NOC-AE-06002090, Request for Enforcement Discretion for Technical Specification 3.5.2 and 3.6.2.1

Request for Enforcement Discretion for Technical Specification 3.5.2 and 3.6.2.1

ML063420192
Person / Time
Site:	South Texas
Issue date:	12/04/2006
From:	Halpin E South Texas
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
NOC-AE-06002090
Download: ML063420192 (21)

Text

Nuclear Operating Company South Tetas ProjectEk*tinc Generaftin Station PO.Box 289 Wadswortho Texas 77483 ***.

December 4, 2006 NOC-AE-06002090 10CFR50.36 STI: 32095724 U. S. Nuclear Regulatory Commission Attention: Document Control Desk One White Flint North 11555 Rockville Pike Rockville, MD 20852-2738 South Texas Project Unit 2 Docket No. 50-499 Request for Enforcement Discretion for Technical Specification 3.5.2 and 3.6.2.1 In this letter, STP provides a follow-up written request for Enforcement Discretion, which was granted verbally at 1538 hours0.0178 days <br />0.427 hours <br />0.00254 weeks <br />5.85209e-4 months <br /> (Central Time) on December 3, 2006, for South Texas Project Unit 2.

STP requested Enforcement Discretion for Unit 2 from the provisions of Technical Specification (TS) 3.5.2, "ECCS Subsystems - Tvg Greater Than or Equal to 350 deg F," Action a., for the Unit 2 Train A High Head Safety Injection (HHSI) Pump and Low Head Safety Injection (LHSI)

Pump. Additionally, Enforcement Discretion is requested from the provisions of TS 3.6.2.1, "Containment Spray System," for Unit 2 Train A Containment Spray (CS).

Action a. of TS 3.5.2 and the Action of TS 3.6.2.1 were entered at 0100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> on November 27, 2006. STP requested this discretion from the Action requirements to complete repair and testing of the Unit 2 Train A HHSI Pump without requiring a plant shutdown. The Train A LHSI and CS pumps share a common suction header with the HHSI pump, and because this line is out of service to support HHSI maintenance, the LHSI and CS pumps are also inoperable.

The Enforcement Discretion granted will be effective until 0100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> on December 12, 2006.

STP determined the proposed Enforcement Discretion was not risk-significant and did not result in a net increase in the radiological risk to the public. The attachment provides the required information for Enforcement Discretion as described in the Part 9900 Technical Guidance of the NRC Inspection Manual.

The only commitments made in this submittal are listed in Attachment 2.

AoDCA

NOC-AE-06002090 Page 2 If you have any questions regarding this request, please contact Mr. Wayne Harrison at (361) 972-7298 or me at (361) 972-7849.

Edwad D. Halpin Site Vice President and Plant General Manager jrn/

Attachments:

1. Criteria for Enforcement Discretion

2. Commitments

3. HHSI Pump Diagram

NOC-AE-6002090 Page 3 cc:

(paper copy) (electronic copy)

Regional Administrator, Region IV A. H. Gutterman, Esquire U. S. Nuclear Regulatory Commission Morgan, Lewis & Bockius LLP 611 Ryan Plaza Drive, Suite 400 Arlington, Texas 76011-8064 Mohan C. Thadani U. S. Nuclear Regulatory Commission Senior Resident Inspector Steve Winn U. S. Nuclear Regulatory Commission Christine Jacobs P. 0. Box 289, Mail Code: MN116 Eddy Daniels Wadsworth, TX 77483 NRG South Texas LP C. M. Canady J. J. Nesrsta City of Austin R. K. Temple Electric Utility Department E. Alarcon 721 Barton Springs Road City Public Service Austin, TX 78704 Richard A. Ratliff Jon C. Wood Bureau of Radiation Control Cox Smith Matthews Texas Department of State Health Services 1100 West 49th Street C. Kirksey Austin, TX 78756-3189 City of Austin

Attachment I NOC-AE-06002090 Page I of 13 ATTACHMENT 1 Criteria for Enforcement Discretion

Attachment 1 NOC-AE-06002090 Page 2 of 13 Criteria for Enforcement Discretion

1. The Technical Specification (TS) or other license conditions that will be violated:

STP is specifically making a one-time request for discretion for Unit 2 from taking the actions required by ACTION a. of Technical Specification (TS) 3.5.2 and the Action of TS 3.6.2.1.

TS 3.5.2, "ECCS Subsystems - Tayg Greater Than or Equal to 350 deg F," requires in Modes 1 through 3 that three independent trains of the Emergency Core Cooling System (ECCS) be operable. TS 3.6.2.1, "Containment Spray System," requires in Modes 1 through 4 that three independent trains of Containment Spray (CS) be operable.

Action a. of TS 3.5.2 states:

"With less than the above subsystems OPERABLE, but with at least two High Head Safety Injection pumps in an OPERABLE status, two Low Head Safety Injection pumps and associated RHR heat exchangers in an OPERABLE status, and sufficient flow paths to accommodate these OPERABLE Safety Injection pumps and RHR heat exchangers,**

restore the inoperable subsystem(s) to OPERABLE status within 7 days or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in HOT SHUTDOWN within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />."

(The associated ** footnote states: "Verify required pumps, heat exchangers and flow paths OPERABLE every 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.")

The Action of TS 3.6.2.1 states:

"With one Containment Spray System inoperable, restore the inoperable Spray System to OPERABLE status within 7 days or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />; restore the inoperable Spray System to OPERABLE status within the next 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or be in COLD SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />."

STP Unit 2 is currently in MODE 1 at 100% power. The Train A SI pumps and CS pump were declared inoperable at 0100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> on November 27, 2006, in order to perform planned corrective maintenance, which included mechanical seal replacement, on the HHSI pump.

The Train A LHSI and CS pumps share a common suction header with the HHSI pump, and because this line is out of service to support HHSI maintenance, the LHSI and CS pumps are also inoperable. The Train A SI pumps and CS pump must be restored to an operable condition by 0100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> on December 4, 2006, or the unit must be shutdown in accordance with the TS requirements. STPNOC requests discretion from taking the actions required by these Actions until 0100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> on December 12, 2006, by which time the HHSI pump will have been restored to operable status. The additional 8 days requested will provide sufficient time to complete repairs and testing necessary to return the HHSI pump to operable status, without requiring a unit shutdown.

Attachment 1 NOC-AE-06002090 Page 3 of 13

2. The circumstances surrounding the situation: including likely causes; the need for prompt action; action taken in an attempt to avoid the need for an NOED; and identification of any relevant historical events.

On November 27, 2006 at 0100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br />, the Unit 2 Train A Emergency Core Cooling System (ECCS) was declared inoperable to perform planned maintenance activities. A planned activity to replace the mechanical seal and o-rings for the Train A High Head Safety Injection (HHSI) pump started as scheduled on November 28, 2006. This same activity had been performed successfully for this type of pump at STP on four previous occasions. The work week maintenance schedule planned for Train A ECCS to be returned to operable status at 0700 on November 30, 2006.

During the disassembly of the coupling, the pump shaft did not drop as expected. As a result, the spacer was very difficult to remove and required use of force to obtain the clearance necessary for removal. In addition, oxidation had formed a bond between the pump shaft and the pump half coupling. This resulted in this designed slip-fit becoming an interference fit. The pump side half-coupling (slip-fit design) required use of hydraulic tool force to remove the coupling from the pump shaft. The practice used to remove the half coupling is consistent with normal pump maintenance practices.

The mechanical seal package was re-installed and the pump casing was refilled with water to check freedom of rotation of the pump shaft. Attempts were made to check the pump rotating assembly freedom of rotation. These attempts were unsuccessful. As a result, it was decided on December 1, 2006, to replace the rotating element to restore the pump to operability. Rotating element replacement for this type of pump is a first-time evolution for STP. Parts are available to support this work. The rotating element replacement and post-maintenance testing is expected to require an additional 6 days beyond the 7-day AOT that expires at 0100 on December 4, 2006. An 8-day AOT extension is requested to allow for contingencies for this first-time evolution.

The most probable causes of the inability to complete the maintenance of the pump are:

Reduced uncoupled vertical travel of the shaft and the oxidation binding of the half-coupling to the pump shaft. This reduced free travel complicates the removal of the spacer. The oxidation binding of the half coupling resulted in the work activities requiring additional force to accomplish the half coupling removal.

Internal obstruction resulting from the application of an upward force to remove the half-coupling. Removal of the half-coupling was accomplished by the application of a hydraulic jack on the pump flange and the half-coupling. The applied force caused the shaft to move upwards prior to the removal of the coupling.

This upward shaft movement may have caused the stage-I impeller to contact the

Attachment 1 NOC-AE-06002090 Page 4 of 13 lower edge of the suction bell bearing, forcing the bearing to move up. The final position of the suction bell bearing would be higher than design resulting in an obstruction with bottom edge of the impeller reducing free vertical shaft movement.

Internal obstructions resulting from repeated vertical movement of the pump shaft without lubrication to the upper impeller bearings can cause galling in the stainless steel bearings. During attempts to measure the pump shaft float, the shaft was raised and lowered without water covering the upper most shaft bearing.

Without water as a lubricant, the stainless steel bearing material may become galled resulting in an obstruction to vertical and rotational movement.

The reduced uncoupled vertical travel of the shaft and the oxidation binding of the half coupling does not impact the ability of the pumps to perform their design function.

STP has reviewed work history on both Units I and 2 for mechanical seal replacements on high head safety injection (HHSI) pumps. STP has previously replaced the mechanical seals on HHSI pumps without any adverse conditions. One HHSI pump in Unit I is still running the mechanical seal that was in place at startup. This replacement of the 2A HHSI pump mechanical seal was the first seal replacement for this pump since initial plant startup.

STP has also reviewed the work history for Units 1 and 2 for mechanical seal replacements for low head safety injection (LHSI) and containment spray (CS) pumps. In only one instance, (Unit 2) the pump half coupling was found stuck on one LHSI pump. This issue was resolved by motor removal and half coupling removal with a puller. The remainder of the data indicates uneventful mechanical seal replacements.

STP has reviewed In-service Testing (IST) performance and vibration data, motor and pump predictive maintenance vibration data and motor current trends gathered during outages for the past 3 years, as well as current open work requests associated with HHSI, LHSI and CS pumps for any adverse trends that might have been indicative of the current condition found on 2A HHSI pump. No adverse trends have been identified.

STP has identified the most recent surveillance dates for HHSI as follows:

Pump Date Pum Date IA HHSI 11/22/06 2A HHSI 09/08/06 11B HHSI 09/04/06 2B HHSI 10/12/06 1C HHSI 11/10/06 2C HHSI 11/17/06 In conclusion, the condition in the 2A HHSI pump (i.e. tight tolerances and oxidized half coupling to the shaft) did not impact pump performance prior to maintenance but was exacerbated by maintenance activities involved with the work performed to replace the pump's mechanical seal. The mechanical seal replacement had been successfully performed on four previous occasions. Similar work instructions for those replacements were used to

Attachment 1 NOC-AE-06002090 Page 5 of 13 replace the mechanical seal on the Train A HHSI pump.

Therefore, the condition in HHSI 2A and review of operating and maintenance history of HHSI, LHSI AND CS pumps does not identify any concern to the pumps ability to perform their design function.

Additionally, the Unit 2 Train B and C HHSI pumps were satisfactorily tested on December 2, 2006, to confirm operability.

The pump work had been planned to be completed for the Unit 2 Train A ECCS to be returned to operability status well before the expiration of the TS AOT. Once the condition with the rotating assembly was identified, maintenance and engineering resources were mobilized on an around-the-clock basis to identify the causes of the condition, identify pump repair alternatives, and schedule impacts. It was determined that the unanticipated repairs could not be completed within the time remaining in the AOT, and there was insufficient time remaining in the AOT (i.e., less than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />) to prepare and submit an emergency license amendment request. Therefore, the need for an Enforcement Discretion request could not be avoided.

Since the shaft obstruction is known to be inside the rotating element assembly, replacement of the rotating element assembly will resolve the condition that led to the inability to complete the pump maintenance. In addition, the issues of oxidation and reduced vertical travel of the pump discussed above will be resolved as well by the installation of the new rotating element assembly. Given the currently permitted 7-day AOT, a plant shutdown would be required to restore the Train A HHSI pump to operability. Therefore, STPNOC is requesting Enforcement Discretion in order to perform the Train A HHSI pump rotating element replacement without requiring a plant shutdown.

3. Information to show that the cause and proposed path to resolve the situation are understood by the licensee, such that there is a high likelihood that planned actions to resolve the situation can be completed within the proposed NOED timeframe.

The probable causes of the Train A HHSI pump condition are discussed in Section 2 above.

As discussed above, replacement of the rotating element assembly will resolve the condition. Current estimates show that the proposed corrective maintenance and testing can be completed within the requested Enforcement Discretion period. The scope of work is understood, spare parts are available (including a complete rotating element assembly), and the maintenance and testing activities will be performed on an around-the-clock basis until the pump is restored to operable status. The 8-day Enforcement Discretion period is requested in order to complete the pump rotating element replacement, and testing to restore the pump to an operable condition.

Attachment I NOC-AE-06002090 Page 6 of 13 If unanticipated problems arise which cannot be corrected within the Enforcement Discretion period, or if delays occur which prevent completion of the desired corrective maintenance within the additional time permitted, then STP will enter into the required shutdown actions of TS 3.5.2 and 3.6.2.1, unless further regulatory relief is obtained.

Attachment 3 provides a diagram of the HHSI pump for reference.

4. The safety basis for the request, including an evaluation of the safety significance and potential consequences of the proposed course of action.

System Description

The Emergency Core Cooling System (ECCS) is designed to cool the reactor core and provide shutdown capability subsequent to the following accident conditions:

1. Pipe breaks in the Reactor Coolant System (RCS) which cause a discharge larger than that which can be made up by the normal makeup system, up to and including the instantaneous circumferential rupture of the largest pipe in the RCS.

2. Rupture of a control rod drive mechanism (CDRM) causing a rod cluster control assembly (RCCA) ejection accident.

3. Pipe breaks in the steam system, up to and including the instantaneous circumferential rupture of the largest pipe in the steam system.

4. A steam generator tube rupture.

The primary function of the ECCS is to remove the stored and fission product decay heat from the reactor core and to provide shutdown capability during accident conditions.

The ECCS consists of the high head safety injection (HHSI) and low head safety injection (LHSI) pumps, Safety Injection System (SIS) accumulators, residual heat removal (RHR) heat exchangers (HXs), the refueling water storage tank (RWST) along with the associated piping, valves, instrumentation, and other related equipment.

The ECCS components are designed such that a minimum of two accumulators delivering to two unaffected loops, and one HHSI and one LHSI pump delivering to an unaffected loop, will assure adequate core cooling in the event of a design basis LOCA. The redundant onsite standby Diesel Generators (DG) assure adequate emergency power to all electrically-operated components in the event a loss-of-offsite power (LOOP) occurs simultaneously with a LOCA, even assuming a single failure in the emergency power system such as the failure of one DG to start.

Attachment I NOC-AE-06002090 Page 7 of 13 In the event of an accident, the three HHSI pumps are started automatically on receipt of an SI signal and a load sequencer start permissive. These pumps deliver water to the RCS from the RWST during the injection phase and from the containment sump during the re-circulation phase. Each HHSI pump is a multi-stage, vertical, motor-driven centrifugal pump.

The OPERABILITY of three independent ECCS subsystems ensures that sufficient emergency core cooling capability will be available in the event of a Loss of Coolant Accident (LOCA) assuming the loss of one subsystem through any single failure consideration. Each subsystem operating in conjunction with the accumulators is capable of supplying sufficient core cooling to limit the peak cladding temperatures within acceptable limits for all postulated break sizes ranging from the double ended break of the largest RCS cold leg pipe downward. One ECCS is assumed to discharge completely through the postulated break in the RCS loop. Thus, three trains are required to satisfy the single failure criterion.

Risk Evaluation An assessment of the change in the South Texas Project Unit 2 core damage frequency (CDF) due to allowing continued operation while repairing the Train A High Head Safety Injection (HHSI) beyond the Technical Specification AOT (Allowed Outage Time) of 7 days was performed for an additional period of 8 days. This assessment was performed with the South Texas Project Probabilistic Risk Assessment (PRA) model STPREV5. The PRA model is an at-power model including both internal and external events that has been peer reviewed to capability category 2 per Regulatory Guide 1.200 and all facts and observations have been closed. Due to the nature of the repair required, the High Head Safety Injection, Low Head Safety Injection, and Containment Spray common header is out of service which is represented by Safety Injection Common Train A in the STP PRA.

Assumptions:

" No other maintenance that would render a system non-functional other than Safety Injection Common Train A will be performed during the 8-day extended allowed outage time.

" All other assumptions of the STP PRA STPREVS remain valid.

The dominant contributors to CDF associated with Safety Injection common header 2A changed with regard to some fire initiating events. The dominant Initiating Events affected by this configuration are listed below in order with the associated mitigating effect of the STP compensatory actions.

Fire Scenarios for Cable Spreading Room Train B (Z047X, Z47BC, and Z047B) -

which disables Train B and Train C AC and DC power and associated equipment including the PDP: This initiator is mitigated by STPNOC's compensatory action to ensure availability of one fire water storage tank and two diesel fire pumps. Additionally, periodic walkdown of the B Train cable spreading room (Unit 2 EAB 60' elevation

Attachment I NOC-AE-06002090 Page 8 of 13 room 302) will be conducted to ensure no hot work is being performed. This initiator is additionally reduced by disallowing planned maintenance on the remaining operable trains, heightened station awareness for the exposure, and briefing operating crews of the exposure caused by this maintenance configuration (Attachment 2 all Items).

High winds (HWIND) (Tornado) which disables the switchyard, BOP&TSC diesels, and ECW Cooling water pond due to debris in traveling screens: The frequency of tornadoes and other high winds is significantly reduced during this time of year.

Loss of ALL off site power 345 and 138 kv (LOSPX): This initiator is expected to be slightly reduced by STPNOC's compensatory action to lock the switchyard to reduce the exposure of a self-induced loss of offsite power event, along with verifying with the TDSP that there is no grid instability issues at the time of entry into the 8-day extension.

Loss of 345KV off site power (LOSP): Same as above.

Loss of all 3 EAB HVAC trains (LOEAB3): Assuring the availability of the PDP, TSC DG, and TDAFW (Attachment 2 Items 9, 10, 11, 12, & 15) reduce the risk from this initiator since LOEAB3 initiator can cause loss of safety-related switchgear (intemal "blackout" scenario).

Steam Generator Tube Rupture (SGTR): The compensatory actions to assure that all remaining equipment is operable (Attachment 2 Items 2, 3, 6, 15) mitigate this initiating event.

The remaining contributors to CDF will have less effect on the cumulative risk and are not considered dominant.

STPNOC has implemented other compensatory actions that provide the following unquantifiable benefits that are not associated with a specific initiator:

Confirmation of operability of the Train B and Train C HHSI pumps (Attachment 2 Item 1) reduced the exposure interval for potential failure.

Erection of protected train signs on Train B and Train C ESF equipment (Attachment 2 Item 4) reduces the potential for human error associated with the remaining operable trains.

Restriction on the performance of maintenance on equipment that could affect the ICCDP (Attachment 2 Item 6) enhances the ability of the plant to respond to all initiators, dominant and otherwise.

Briefing on-shift Operations crews that Train A ECCS and CS is unavailable (Attachment 2 Item 16) will reduce the chance of operator error in executing EOP actions in the unlikely event of an accident.

Part 9900 NOED Technical Guidance Evaluation Because the Train A HHSI condition is limited in time, the delta CDF and the delta Large Early Release Frequency (LERF) is multiplied by the expected 8-day extension to obtain conditional probabilities. The conditional probabilities are treated as Incremental Conditional Core Damage Probability (ICCDP) and Incremental Conditional Large Early

Attachment I NOC-AE-06002090 Page 9 of 13 Release Probability (ICLERP) for the evaluation against the Part 9900 NOED Technical Guidance criteria. The PRA evaluation for extending the AOT an additional 8 days was performed assuming "zero maintenance" for that time using a STP zero maintenance model, MASREV5. The table below is the base case zero maintenance CDF and LERF, along with the CDF and LERF associated with safety injection common train out of service.

MAS REV5 CDF/yr LERF/yr Train A Base Case 7.60E-06 4.50E-07 Train A with Safety Injection Common Train A 2.79E-05 4.53E-07 ACDF/yr ALERF/yr 2.03E-05 3.45E-09 The table below depicts the acceptance criteria of Part 9900 NOED Technical Guidance and the results calculated for the proposed 8-day extension.

Days I START TIMEI END TIME I Hours I ICCDP ICLERP I 8 12/4/2006 1:00 12/12/2006 1:00 192.00 4.44E-07 7.57E-11 Part 9900 NOED Guidance Criteria ICCDP<5.OE-07. ICLERP<5.0E-08 PRA Evaluation Conclusions for NOED:

The calculated values for ICCDP and ICLERP demonstrate that the proposed one-time Train A Safety Injection common AOT extension has a very small quantitative impact on plant risk. The ICCDP is less than the 5.OE-07 guidance in the Part 9900 NRC Inspection Manual Technical Guidance. Additionally, the compensatory measures listed in Attachment 2 should reduce the risk associated with the additional AOT period. The objectives of these compensatory measures are to reduce the likelihood of unavailability of trains redundant to the equipment that is out-of-service during the period of the Enforcement Discretion. The ICLERP is less than the Part 9900 5.OE-08 guidance. Station risk levels remain low (near baseline values) and manageable using normal work controls with sufficient margin to allow remedial and corrective actions to be implemented in the event unplanned equipment outages occur. Therefore, it is concluded that, based on the very small quantitative plant risk impact and the compensatory measures and risk management actions described below, the risk associated with the Train A High Head Safety Injection outage does not impose a significant risk to public health and safety.

This very small change in risk must be balanced against the risk associated with the alternative of shutting down the plant for repair. While not quantifiable at the South Texas Project (the South Texas Project does not have a quantitative transition and shutdown model), there are risks associated with manually shutting the plant down from a stable condition. They include challenging systems that are currently in standby. Therefore, the relative safety significance of the proposed Enforcement Discretion is low and the potential consequences of the proposed request are preferable to the potential consequences

Attachment I NOC-AE-06002090 Page 10 of 13 associated with plant shutdown.

Loss of electrical power is an important risk consideration at the South Texas Project and grid reliability is a factor in assessing its contribution to risk. STPNOC has contacted the Transmission and Distribution Service Provider (TDSP) and confirmed the stability of the power grid and that there are no unusual factors that need to be considered in this evaluation.

During the period of the Enforcement Discretion, the calculated risk does not exceed the level determined acceptable during normal work controls. The proposed action conforms to the requirements of the STP Configuration Risk Management Program (CRMP). South Texas will continue to use the CRMP to evaluate and monitor the risk significance associated with extending the Train A HHSI pump outage. The CRMP requires the compensatory measures listed below to be implemented if the Non-Risk Significant Threshold of 1.OE-06 is exceeded.

• 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 sensitivity activities from the planned work scope

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

• Ensure any measures taken to reduce risk are recorded in the Control Room Logbook.

• Evaluate whether heightened station awareness is acceptable while attempting to return components or systems to functional status. Duty Plant Manager approval is required to solely implement heightened station awareness.

The above compensatory measures in addition to those listed in Attachment 2 have already been implemented prior to entry into the Enforcement Discretion period, to address the current condition with the Train A HHSI pump. In accordance with the CRMP process and governing station procedures, if an emergent issue develops that could affect the calculated risk, then the risk will be recalculated and appropriate risk management actions will be taken.

The STP CRMP satisfies the Maintenance Rule requirements as specified in 10 CFR 50.65(a)(4).

There are no significant safety concerns resulting from the proposed Enforcement Discretion. The extent of the condition that caused the Train A HHSI pump to remain inoperable beyond the planned maintenance period is discussed above in Section 2. No common cause factors have been identified that would potentially increase the failure probabilities of the remaining ECCS equipment. Trains B and C of Safety Injection and Containment Spray remain operable.

Attachment I NOC-AE-06002090 Page 11 of 13 Based on the above evaluation and the planned compensatory measures, STPNOC concludes that the proposed Enforcement Discretion does not cause risk to exceed the level determined acceptable during normal work controls and, therefore, there is no net increase in radiological risk to the public.

5. The justification for the duration of the noncompliance.

The expected duration of the noncompliance, using the available rotating element assembly, is 6 days. Because this is a first-time evolution, an additional 2 days is requested to allow for any unanticipated schedule delays or unforeseen challenges which may develop during pump reassembly efforts (e.g., bolting or assembly problems, clearance issues, resolution of testing issues, etc.).. Therefore, an 8-day Enforcement Discretion period is requested in order to complete pump rotating element replacement and testing activities necessary to return the Train A HHSI pump to an operable condition.

6. The condition and operational status of the plant.

Unit 2 is in Mode I at 100% power. There are no other Limiting Condition for Operation Action statements in effect. Trains B and C of Safety Injection and Containment Spray remain operable. All Standby Diesel Generators are operable.

7. The status and potential challenges to off-site and on-site power sources.

All onsite and offsite power sources are currently available. The TDSP has confirmed there are no known challenges to the offsite power sources. The Technical Specification required components of the onsite power distribution system are operable and capable of performing their design function.

8. The basis for the licensee's conclusion that the noncompliance will not be of potential detriment to the public health and safety.

a. The proposed Enforcement Discretion does not involve a significant increase in the probability or consequences of a previously evaluated accident. As discussed in Section 4 above, there are no significant safety concerns resulting from the proposed Enforcement Discretion. Trains B and C of Safety Injection and Containment Spray remain operable. Safety Injection and Containment Spray are not initiators of any accident previously evaluated. Probabilistic Risk Assessment has determined that the incremental core damage and large early release probabilities are not risk significant.

Attachment I NOC-AE-06002090 Page 12 of 13

b. The proposed Enforcement Discretion does not create the possibility of a new or different accident from any previously evaluated. No new accident precursors have been created due to the inoperability of Train A SI or CS. The requested extended period of operation with an inoperable SI and CS train do not introduce any new modes of operation or new accident precursors, and do not involve any physical modifications to the plant. Trains B and C of SI and CS remain operable.

c. The proposed Enforcement Discretion does not involve a significant reduction in the margin of safety. Trains B and C of SI and CS remain operable and are capable of performing their design function.

Based on the above, the proposed changes will not be of potential detriment to the public health and safety and no significant hazards consideration is involved.

9. The basis for the conclusion that the noncompliance will not involve adverse consequences to the environment.

STP has reviewed the proposed Enforcement Discretion request and the Nuclear Regulatory Commission Final Environmental Assessment for the South Texas Project Units 1 and 2 and has concluded that pursuant to 10 CFR 51, there are no significant radiological or non-radiological impacts associated with the proposed Enforcement Discretion request.

This proposed Enforcement Discretion request has been evaluated against the criteria for and identification of licensing and regulatory actions requiring environmental assessment in accordance with 10 CFR 51.21. It has been determined that the proposed changes meet the criteria for categorical exclusion as provided for under 10 CFR 51.22(c)(9). The following is a discussion of how the proposed Enforcement Discretion request meets the criteria for categorical exclusion.

(i) The proposed change involves no Significant Hazards Consideration (refer to Section 8 above),

(ii) there is no significant change in the types or significant increase in the amounts of any effluent that may be released offsite since the proposed changes do not affect the generation of any radioactive effluent nor do they affect any of the permitted release paths, and (iii) there is no significant increase in individual or cumulative occupational radiation exposure.

Accordingly, the proposed change meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Based on the aforementioned and pursuant to 10 CFR 51.22(b), no environmental assessment or environmental impact statement need be prepared.

Attachment I NOC-AE-06002090 Page 13 of 13

10. A statement that the request has been approved by the facility organization that normally reviews safety issues (Plant On-site Review Committee, or its equivalent).

The Plant Operations Review Committee approved this request on December 2, 2006.

11. The request must specifically address which of the NOED criteria for appropriate plant conditions specified in Section B is satisfied and how it is satisfied.

The NOED criteria for an operating plant are applicable in this situation. The criteria and associated justification are as follows:

a. Avoid unnecessarytransientsas a result of compliance with the license condition and, thus, minimize potentialsafety consequences and operationalrisks.

Requiring the plant to shutdown and put the systems through the resulting transient and thermal cycle is not commensurate with the low safety significance of this condition. As discussed above, the minimal risk associated with the maintenance on the Train A HHSI pump is offset by the compensatory measures described in this request.

12. Written NOED request and follow-up license amendment request.

Verbal approval of Enforcement Discretion was granted on December 3, 2006, at 1538 hours0.0178 days <br />0.427 hours <br />0.00254 weeks <br />5.85209e-4 months <br /> (Central Time). As discussed with the NRC staff, a follow-up amendment request is not needed, since the Train A HHSI pump will be returned to an operable condition before the amendment request would be approved. Additionally, a broad-scope Risk Managed Technical Specification amendment application is currently under review by the NRC staff that once approved should preclude the need for Enforcement Discretion in a future similar circumstance.

13. For NOED requests involving severe weather or other natural events.

The requested Enforcement Discretion does not involve severe weather or other natural events.

Attachment 2 NOC-AE-06002090 Page 1 of3 ATTACHMENT 2 Commitments

Attachment 2 NOC-AE-06002090 Page 2 of 3 As part of this Enforcement Discretion request, STPNOC makes the following commitments:

The following compensatory actions will be in effect until the Unit 2 Train A HHSI pump is restored to OPERABLE status:

1. Prior to entry into the Enforcement Discretion period, STPNOC will confirm operability of the Train B and C High Head Safety Injection trains by performance of the quarterly pump run surveillances. (Complete)

2. No planned maintenance will be performed on the Unit 2 Train B or C Engineered Safety Features trains. *

3. No planned maintenance will be performed on the Unit 2 Centrifugal Charging Pumps. *

4. Protected train signs will be placed for the Train B and C ESF equipment.

5. The switchyard will be locked, and STPNOC will ensure that no maintenance activities are performed 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. *

6. STPNOC will not perform any planned voluntary maintenance in Unit 2 during the Enforcement Discretion period that would increase the ICCDP. *

7. STPNOC will not perform any planned maintenance that could result in an inoperable open containment penetration. *

8. STPNOC will purge containment only for pressure control and only for short duration. *

9. STPNOC will not perform any planned maintenance on the Unit 2 Technical Support Center Diesel Generator. *

10. STPNOC will not perform any planned maintenance on Load Center 2W. *

11. STPNOC will not perform any planned maintenance on Motor Control Center 2G8. *

12. STPNOC will not perform any planned maintenance on the Positive Displacement Charging Pump. *

13. STPNOC will ensure that no planned maintenance is performed on the Emergency Transformer or the 138KV Blessing to STP and Lane City to Bay City lines. *

14. For the duration of the Enforcement Discretion, no planned maintenance will be performed on any of the Standby Diesel Generators. *

15. STPNOC will not perform any planned maintenance on the auxiliary feedwater system or steam generator PORVs. *

16. The Unit 2 on-shift Operations crews will brief on the Emergency Operating Procedures assuming one train of Safety Injection and Containment Spray is unavailable.

17. During the Enforcement Discretion period, the Unit 2 on-shift crews will evaluate compensatory actions and establish any additional actions as deemed necessary to effectively manage risk during this timeframe.

18. STPNOC will not perform any planned maintenance on Switchgear 2L or 2K. *

19. STPNOC will consider approval of all unscheduled emergent work in accordance with the STP work process program.

Attachment 2 NOC-AE-06002090 Page 3 of 3

20. STPNOC will not perform planned maintenance that will result in less than one Fire Water Storage Tank or less than two Diesel Fire Pumps being functional. *

21. STPNOC will ensure periodic walkdowns are performed in the B Train cable spreading room (Unit 2 EAB 60' elevation room 302). In addition, no hot work will be allowed in this room.

• Explicitly modeled in the STP PRA.

It should be noted that STPNOC will continue to perform surveillance testing that does not increase the ICCDP.

In the teleconference in which the NRC staff granted Enforcement Discretion, STPNOC made the following additional commitments:

" STPNOC will notify the NRC Resident Inspector of any changes that affect the basis for approval of the Enforcement Discretion request.

• STPNOC will notify the NRC Resident Inspector of any changes to plant configuration that affects the calculated risk basis described in this request.

Attachment 3 NOC-AE-06002090 Page 1 of2 ATTACHMENT 3 HHSI Pump Diagram

Attachment 3 NOC-AE-06002090 Page 2 of 2 High Head Safety Injection Pump Shaft and Coupling HALF-COUPLING (905)

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