV buses.

NOC-AE-04001 685 Attachment I Page 15 of 24 Table 1 Initiating Events in the Mode 3 RISKMAN Batch File Loss of Coolant Accidents Excessive LOCA Large LOCA Medium LOCA Small LOCA - Isolable Small LOCA - Unisolable Pressurizer Safety Valve Opening Pressurizer PORV Opening RCP Seal LOCA Interfacing Systems LOCA Steam Generator Tube Rupture External Events High Wind MCR Breach (3)

Seismic Events (4)

Plant Fires - Control Room (3)

Plant Fires - Other (5)

Loss of Offsite Powver Loss of 345kV Loss of 345kV and 138kV Support System Initiating Events Loss of DC Bus A Loss of DC Bus B Loss of CCW (3)

Loss of ECW (3)

Loss of EAB HVAC (3)

Loss of CR HVAC (3)

Other Events Steam Line break Inside Containment Steam Line Break Outside Containment

NOC-AE-04001 685 Attachment I Page 16 of 24 Table 2 Chan2c in CDP and LERP for Transitionin2 from Mlode 3 to Mode I Power ZERO DGB Mode 3 ZERO DGB (per ear) CDF LERF CDF LERF (per year) CDF LERF CDF LERF ABRUN 7.21 E-06 [ 3.98E-07 2.79E-05 1.93E-06 ABRUN 6.84E-0 3.85E-07 2.54E-05 1.73E-06 BCRUN 7.30E-06 4.07E-07 2.82E-05 1.95E-06 BCRUN 6.93E-061 3.94E-0 2.57E-05 1.75E-06 ACRUN 7.22E-06 3.99E-07 2.89E-05 2.01E-06 ACRUN 6.85E-061 3.86E-07 2.64E-05 1.81 E-06 Average 7.25E-06 j 4.01E-07 2.83E-05 1.96E-06 Average 2.58E-05 1.76E-06 DELTA - At Power DCDF DLERF DELTA - Mode 3 DCDF DLERF ABRUN - l 2.07E-05 1.53E-06 BRUN l _ 1.86E-05 1.35E-06 BCRUN I - I - 2.09E-05 1.54E-06 SCRUN 1.88E-05 1.36E-06 ACRUN -- - 2.17E-05 1.61 E-06 ACRUN _ 1.95E-05 1.42E-06 tAverage 2.11E-05 1.56E-06 Average 1.90E-05 1.37E-06 14-day Diesel Generator AOT DGB 14-day Diesel Generator AOT DGB ICCDP I ICLERP in Mode 3 ICCDP ICLERP ABRUN 7.92E-07 5.86E-08 ABRUN 7.12E-07 5.16E-08 BCRUN 8.01E-07 5.91E-08 BCRUN 7.21E-07 5.21 E-08 ACRUN 8.31E-07 6.16E-08 ACRUN 7.49E-07 5.44E-08 Average 8.08E-07 5.98E-08 Average 7.27E-07 5.27E-08 Change - Mode 3 to Power DGB (per year) DCDF DLERF rABRUN 2.09E-06 1.82E-07 lBCRUN 2.10E-06 1.83E-07 lACRUN 2.15E-06 1.87E-07 Average 2.11 E-06 1.84E-07 Change - Mode 3 to Power DGB (14 days) ICCDP ICLERP ABRUN 8.OOE-08 6.98E-09 BCRUN 8.05E-08 7.02E-09 ACRUN 8.23E-08 7.18E-09 Average 8.09E-08 7.06E-09 References

1) An Analysis of Loss of Decay Heat Removal Trends and Initiating Event Frequencies (1989-2000), EPRI/TR-10031 13, November 2001.
2) STP PRA Mode, STPREV4, dated September 2003.

NOC-AE-0400 1685 Attachment I Page 17 of 24 4.3.1.2 Tier 2- Avoidance of Risk-Significant Plant Configurations There is reasonable assurance that risk-significant plant equipment configurations will not occur when SDG 22 is out of service (OOS) consistent with the proposed TS change. Increases in risk posed by potential combinations of equipment OOS will be managed by the Configuration Risk Management Program (CRMP).

The compensatory measures may be implemented to avoid risk-significant plant configurations during SDG AOTs. This is achieved by minimizing planned maintenance activities that could have adverse risk impacts and by ensuring that key equipment necessary to respond to loss of offsite power events (e.g., turbine driven auxiliary feedwater pump) remains available for service.

The compensatory actions listed below have been implemented for the SDG 22 extended AOT in accordance with procedure OPOPOI-ZO-0006, "Extended Allowed Outage Time." These compensatory actions are required in MODE 1, 2, 3, and 4 when TS 3.8.1.1 applies. For MODE 5 and 6 operations (i.e. during 2RE 10),

the requirements of shutdown TS 3.8.1.2 and TS 3.S. 1.3 can be met with SDG 21, SDG 23, and the NDGs. STPNOC would impose these compensatory actions for the proposed change for restart from a forced shutdown prior to 2REIO or for restart from 2REl0 when changing plant modes to MODE 4 and higher where TS 3.8.1.1 applies and SDG would normally be required to be operable:

  • Notification of the transmission/distribution service providers (TDSP) of the condition and of the maintenance restrictions required for the STP switchvard.
  • Hang EAOT protected train signs.
  • Planned maintenance on required systems, subsystems, trains, components, and devices that depend on the other trains of equipment during the EAOT SHALL NOT be performned.
  • No maintenance that could result in an inoperable OPEN containment penetration.
  • Containment purges shall be for pressure control only and for short duration.
  • No planned maintenance on the Unit 2 TSC DG.
  • No planned maintenance on Load Center 2W.
  • No planned maintenance on MCC 2G8.
  • No planned maintenance on the Positive Displacement Charging Pump (PDP).
  • No planned maintenance on the Emergency Transformer or the 138KV Blessing to STP and Lane City to Bay City lines.

NOC-AE-04001 685 Attachment I Page 18 of 24

  • No maintenance activities in the switchyard that could directly cause a Loss of Offsite Power event unless required to ensure the continued reliability and availability of the offsite power sources.
  • Verify that the station is NOT under hurricane, tornado, or flood watches or warnings.
  • Verify (or for unplanned entry, attempt to verify) with the TDSP that NO adverse weather conditions exist in the areas of our offsite power supplies that challenge the stability of grid.
  • Ensure the Work Schedule contains NO planned maintenance on SWGR 2L or 2K.

Severe Weather Considerations The STP PRA model loss of offsite power (LOOP) frequency includes causes of LOOP and incorporates site-specific grid recovery information.

STP has not experienced a LOOP as defined and analyzed in the PRA (i.e.,

loss of power in the switchyard and safety busses, with a plant trip). The frequency and duration of LOOP events are based in part on conditions, such as severe weather, external to the plant and specific to the plant location. Severe weather events typically have longer durations for recovery because of the possibility of widespread effects but occur less frequently than other causes of LOOP. Severe weather events at the South Texas Project location are dominated by high winds caused by tornadoes and hurricanes. Tornadoes can occur any time during a year, but typically occur most frequently between March and June.

STPNOC's Procedure OPOP04-ZO-0002, "Natural or Destructive Phenomena Guidelines," addresses actions to be taken for a tornado watch or tornado warning. It includes requirements to verify availability of emergency power and operability of decay heat removal systems such as Auxiliary Feedwater.

4.3.1.3 Tier 3 - Risk-Informed Configturation Risk Management STP's CRMP was described in the application for the extension to the SDG 22 AOT approved in Amendment 149. The description is repeated below with additional specifics pertinent to this application to allow mode change with SDG 22 inoperable.

STP's Configuration Risk Management Program ensures that on-line risk levels are appropriately evaluated prior to performing any maintenance activity. This program provides guidance for managing plant trip risk, nuclear safety risk, and safety function degradation from on-line maintenance, external or internal conditions, as

NOC-AE-0400 1685 Attachment I Page 19of24 required by 10 CFR 50.65(a)(4) of the Maintenance Rule. The procedure addresses risk management practices in maintenance planning and execution.

The proposed action conforms to the requirements of the STP CRMP. The CRMP is controlled by procedure OPGP03-ZA-009 1, "Configuration Risk Management Program." South Texas will continue to use the CRIMP to evaluate and monitor the risk significance associated with mode changes with an inoperable SDG. The CRMP requires the compensatory measures listed below to be implemented if the Non-Risk Significant Threshold of .OE-6 is exceeded. The STP CRMP satisfies the Maintenance Rule requirements as specified in I0CFR50.65(a)(4).

  • Notify the Duty Operations and Duty Plant Manager
  • Identify and implement compensatory measures approved by the Duty Plant Manager. Compensatory measures may include but are not limited to the following:

- Reduce the duration of the risk-sensitive activities

- Remove risk-sensitive activities from the planned work scope

- Reschedule work activities to avoid high risk-sensitive equipment outages or maintenance states

- Accelerate the restoration of out-of-service equipment

- Determine and establish the safest plant configuration

- Establish contingency plan to reduce the effects of the degradation of the affected SSC(s) by utilizing the following:

  • Operator actions
  • Increased awareness of plant configuration concerns and the effects of certain activities and transients on plant stability

. Administrative controls

  • Ensure availability of functionally redundant equipment
  • Ensure any measures taken to reduce risk are recorded in the Control Room Logbook.
  • Heighten station awareness of plant conditions and evolutions as deemed necessary by the Duty Plant Manager.

The PRA evaluation for permitting the mode changes with SDG 22 inoperable and for the SDG 22 AOT extension was performed assuming "zero maintenance" (except for required TS surveillances) for that time. As discussed in the application for the AOT extension for SDG 22, while SDG 22 is inoperable beyond its normal 14-day AOT, STPNOC will suspend planned maintenance of components that could affect the risk calculated for the SDG 22 AOT extension and the proposed mode change allowance. The suspension of the planned maintenance applies only when TS 3 .8.1].1 is applicable.

NOC-AE-04001685 Attachment I Page 20 of 24 Although BOP initiating events are modeled in the Probabilistic Risk Assessment (PRA) (e.g., loss of feedwater), changes in BOP trip risk due to secondary equipment unavailability is not included in the risk calculated for the SDG 22 AOT.

However, the CRMP risk monitor can quantify the change in BOP trip risk and the impact to core damage frequency (CDF). The impact to CDF of planned maintenance of BOP secondary equipment is typically not significant. STPNOC monitors and controls changes in BOP trip risk due to planned maintenance activities in accordance with the CRMP. In addition, during the SDG 22 AOT, approval of the operations management will be required prior to performing planned maintenance that will increase BOP trip risk.

If A or C train components required by TS are found to be inoperable, STPNOC will apply the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> ACTION of TS 3.8. 1.Ld as required and perform corrective maintenance to restore the components within the TS 3.8. 1. .d required action times or follow the shutdown action required by the TS. For B train components required by TS found to be inoperable, STPNOC will apply the appropriate TS and perform corrective maintenance in accordance with the required action times for that TS. If no TS applies, STPNOC will restore the component to operable status as promptly as practical.

STPNOC would similarly apply TS 3.8.1.l.c for corrective maintenance for emergent conditions where a required off-site power source is lost while SDG 22 is not operable and TS 3.S. 1.l.f where more than one SDG is inoperable. STPNOC may perform SRs for SDG 21 or SDG 23 where the SDG is functional, but not operable, for part of the SR. This condition would require entry into TS 3.8.1.L.f.

STP will monitor changes in planned risk levels using the CRMP. During the extended AOT, the calculated average CDF levels will be updated in the event unplanned maintenance is required on equipment within the scope of the CRMP.

Risk levels will be monitored throughout the SDG 22 outage and STP will comply with the risk threshold actions required by the CRMP. In addition, STPNOC will keep the NRC Resident Inspector apprised of deviations from the expected risk profile for the duration of the SDG 22 repair.

4.3.1.4 Non-Safety-Related Diesel Generator(NDG) Capabilitv As committed in the application for the extension to the SDG 22 AOT, STPNOC installed four vendor-supplied diesel generator sets to provide temporary power.

Each diesel is rated for 1350 kW prime at a 0.8 power factor. The NDGs are located sufficiently far away from overhead 345 kV and 138 kV transmission lines so not to present a potential hazard. Each NDG has its own isolation circuit breaker. The temporary equipment includes a set of vendor-supplied step-up transformers to facilitate connection to STP's 13.8 kV non-safety switchgear located in the switchyard. The 13.8 kV non-safety switchgear can be connected through the non-safety emergency 13.8 kV electrical system to allow a source of electrical power to the unit's 4160V ESF buses.

NOC-AE-04001685 Attachment I Page 21 of 24 The NDGs are capable of supplying power to an essential cooling water pump, an auxiliary feedwater pump, and required electrical auxiliary building ventilation to provide a backup power source for achieving safe shutdown. The NDGs are also capable of providing emergency power for spent fuel pool cooling. Each NDG is capable of operating for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> without refueling. Only three of the four NDGs are required to supply these loads.

Additional detail regarding the NDGs and their treatment in the PRA was provided in the application for the SDG 22 AOT approved in Amendment 149.

5.0 Regulatory Assessment 5.1 No Sianificant Hazards Detennination In 10 CFR 50.92(c), the Nuclear Regulatory Commission (NRC) provides the following standards to be used in detennining the existence of a significant hazards consideration:

...a proposed amendment to an operating license for a facility licensed under 50.21 (b) or 50.22, or for a testing facility involves no significant hazards consideration, if operation of the facility in accordance with the proposed amendment would not: (1) Involve a significant increase in the probability or consequences of an accident previously evaluated; or (2) Create the possibility of a new or different kind of accident from any accident previously evaluated; or (3) Involve a significant reduction in the margin of safety.

STPNOC has reviewed the proposed amendment request and determined that its adoption does not involve a significant hazards consideration based as discussed below.

I. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No.

SDG 22 provides onsite electrical power to one of three trains of vital systems should offsite electrical power be interrupted. It is not an initiator to any accident previously evaluated. Therefore, allowing a mode change with SDG 22 out-of-service will not increase the probability of an accident previously evaluated.

SDG 22 acts to mitigate the consequences of design-basis accidents that assume a loss of offsite power. For that purpose, redundant standby diesel generators are provided to protect against a single failure. During the Technical Specification allowed outage time, an operating unit is allowed by the Technical Specifications to remove one of the standby diesel generators from service, thereby losing this single-failure protection. This operating condition is considered acceptable. The consequences of a design-basis accident coincident with a failure of the redundant standby diesel generator during the extended allowed outage time are the same as

NOC-AE-0400 1685 Attachment I Page 22 of 24 those during the 14-day allowed outage time. Therefore, during the changes in mode there is no significant increase in consequences of an accident previously evaluated.

Therefore, the proposed change will not involve 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.

There are no new failure modes or mechanisms created due to plant operation for changing mode with an inoperable standby diesel generator. The proposed change does not involve any modification in the operational limits or physical design of plant systems. There are no new accident precursors generated due to permitting mode changes with an inoperable standby diesel generator.

Therefore, the proposed change does not create the possibility of a new or different kind of accident from any accident previously evaluated.

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

Response: No.

Plant mode changes with an SDG 22 inoperable have been shown to have a very small impact on plant risk using the criteria of RG 1.174 and RG 1.177. During the mode change, the electrical power system maintains the ability to perform its safety function of providing an available source of power to the Engineered Safety Feature (ESF) systems as assumed in the accident analyses. During the mode change with an inoperable standby diesel generator, risk impact will be managed through the application of 10 CFR 50.65(a)(4) and its implementation guidance, NRC Regulatory Guide 1.182, "Assessing and Managing Risks Before Maintenance Activities at Nuclear Power Plants." The results of the risk assessment will be considered in determining the acceptability of entering the mode or other specified condition in the Applicability, and any corresponding risk management actions.

Therefore, the proposed change does not involve a significant reduction in a margin of safety as defined in the basis for any Technical Specification.

NOC-AE-04001 685 Attachment I Page 23 of 24 6.0 Environmental Evaluation STPNOC has evaluated the proposed changes and determined the changes do not involve (1) a significant hazards consideration, (2) a significant change in the types or significant increase in the amounts of any effluents that may be released offsite, or (3) a significant increase in the individual or cumulative occupational exposure. Accordingly, the proposed changes meet the eligibility criteria for categorical exclusion set forth in 10 CFR 51 .22(c)(9), and an environmental assessment of the proposed changes is not required.

7.0 Verification and Commitnmcnts The commitments and verifications made in the February 3, 2004 license amendment request to incorporate the generic provisions of TSTF-359 to relax TS 3.0.4 mode change restrictions (Reference 4) also apply to this application. However, STPNOC does not plan to revise the Bases specifically for a one-time change for SDG 22.

The commitments below were made as part of the implementation of Amendment 149 for the extended AOT for SDG 22 and are applicable to this proposed change (References I and 2).

  • Station procedures for responding to inclement weather include guidance for coping with icing conditions that are affecting the offsite distribution system and apply a similar strategy to the strategy currently in place to respond to hurricane force winds onsite. Specifically, in the event of a determination by the Duty Plant Manager after consultation with the TDSP that icing conditions in the area of STP may result in a loss of all power to the switchyard, STP will commence a shutdown of Unit 2 to Mode 3. The procedure will also require that one Standby Diesel be started and loaded to its ESF bus and that the ESF bus be subsequently removed from offsite power. These procedure revisions will be completed by December 23, 2003.
  • STP has procedural guidance to supply electrical power to an ESF bus in a unit that has lost all electrical power to its ESF busses from a functioning Emergency Diesel in the opposite unit. This procedure will only be implemented when the failure of emergency power sources in a unit has occurred (including the temporary non-safety-related diesels described in the compensatory actions) such that the remaining emergency power is judged to be inadequate for mitigation of the event and sufficient power is available in the opposite unit to meet its electrical power requirements.
  • STP will monitor changes in planned risk levels using the CRMP. During the extended AOT, the calculated average CDF levels will be updated in the event unplanned maintenance is required on equipment within the scope of the CRMP.

Risk levels will be monitored throughout the SDG 22 outage and STP will comply with the risk threshold actions required by the CRMP. In addition, STPNOC will

NOC-AE-04001685 Attachment I Page 24 of 24 keep the NRC Resident Inspector apprised of deviations from the expected risk profile for the duration of the SDG 22 repair.

The temporary non-safety-related diesel capability described in letter dated December 20, 2003 (NOC-AE-03001653) will be available for use.

8.0 References I. Letter from T. J. Jordan, STPNOC, to NRC Document Control Desk. dated December 20, 2003, "Revision to Proposed Emergency Change to Technical Specification 3.8.1.1" (NOC-AE-03001653)

2. Letter from T. J. Jordan, STPNOC, to NRC Document Control Desk, dated December 27. 2003, "Proposed Emergency Change to Technical Specification 3.8.1.1 Note 12" (NOC-AE-03001657)
3. Letter from David Jaffe, NRC, to J. J. Sheppard, STPNOC, dated December 30, 200)3, "South Texas Project, Unit 2 - Issuance Of Amendment Concerning One-Time Allowed Outage Time Extension For No. 22 Standby Diesel Generator (TAC NO.

MC1643)"

4. Letter from T. J. Jordan, STPNOC, to NRC Document Control Desk, dated February 3, 2004, "Proposed Revision to the Technical Specifications Regarding Mode Change Limitations Using the Consolidated Line Item Improvement Process" (NOC-AE-04001668)

NOC-AE-0400 1685 Attachment 2 Page I of 2 Attachment 2 Annotated Technical Specification Page

NOC-AE-0400 1685 Attachment 2 Page 2 of 2 ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION ACTION (continued)

g. With one or more diesel generator fuel oil storage tanks with stored fuel oil total particulates not within the Diesel Fuel Oil Testing Program limits, within 7 days restore the fuel oil total particulates within limits, or declare the associated standby diesel generator(s) inoperable.
h. With one or more diesel generator fuel oil storage tanks with new fuel oil properties not within the Diesel Fuel Oil Testing Program limits, within 30 days restore the fuel oil properties within limits, or declare the associated standby diesel generator(s) inoperable.
i. Specification 3.0.4.b is not applicable for standby diesel generators, except as follows: Specification 3.0.4.b is applicable to Standby Diesel Generator 22 until 14 days after entering MODE 4 from restart from the Unit 2 Spring 2004 refueling outage.

SOUTH TEXAS - UNITS 1 & 2 3/4 8-2a Unit 1 -Amendment No. 151 Unit 2-Amendment No. 139

NOC-AE-0400 1685 Attachment 3 Page I of 2 Attachment 3 Retyped Technical Specification Page

ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION ACTION (continued)

g. With one or more diesel generator fuel oil storage tanks with stored fuel oil total particulates not within the Diesel Fuel Oil Testing Program limits, within 7 days restore the fuel oil total particulates within limits, or declare the associated standby diesel generator(s) inoperable.
h. With one or more diesel generator fuel oil storage tanks with new fuel oil properties not within the Diesel Fuel Oil Testing Program limits, within 30 days restore the fuel oil properties within limits, or declare the associated standby diesel generator(s) inoperable.
i. Specification 3.0.4.b is not applicable for standby diesel generators, except as follows:

Specification 3.0.4.b is applicable to Standby Diesel Generator 22 until 14 days after entering MODE 4 from restart from the Unit 2 Spring 2004 refueling outage.

SOUTH TEXAS - UNITS 1 & 2 3/4 8-2a Unit 1 -Amendment No. 454, Unit 2 - Amendment No. 439,

Nuclear Operating Company Souwth 7= PmlcctEkc=rc G=1cngStxfon PO. Box 289 Mrdsworth. Ts 77483 -- %WAN--

March 4, 2004 NOC-AE-04001 689 10CFR 2.202 Secretary, Office of the Secretary of the Commission U.S. Nuclear Regulatory Commission ATTN: Rulemakings and Adjudications Staff Washington, DC 20555 South Texas Project Units 1 & 2 Docket Nos. STN 50-498, STN 50-499 Response to First Revised Order Modifving Licenses (EA-03-009)

STP Nuclear Operating Company (STPNOC) has received the NRC First Revised Order Establishing Interim Inspection Requirements for Reactor Pressure Vessel Heads at Pressurized Water Reactors dated February 20, 2004. Pursuant to 10 CFR § 2.202, STPNOC files this answer consenting to the NRC Order, and indicating its decision to not request a hearing.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on: 3S L' o/

J. J. Sheppard President & Chief Executive Officer 04001689 (First Revised RPV Head Inspection Order - 2.202 Response).doc STI 31704943

NOC-AE-04001689 Page 2 of 2 cc:

(paper copy) (electronic copy)

Bruce S. Mallett A. H. Gutterman, Esquire Regional Administrator, Region IV Morgan, Lewis & Bockius LLP U. S. Nuclear Regulatory Commission 611 Ryan Plaza Drive, Suite 400 L. D. Blaylock Arlington, Texas 76011-8064 City Public Service Director David H. Jaffe Office of Nuclear Reactor Regulation U. S. Nuclear Regulatory Commission U. S. Nuclear Regulatory Commission Washington, DC 20555 R. L. Balcom Texas Genco, LP Assistant General Counsel for Materials A. Ramirez Litigation and Enforcement City of Austin U. S. Nuclear Regulatory Commission Washington, DC 20555 C. A. Johnson AEP Texas Central Company U. S. Nuclear Regulatory Commission Jon C.Wood Attention: Document Control Desk Matthews & Branscomb One White Flint North 11555 Rockville Pike Rockville, MD 20852 Richard A. Ratliff Secretary of the Commission by e-mail Bureau of Radiation Control to hearingdocket~nrc.gov Texas Department of Health 1100 West 49th Street Austin, TX 78756-3189 Jeffrey Cruz Assistant General Counsel for U. S. Nuclear Regulatory Commission Materials Litigation and Enforcement P.O. Box 289, Mail Code: MN116 by e-mail to OGCMailCenter nrc.gov.

Wadsworth, TX 77483 C. M. Canady City of Austin Electric Utility Department 721 Barton Springs Road Austin, TX 78704

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