ML051790240

Facility and Commitment Change Reports for May 1, 2003 Through June 15, 2005

ML051790240
Person / Time
Site:	San Onofre
Issue date:	06/24/2005
From:	Scherer A Southern California Edison Co
To:	Document Control Desk, Office of Nuclear Material Safety and Safeguards
References
Download: ML051790240 (24)

Text

F SOUITIERN CALIFORNIA A. Edward Scherer IfE D IS Manager or EDISON' Nuclear Regulatory Affairs IX An ElDISONV ':RN.vt7710V.A I Compan)

June 24, 2005 U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D.C. 20555

Subject:

Docket Nos. 50-361, 50-362, and 72-41 Facility and Commitment Change Reports San Onofre Nuclear Generating Station Units 2 and 3

Dear Sir or Madam:

This letter transmits the Facility Change Reports required by 10 CFR 50.59(d)(2) and 10 CFR 72.48(d)(2) for San Onofre Units 2 and 3 for the period from May 1, 2003 through June 15, 2005. The reports (Enclosures 1 and 2) provide a summary of the facility changes and procedure changes, including a summary of the safety evaluations performed for each change. There were no tests or experiments during this period.

The scope of these reports is based on a review of plant records and all 50.59 and 72.48 evaluations identified for the time period above. Complete facility change documentation is available onsite.

Enclosure 3 provides a report on commitment changes made per NEI 'Guidelines for Managing NRC Commitment Changes," NEI-99-04, Revision 0, for the period from July 1, 2003 through June 15, 2005.

If you would like any additional information, please contact Mr. J. L. Rainsberry at (949) 368-7420.

Sincerely, Enclosures cc: B. S. Mallett, Regional Administrator, NRC Region IV B. M. Pham, NRC Project Manager, San Onofre Units 2, and 3 C. C. Osterholtz, NRC Senior Resident Inspector, San Onofre Units 2 & 3 J. C. Shepherd, NPC Project Manager, San Onofre Unit 1 M. J. Ross-Lee, NRC Project Manager, Spent Fuel Project Office P.O. Box 128 San Clemente, CA 92672 949-368-7501 Fax 949-368-7575

ENCLOSURES 1 AND 2 SAN ONOFRE NUCLEAR GENERATING STATION UNIT 2 AND 3 FACILITY CHANGE REPORT (FCR)

FOR THE PERIOD FROM MAY 1, 2003 THROUGH JUNE 15, 2005

ENCLOSURE I 10 CFR 50.59 EVALUATION SUMMARIES

AR 010301066-72, Engineering Change Package (ECP) Pressurizer Heater Half Nozzle Repair (Supercedes 01 0301066-58, 51, and 37)

==

Description:==

ECP 01 0301066-33 provides a half-nozzle repair method for cracked pressurizer heater sleeves to prevent future leakage of primary coolant. The repair removes the installed heater, modifies the heater sleeve, and installs an in kind replacement heater. The modified assembly heater sleeve combines a new Alloy 690 partial sleeve with the existing Alloy 600 sleeve. After the modification has been installed, the J-groove weld between the Alloy 690 heater sleeve and the external weld pad on the pressurizer lower head, and the fillet weld between the Alloy 690 heater sleeve and the heater form the reactor coolant system (RCS) pressure boundary. The original J-groove welds internal to the pressurizer and the area of base metal near the weld that may contain flaws remain in place but are no longer considered to be RCS pressure boundary components.

Evaluation SummarV:

Prior NRC approval in accordance with 10 CFR 50.55a (a)(3)(i) is required for certain*

aspects of the change. Southern California Edison submitted Relief Request ISI-3-11, Revision 1, and Relief Request ISI-3-12 to cover these areas. Relief Request ISI-3-1 1, Revision 1, requested the use of the ambient tempered bead welding technique. Relief Request ISI-3-12 requested that flaws be allowed to remain in place without full characterization and without performing successful examinations.

The replacement creates a gap between the new Alloy 690 sleeve segment and the remaining inner segment of the Alloy 600 sleeve. The gap's creation is considered adverse as it exposes a small area of pressurizer base metal to borated water leading to an increase in the potential for a small break LOCA from the Pressurizer. The gap prevents stresses from occurring from contact between the remnant and the partial sleeves due to thermal expansion. An evaluation of the Boric Acid Corrosion potential was performed to examine the consequences of allowing the potential corrosion. The evaluation concluded that the corrosion rate was of such low magnitude that the increase in the frequency of a small break LOCA met the "less than minimal" aspects of 50.59. The conclusion's basis stems from the fact that the exposed metal area is in a low oxygen environment and that no flow will occur through the gap. Other aspects of the change were examined and were found to be within design criteria. Hence, the structural integrity of the pressurizer is not a concern for the remaining 40-year design life of the vessel.

This change meets applicable NRC requirements as well as the design, material, and construction standards applicable to repair/replacement of a heater sleeve. Therefore, it is concluded that prior NRC review of this modification, beyond that obtained via relief requests ISI 3-11 revision 1 and ISI 3-12, is not required.

AR 011200386-13: Relocation of cabling for the Unit 2 and 3 Perimeter Paqinq System (PPS)

==

Description:==

The Paging Speakers located on the Unit 1 reservoir area bluff are part of Units 2/3 Perimeter Paging System (PPS). The signal for these speakers originated from cabinet 2/31210 via approximately 266' aerial cable, from Unit 1 (PBAZ25) to the reservoir area (PBAZ23). The aerial cable was removed to allow installation of a super crane for large component removal in Unit 1. The aerial cable was replaced with new cable re-routed on the ground through existing and/or new conduits. The seismic category was changed from SC I to SC II; Emergency Preparedness (EP) criteria does not have Safe Shutdown Earthquake functional requirements.

Evaluation Summary:

The cabling for the Units 2 and 3 Perimeter Paging System (PPS) was relocated to route through existing and/or new conduit. The system routing is external to the Units 2/3 power block such that possible failures of the system cannot impact systems that store or process radioactive materials. The routing contains no seismic 11over I hazards to lighting or power systems having quality-affecting attributes that could initiate an accident. There is no EP functional requirement for notification components to function after an SSE. The change to the seismic category for this cable routing has no impact on consequences of an accident or the emergency plan. A review under 10 CFR 50.54(q) for changes to the Emergency Plan is not required as there is no change to the plan. This change does not involve a change to the Emergency Plan nor does it increase accident consequences.

This activity was determined to not require prior NRC approval.

AR 020901502-21: Replacement of an Analog Radiation Monitor Sample Flow Switch with a Dicital Device

==

Description:==

Engineering Change Packages (ESP's) 020901502-3 (Unit 2) and 020901502-4 (Unit 3) replaced the analog radiation monitor sample flow switch 2(3) RE7817 with a digital device that uses a Coriolis design principle, a non-invasive method of flow measurement. The switch monitors the Blowdown Processing System (BPS) neutralization sump discharge to outfall flow. The existing analog switch has exhibited repeated failures due to the combination of equipment location (temperature effects) and detector design (invasive method of measurement). All of the output functions and features of the new flow switch remain unchanged from the old flow switch. A relay contact feature of the present flow switch is being retained as the alarm-generating device. Therefore, the alarm function remains unchanged. The communication of the flow signal with the existing digital radiation monitor remains a contact. The flow switch quality and seismic class remains the same.

Evaluation Summary:

The evaluation examines replacement of the analog sample flow switch for the BPS neutralization sump discharge to outfall radiation monitor 2(3) RE7817 with a digital sample flow switch. All input and output devices continue to provide the same types of signals.

The switch replacement may be implemented without prior NRC approval. The bases for this conclusion are:

1) The structures systems and components remain unchanged regarding interaction with the limiting design bases accident (steam generator tube rupture),

2) The limiting design bases accident remains unchanged,

3) No quality class or seismic changes have been made,

4) There are no changes to the radiological consequences associated with the change, and

5) There are no adverse consequences associated with a change from analog to digital equipment.

AR 021100392-29: Procedure Changes to Improve Chiller Reliability

==

Description:==

This change will increase the chiller's reliability by making them less susceptible to "low refrigerant temperature" trips. Procedures were revised to set the electrical demand signal from 100% to 80%. However, this change will require Operations to reset the switch to 100% if any room temperature reaches a high temperature alarm setpoint during post accident conditions. This action will not be required within the first 30 minutes following the accident initiation.

Evaluation Summary:

An investigation into the cause of "low refrigerant temperature" trip on the emergency chillers identified a methodology to help minimize its occurrence. To implement the change, the chiller control circuit was modified (addition of time delay) to limit the guide vane opening during the initial startup of the emergency chiller. As an interim measure, prior to the chiller circuit modification, a manual version of the modification was implemented via Operations and Maintenance procedure changes. This evaluation focused on the interim procedure changes.

The change directs Operations and Maintenance to set the chiller electrical deman'd knob to 80%

from 100% for standby conditions, and reset the electrical demand to 100% if the temperature in any room supplied by the emergency chilled water alarms reaches a high temperature alarm setpoint. Setting the chiller electrical demand knob from 100% to 80% will limit the maximum guide vane opening during a chiller startup and it will also limit the chiller capacity during steady state operation to below its 100% capacity.

Setting the electrical demand knob to a lower setting is an option made available by the design of the machine. The operating instructions for Carrier centrifugal machines permits a machine operator to limit the maximum motor current draw to any percentage of full load from 100% to 40%. Electrical demand rates can be minimized in this manner. The evaluation concluded that this change would not create any situation that exceeds the bounding design criteria for existing chiller systems, structures, and components. Therefore, prior NRC review is not considered necessary.

AR 030201804-37: Quench Tank Alarm Setpoint Change

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Description:==

A Temporary Engineering Change Package (ECP) was issued to revise the high-level alarm set point for the Unit 3 Quench Tank MT01 1 from 82.5% to 90%. The 82.5% level corresponds to approximately 2078 gallons of water in the tank. Changing the high level alarm to 90% reduces the steam volume capacity to approximately 911 Ibms of steam, less than the 1102 Ibms assumed for the loss of condenser vacuum. This change has an adverse effect to the quench tank design function. The Unit 3 Quench Tank is designed to receive and quench steam from a pressurizer safety valve discharge from a loss of load transient event (approximately 800 Ibms) and to receive miscellaneous gas discharges from the head vent and other systems. Reactor Coolant System (RCS) inventory leakage through 3HV0296A/B or 3HV0297A/B and 3HV0299 was slowly filling the quench tank. As the tank filled, Operators drained the tank to maintain level between the low and high alarm set points. The current alarm set point values are 74% and 82.5%. To compensate for the identified valve seat leakage, the Temporary ECP revised the Quench Tank 3MT01 1 high-level alarm set point from 82.5% to 90%. Nominal valve seat leakage is not considered to be critical to Reactor Coolant System inventory. Therefore, these valves are not outside their design basis and are not considered to be inoperable. The draining -

operation requires using 3HV91 01. Frequent use of 3HV91 01 (every 10-12 days) rover an extended period could impair its ability to fully close. In this situation, Maintenance would require a containment entry to repair the valve. Therefore, temporarily changing the upper level setpoint provides Operators with a larger operating band to lengthen the time between draining operations, and thereby reduce cycling of 3HV91 01. Maintenance planned to rework the leaking valves at the next refueling outage.

Evaluation Summary:

The Quench Tank was initially sized by the vendor, Combustion Engineering (CE), to accept a steam discharge of approximately 1300 lbs. of steam from a loss of load transient event. Subsequently, CE reanalyzed the pressurizer level response following a loss of load transient. The new analysis determined the amount of steam dumped to the quench tank to be 911 lbs. This temporary change will reduce the assumed amount of steam to be quenched from 1230 lbs. to 911 Ibms, thus matching the requirements from the loss of load transient. The quench tank does not perform a Chapter 15 described safety related function. The tank is currently sized to receive approximately 1232 Ibms of steam without failing the installed rupture disk. The loss of normal feedwater and the Chemical and Volume Control System (CVCS) malfunction accidents will release more than approximately 1300 Ibms of steam and will cause the rupture disk to fail, releasing the tank contents to the containment building. However, the consequences of that breach have been evaluated and accepted. The quench tank is simply a method to capture small amounts of steam rather than releasing the steam to the containment atmosphere. There is no safety related function for the quench tank or its rupture disk. Therefore, it can be concluded that, regardless of the event, the consequences of a rupture disk breach are bounded and previously evaluated. This activity was determined to not require prior NRC approval.

AR 030400078-99: Transfer of Unit 1 Spent Fuel to Drv Storage

Description:

Unit 1 spent fuel stored in the Unit 3 spent fuel pool was to be transferred to an Independent Spent Fuel Storage Installation (ISFSI). The transfer process contains a drop of 30 feet. This drop exceeds the dry storage cask limitation of 80 inches. This 10 CFR 50.59 evaluates the intended use of existing plant equipment for transfer of Unit 1 spent fuel from the Unit 3 spent fuel pool.

Components of the dry cask storage system (i.e., transfer cask, canister, transfer system, and storage module) are designed to maximize use of existing site features and procedures. The existing structures, systems, and components that will be used during transfer of spent fuel to dry storage include: the fuel building truck bay area, the fuel pool and deck area and associated HVAC and filter systems, fuel handling equipment, radwaste decontamination systems, single failure proof cask handling crane, auxiliary hoists, access roads, security processing facilities, fire protection systems, water, power and gas supplies and hookups. Interfacing procedures include the site NUREG 0612 heavy load program, security program, and fire protection program. Indirect affects are a concern with respect to interactions with structures, systems, and components in the vicinity of the activity for the operating units and for external hazards (weather, seismic, toxic hazards, personnel safety, heavy load drop, etc). Analysis of the single failure proof crane concluded that the dynamic effects from maximum drop would be limited to 9 inches following an uncontrolled lowering of a load.

Evaluation Summary:

Interim dry storage of Unit 1 spent fuel assemblies is limited to spent fuel assemblies that have been removed from the reactor for over 10 years. This requirement provides an inherent safety feature in that the radiological consequences of postulated accidents are conservatively bounded by evaluation of accidents involving release of radioactive materials in the operating plant. The As Low As Reasonably achievable (ALARA) principle was applied to the design to ensure expected occupational dose hazards remain within acceptable limits. The systems used for storage and loading operations satisfy the provisions of the applicable general license in accordance with 10CFR72. The design criteria section of Engineering Change Package (ECP) 020701186-33 evaluated the interface between the transfer system and the existing spent fuel pool, cask handling crane, site infrastructure, and other site conditions and procedures. It concluded that transfer to dry storage using the single failure proof crane in the manner described will not create any situation that exceeds the bounding design criteria for existing plant systems, structures, and components, or for dry storage system components. Therefore, prior NRC review is not considered necessary.

AR 030800183-77: Procedure S023-10-7 Revision to Place Heater Switch for MA361 into "On" Position instead of "Auto" Position as the Normal Operating Condition

Description:

Control switch HS9797 for control of the heater element for MA361 position is being changed from the present position of AUTO to be permanently left in the ON position. This change will ensure that the heater will remain on during system operation and maintain the Units' charcoal beds.

Evaluation Summary:

The heater's purpose is to reduce the relative humidity of the flow to less than 70% prior to entering the charcoal beds. In the AUTO position, the system flow (as sensed by a differential pressure switch) and humidity conditions (as sensed by a humidistat) are required to cause the heaters to energize. In the ON position, the heater will be energized by just system flow. The humidistat will be bypassed.

This change is acceptable because activation of the heater is always required.

Measurements have shown that the relative humidity of the flow entering MA361 is always greater than 70% (actually, greater than 90%). Unit performance necessitates that the process flow into the charcoal beds be maintained at less than 70% relative humidity. To accomplish this, the heaters need to be energized during operation. Failure of the heaters to energize will result in degradation of the charcoal to perform its design function. The charcoal acts to remove iodine in the event of a steam generator tube leak. Process flow alone is an acceptable parameter to control heater operation. Because incoming flow is always greater than 70% RH, the humidistat logic should always be satisfied to energize the heaters. The installed humidistat performs no required function. Placing the control switch in ON will eliminate the possibility that the heater will turn off during operation of the unit due to a failure of the humidistat.

Thus it is concluded that deleting the automatic function of having HS9797 in the AUTO position by placing HS9797 in the ON position meets all the 50.59 criteria for the change to be implemented by the utility. The activity does not introduce more than a minimal increase in the frequency of an accident previously identified nor does it result in more than a minimal increase of a malfunction of an SSC important to safety or their consequences. In fact, this change eliminates the possible failure of the humidistat to impact the function of MA361. Based on this data, prior NRC approval was determined to not be required.

AR 030901054-1: Licensee Controlled Specifications (LCS) Change L02-008 Extends the Allowed Outage Time for One Train of the Toxic Gas Isolation Signal (TGIS) in LCS 3.3.1 01 from 7 to 14 days

==

Description:==

Licensee Controlled Specification (LCS) change L02-008 evaluated extending the Allowed Outage Time (AOT) for one train of the Toxic Gas Isolation Signal (TGIS) in LCS 3.3.1 01 from 7 to 14 days. The evaluation concluded that an increase in the probability of a malfunction is less than 2. Consequently, the AOT extension was found to have an insignificant increase in risk.

Evaluation Summary:

LCS change L02-008 evaluates extending the Allowed Outage Time (AOT) for one train of the Toxic Gas Isolation Signal (TGIS) in LCS 3.3.101 from 7 to 14 days. The increase in the unavailability of TGIS is similar to the increase in the likelihood of occurrence of a malfunction, however, it was determined that this increase was not more than minimal.

Failure of the sensors (either HI or LOW) is described in the Failure Modes and Effects Analysis (FMEA) shown in Updated Final Safety Analysis Report (UFSAR) Table 7.3-24.

Another failure mode described in this FMEA is the loss of one alternating current (AC) load group. The effect of losing an AC load group is "Loss of a Train" of TGIS. This loss has the same effect that would result from operating within the proposed AOT.

The TGIS initiation equipment that is subject to LCS 3.3.101 Condition A is listed in the UFSAR text and FMEA. The FMEA lists the effect of a different malfunction which bounds the effect of removing one train of TGIS instrumentation from service. It is reasonable to conclude that evaluating the effect of failure of one initiation channel of TGIS is on a level consistent with existing UFSAR-described malfunctions. The acceptance criterion of a factor of 2 increase in probability of a malfunction may be applied to 1 channel of TGIS.

Including unavailability in the definition of "malfunction," allows quantification for the likelihood of the UPS malfunction as follows:

UPS Malfunction Likelihood = Unavailability + Unreliability Assuming the overall unreliability of one channel of TGIS instrumentation (failure to operate probability of 1.45E-2) to remain unchanged, the evaluation concluded that the malfunction likelihood increased by 1.57, which is less than the acceptance criterion of 2 and is therefore acceptable. Therefore, this change does not result in an increase of the likelihood of occurrence of a malfunction of a structure, system, or component important to safety previously evaluated in the Unit 2 and 3 UFSAR/Unit 1 Defueled Safety Evaluation Report (DSAR).

There was no increase in the probability of occurrence of a previously evaluated accident, there is no increase in the consequences of a previously evaluated accident or malfunction, there is no new accident or malfunction created by this change, and there was no effect on a design basis limit for a fission product barrier. It is concluded that this activity does not require prior NRC approval.

AR 031001124-5: Controlling the Steam Generator Blowdown Processing System (BPS)

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Description:==

These changes support updating the Updated Final Safety Analysis Report (UFSAR) to reflect the following methods of controlling the steam generator Blowdown Processing System (BPS):

1. The method of diverting blowdown effluent to the outfall (ocean) when conductivity is too high is changed from automatic to manual for normal operation. (Ref.

Procedure S023-9-4.1)

2. A second valve (PV4086) may be used to control flash tank bypass flow to the outfall when the steam generators are "cold" (less than 210 F). (Ref. Procedure S023-9-4)

3. Two methods involving manual control are used to minimize water hammer in the line when the steam generators are "hot," rather than a single "regulating" valve as suggested by the description in the UFSAR. (Ref. Procedure S023-9-4)

The first change reflects the addition of the Full Flow Condensate Polishing Demineralizer (FFCPD) to San Onofre. The second and third changes improve operating flexibility and minimize water hammer in the BPS. A 50.59 evaluation is required due to the change in method of control from automatic to manual.

Evaluation Summary:

Updating the UFSAR to reflect the proposed changes in the method of controlling the BPS may proceed without NRC approval. Each procedure changes involve components downstream of the containment isolation valves, i.e., in the portion of the BPS that is not important to safety (ITS). Impacts on secondary chemistry, if any, are not significant because maintaining water quality does not increase accident frequency or create an accident of a different type, increase the likelihood of a malfunction, or affect the consequence of an accident. The changes involving manual control are improvements and do not adversely affect the reliability of the BPS or any ITS system.

The BPS can automatically divert steam generator blowdown from the condenser to the outfall (ocean) when blowdown conductivity exceeds a predetermined level. Pneumatically operated valves (CV3776A & B) on the discharge paths change position when the final effluent conductivity meter, CJI-3776 (Ref. P&lDs 40148C and 40148D), generates a high conductivity signal. The original plant design concept was to perform all condensate/feedwater demineralization with the BPS, i.e., a FFCPD was not part of the original design. With the addition of the FFCPD to San Onofre, the water treatment approach changed to performing all cleanups in the FFCPD, downstream of the condenser, and bypassing the BPS demineralizer tanks.

AR 031001124-5: Controlling the Steam Generator Blowdown Processing System (BPS)

(continued)

The BPS has capability to bypass the flash tank and discharge directly to the outfall. In the bypass mode, valves FV4055B and 4056B, located near the flash tank, control the blowdown flow rate. Since the blowdown heat exchanger (E007) is also bypassed, the blowdown effluent temperature may be high, resulting in flashing and waterhammer downstream of the flow control valves. Waterhammer is minimized in two ways:

1. The magnitude of blowdown flow rate is administratively limited, and

2. One of the three valves located near the end of the discharge line, in the intake structure, is used to control backpressure in the line.

Each of these valves may be employed to control conditions in the discharge line downstream of the flow control valves. Whether PV4086 or MU623 is being used, the method of controlling backpressure is essentially the same: S023-9-4 states that the valve, or valve controller, is to be "SLOWLY" adjusted as conditions change (1) to keep the flow below the maximum allowed value, and (2) to minimize waterhammer. Based on this evaluation it was determined that prior NRC approval was not required for this proposed activity.

AR 040201335-2: Procedure Change to S023-11-7. "HFMUD (High Flow Makeup Demineralizer) Operation" via Procedure Modification Permit (PMP) #1 to Allow the Method of Removing the Ion-exchange Beds From Service From Automatic to Manual

==

Description:==

PMP (Procedure Modification Permit), S0123-0-A3 #1 to procedure S023-11-7 has been prepared to allow continued operation of the HFMUD water processing trains when the SA (Secondary Anion) conductivity is above 0.15 gS/cm (SO23-11-7, Step 6.3.12 & L&S 7.7).

The PMP establishes new criteria for HFMUD operation while the current Primary Anion resin remains in service. The PMP will replace automatic operation with manual operation of the HFMUD above the 0.12 VtS/cm setpoint (up to the [Updated Final Safety Analysis Report] UFSAR limit of 0.20 pS/cm). Manual operation is required because the system will not produce water with control in Automatic and SA conductivity above the 0.12 uS/cm setpoint. The UFSAR limit of 0.20 VS/cm was provided by the vendor who initially installed the system and represented the best available technology at the time of installation.

Evaluation Summary:

The activity allows changing the method to remove the ion-exchange beds from service from automatic to manual in accordance with PMP #1 to S023-11-7, "HFMUD Operation."

Conductivity levels above the 0.12 pS/cm setpoint does not have a licensing basis impact since the makeup demineralizer system serves no safety function and has no safety design bases (UFSAR Section 9.2.3.1). The conductivity limit of < 0.2 micromhos/cm (UFSAR Section 9.2.3.1.C.1) is still being met periodic operator surveillances.

Furthermore, the statement in UFSAR Section 10.3.5.3, "Chemistry Control Effects on Iodine Partitioning" regarding "...operating practices are directed toward the goal of corrosion protection which...provides...for the suppression of iodine emissions..." is still being satisfied, regardless of whether the function of removing the ion-exchange beds from service is automatic or manual.

Changing the method of removing the ion-exchange beds from service from automatic to manual in accordance with PMP #1 to S023-11-7, "HFMUD Operation," may proceed without NRC approval based on the negative responses to evaluation criteria (i)-(vii).

Additional information regarding chemistry control at San Onofre (documented in Field Support (FS) assignment 040201335-3) indicates that there are no other considerations that need to be evaluated.

AR 040700922-38: Engineerinq Change Package (ECP) 040700922-19, Disable Unit 2 High Hydrogen Gas Temperature Main Generator Trip

==

Description:==

This temporary modification disabled the automatic high hydrogen (H2) temperature main generator trip function, substituting manual operator actions, until the U2 Refueling Outage, expected in January 2006. The temporary change avoids tripping the main generator due to false H2 gas temperature indications.

The hydrogen gas system provides a cooling medium for the main generator. The automatic system provides for a 2-out-of-4 logic circuit that trips the generator at a high temperature setpoint of 830C (181OF). This automatically initiated trip subsequently trips the main turbine and reactor systems at power levels above approximately 55%.

A number of temperature monitoring instruments for the Unit 2 generator experienced erratic behavior, initially in July 2004 and again in October. Investigations found ungrounded thermocouples, terminal corrosion, and poor grounding in the generator junction boxes, where sensor connections are made. These conditions have caused the temperature swing indications. It has been determined that the observed short-term high temperature variations (increasing temperatures up to 460 F and decreasing temperatures up to 102 0F) do not reflect the actual cooling gas temperature based on the time response and pattern of indication changes.

The temporary modification:

• Disables the generator trip function from the high H2 temperature sensors.

• Lowers the temperature setpoint for the high H2 temperature alarm from its current value of 83CC (181OF) to 75OC (167 0F).

• Revises appropriate Operations procedures for alarm response and provides steps for manual action to trip the generator on valid high H2 temperature indication.

Evaluation Summary:

The protective trip is not an initiator of any accident and no new failure modes introduced.

The trip serves to protect the equipment. Chapter 15 of the Updated Final Safety Analysis Report (UFSAR) lists secondary plant initiated trips as moderate frequency accidents.

Substituting manual for automatic actions, combined with the lowering of the high temperature setpoint does not change the accident frequency nor introduce any changes to plant malfunctions. Generator failure has also been examined within Chapter 15. The change does not alter nor increase any consequences of an accident or malfunction of equipment. This modification lowers the risk of a plant trip due to false high hydrogen temperature sensor signals. Hence, the change can be installed without regulatory review.

AR 040701007-26: BatterV Bank 2B009 Annual Testinq

==

Description:==

Temporary Engineering Change Packages (ECPs) 040701007-1 and 040701007-2 provide cables to connect BOOX, a new Class-1 E qualified battery bank, to Bus 2D3 or 2D4. These connections are made at separate times to allow on-line testing of batteries 2B009 or 2B01 0. Technical Specification 3.8.4.8 requires annual performance tests for these batteries when they reach 85% of their 20-year design life. The revised 50.59 regulations consider testing to be a 'maintenance" activity and hence outside 50.59 considerations. However, procedure S0123-XV-44.1 requires an evaluation against the 50.59 criteria as the temporary alteration is credited with maintaining operability of Technical Specification equipment.

During the temporary evolution, manual actions will be used in lieu of control room indication to locally monitor the continuous battery breaker position indication, Direct Current (DC) voltage indication, and the BOOX battery area temperature. Substituting manual actions for control room indications increases the time to determine a failure or an out of tolerance condition and then report that condition(s) to the control room. The time delay required represents, at worst, a minimal increase in the consequences of an accident previously evaluated in the Unit 2 and 3 Updated Final Safety Analysis Report (UFSAR)/Unit 1 Defueled Safety Analysis Report (DSAR).

Evaluation Summary:

Batteries 2B009 and 2B01 0 require testing as they have reached 85% of their 20 year design life. To allow on-line testing, a spare Class-1 E qualified battery bank, BOOX, is used to replace the DC supply from 2B009 or 2B01 0. Battery bank BOOX is installed in the corridor area of the Auxiliary Building 50 ft. elevation. Temporary ECPs 040701007-1 and 040701007-2 provide cables to connect BOOX to Bus 2D3 or 2D4. If either 2B009 or 2B01 0 fail their performance test, the alternate bus feeder remains in place while the battery is replaced. Each test activity is expected to last less than 90 days. Once battery testing (or replacement if needed) has been completed, the 125V DC system will be restored to its original configuration.

Battery BOOX and associated equipment including temporary cables maintains Reg. Guide (RG) 1.75 separation requirements. Bottom trays for "A" train cables above the BOOX battery are wrapped to meet RG 1.75 requirements. The temporary cables routed from BOOX to 2B009 (and 2B010 at a separate time) in Corridor 303C are protected by installing inverted metal trays over the cables and bolted to the floor. Plastic, fire-retardant, water-repellant covers are installed over the battery cells to protect the battery in the event of a sprinkler system actuation or failure. A Fire Protection Evaluation has addressed fire protection and Appendix R issues, reference AR#040701007-25.

AR 040701007-26: Battery Bank 2B009 Annual Testing (continued)

The Temp ECPs provide the following compensatory actions:

• Connection of a new 2000A fuse in the BOOX battery supply to the bus to provide overcurrent protection and electrical coordination.

• Local battery temperature monitoring.

• Local monitoring by a qualified technician provides continuous battery breaker position indication and voltage indication.

The combination of the design features of the Temporary ECPs and the compensatory actions ensure that temporary change represents less than minimal increases in the frequency or consequences of accidents or malfunctions. The change creates no new accidents; does not affect a design basis limit for a fission product barrier, nor result in a departure from a method of evaluation described in the UFSAR. Thus the change may be initiated without regulatory approval.

AR 041100534-39: Acceptance of an As-Found Condition of Check Valves S2/32426MU169, MU170, & MU171

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Description:==

Maintenance Engineering inspected the U2 and U3 FHB sumps after an overflow of the Main and Spent Fuel cask pools. The inspection determined that the check valve internals had been removed from valves S2/32426MU169, MU170, & MU171. This condition is contrary to the published information as no documentation was found indicating removal of the internals or bonnets. These check valves are located in the drain lines to the Fuel Handling Building Sump and are classified as Quality Class Ill, Seismic Category 2.

Design Engineering created Engineering Change Package (ECP) 041100534-37 to accept the as-found condition of the missing check valve internals including bonnets. The ECP updated the Updated Final Safety Analysis Report (UFSAR) Section 9.3.3.1, Sump and Drain Systems Design Bases, to document the as-found condition. The change is considered "adverse" as it accepts a degraded condition from the original plant design.

Drainage from engineered safety feature equipment rooms is configured to prevent flooding of engineered safety features equipment by drainage piping backflow. The Fuel Handling Building Sump Room contains spent fuel pool pumps P-009 and P-01 0 and Emergency Air Conditioning (A/C) Units E-441 and E-442. Check valves are installed on the main headers where they enter the sumps to assure that no backflow occurs between trains. However, the analysis contained in calculations M-0120-010, uFlooding Analysis Fuel Handling," and M-01 20-015, "Plant Flooding Analysis Review" demonstrates that the failure of checkvalves S2/32426MU169, MU170, and MU171 to close does not adversely impact any safe shutdown components or the overall plant safe shutdown capability.

Evaluation SummarV:

The FHB sump check valves S2/32426MU169, MU170 and MU171 design basis is to prevent flooding of engineered safety feature equipment from drainage piping backflow.

This design basis is established in UFSAR Section 9.3.3.1. Omission of these valves does not create any new accidents or malfunctions nor does it increase the frequency of any accident or malfunction previously evaluated in the UFSAR. As the change fails to create any new radiological release paths, consequences previously determined continue to bound the plant. Design basis limits for fission product barriers are unaffected by the change and methods of evaluation remain the same. As such, removal of the check valve internals including bonnets does not require prior NRC review or approval.

ENCLOSURE 2 10 CFR 72.48 EVALUATION SUMMARIES

AR 040300755-4: Scratches on the Inner liner of a Spent Fuel Transfer Cask

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Description:==

After using the Transfer Cask to move dry shielded canisters with Unit 1 spent fuel to the Independent Spent Fuel Storage Installation, scratches were found on the inner liner of the transfer cask. The thickness in a small area of the inner liner was found to be less than the minimum thickness required by Transnuclear's Transfer Cask drawing. A nonconformance report was initiated to address the condition. Transnuclear performed a 72.48 evaluation for a nonconformance found on the inner liner of the Onsite Transfer Cask. Scratches were found after normal use of the transfer cask and a small area (1.75 sq. in.) of the inner liner was found to have a thickness (0.412 inch) that was less than the minimum specified (0.44 inch) by Transnuclear's Transfer Cask drawing.

The transfer cask is a nonpressure-retaining vessel used for loading/unloading operations within the spent fuel building and for transfer operations to and from the Independent Spent Fuel Storage Installation (ISFSI). The cask provides the principal biological shielding and heat transfer mechanism for the Dry Shielded Canisters (DSC) and spent fuel assemblies during transfer, loading and retrieval operations. The transfer cask also provides primary protection for the loaded DSCs during accident events postulated to occur during the transfer operations. The transfer cask inner liner provides the structural support for the DSC, shielding and support for the lead gamma shielding.

The nonconformance was found to have a negligible effect on the Transfer Cask's safety functions and dispositioned to be "ACCEPT-AS-IS".

Evaluation Summary:

The nonconformance described in the above summary does not adversely affect the features, function, or performance of the transfer cask. The conclusion was based on the area of the nonconforming scratch still being within ASME code allowable for membrane stress, and located near the top of the transfer cask and away from the active fuel zone of a DSC which governs the thermal, criticality, and shielding analyses for the transfer cask.

Since the responses to all the eight 72.48 evaluation questions were "No," the accept-as-is disposition of the nonconformance may be implemented without an amendment to the General License.

AR 040800618-4: 72.48 Evaluation for Dry Cask Storage Canister and Inadvertent Introduction of Foreign Material SO1-207-1-M4044

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Description:==

This 72.48 evaluation addresses the inadvertent introduction of foreign material (paint chip) into Dry Shielded Canister (DSC) 24PT1-SO1-S016 during fuel loading and closure operations. As described in SCE's NCR 040800618-4, a small piece of a paint chip is lodged on an outer spent fuel assembly (SFA) between the upper grid strap and the fuel rods. This piece of paint chip is conservatively estimated to be 5/16" x 3/8" x 1/16". The DSC was loaded August 11, 2004 with a decay heat of approximately 8 kW.

Evaluation Summary:

Transnuclear performed a 72.48 evaluation for a nonconformance when a foreign material (paint chip) was inadvertently introduced into a dry shielded canister (DSC). A small piece of a paint chip was lodged on an outer spent fuel assembly (SFA) between the upper grid strap and the fuel rods. This piece of paint chip was conservatively estimated to be 5/16" x 3/8" x 1/16". The DSC has containment, shielding, criticality control, and thermal safety functions. The primary function of the DSC is to provide confinement for the spent nuclear fuel. This function is achieved by the stainless steel shell and the two inner cover plates (top and bottom ends) of the shell assembly. There are redundant outer cover plates (top and bottom) to assure confinement integrity. The DSC provides gamma shielding at its ends by the use of thick end plugs. These provide As Low As Reasonably Achievable (ALARA) dose rates at the top of the canister (for DSC drying and sealing operations) and at the bottom (for minimizing dose rates at the Advanced Horizontal Storage Model

[AHSM] doorway). Shielding in the radial direction is not a safety function of the DSC, although it does provide a small amount due to the shell thickness.

The DSC's internal basket assembly provides criticality control. A series of spacer disks and axial support rods maintain the fuel assemblies in known positions under all normal and accident conditions. The thickness and location of the spacer disks, the BORAL poison plate and the relative locations of the fuel assemblies achieve the criticality control function. The primary pressure boundary, which is ASME SA-204, Type 316 stainless steel, maintains an inert (helium) dry atmosphere inside the DSC to minimize pressure boundary and fuel degradation.

The nonconformance was found to have a negligible effect on the safe storage of spent fuel in the dry shielded canister and dispositioned to be "ACCEPT-AS-IS." Based on this evaluation it was determined that prior NRC approval was not required for this proposed activity.

ENCLOSURE 3 SAN ONOFRE NUCLEAR GENERATING STATION UNIT 2 AND 3 REPORT ON THE COMMITMENT CHANGES MADE PER NEI "GUIDELINES FOR MANAGING NRC COMMITMENT CHANGES" FOR THE PERIOD FROM JULY 1, 2003 UNTIL JUNE 15, 2005

REPORT ON COMMITMENT CHANGES MADE PER NEI "GUIDELINES FOR MANAGING NRC COMMITMENT CHANGES" NRC letter to Mr. Ralph Beedle, Senior Vice President and Chief Nuclear Officer, Nuclear Energy Institute (NEI), dated March 31, 2000 and SECY-98-224, " Staff and Industry Activities Pertaining to the Management of Commitments Made by Power Reactor Licensees to the NRC ", both state that the NEI 99-04 "A Guidelines for Managing NRC Commitments Changes" Revision 0, dated August 2,1999, was an acceptable guide for licensees to follow for managing and changing their commitments to the NRC. Part of the commitment change process, given in the NEI guidelines, identifies that various commitments can be changed with the notification to the NRC made in a report submitted annually or along with the FSAR updates as required by 10CFR50.71 (e). The intent of this report would be to provide a brief summary of the commitments changed since the last report in lieu of filing individual notifications as commitments are revised.

The following summarizes the commitment changes for San Onofre Units 2 and 3 that are to be reported and have occurred from the last facility change report of July 1, 2003 until June 15, 2005.

1. Reactor Trip Breaker Surveillance Technical Specification 3.3.4, Reactor Protective System Logic and Trip Initiation, has a surveillance frequency of 18 months for performing a channel functional test.

In the October 2, 1985 response to Generic Letter (GL) 83-23, SCE stated that the Preventative Maintenance (PM) interval for the Reactor Trip Breakers (RTBs) would be 6 months. This response to GL 83-23 was based on the original April 15, 1983 SCE commitment and May 2, 1983 NRC SER on RTBs. The commitment for the frequency for RTBs testing was changed from every 6 months to 12 months based on successful testing, frequent testing results in unnecessary cycling of the RTBs and the vendor's recommended maintenance schedule for the General Electric breakers of every 12 months. This commitment change was reported in the San Onofre Facility Change Report Dated January 21, 1998.

The RTBs have been replaced with Square-D breakers that have a vendor's recommended maintenance schedule of 6 years. Based on this, the frequency for the RTBs surveillance test has now been change to 18 months as allowed by Technical Specification Surveillance Requirement 3.3.4.3.

This commitment change is being reported to the NRC in the Refueling interval summary report per the NEI Guidelines. This is a change made in response to a Generic letter that already has been implemented.

2. Removal of the Seawall Chain Link Fence SCE lacks total control over a segment of the exclusion area established at SONGS. This matter was the subject of construction permit hearings directed at considering whether SCE's control over the beach posed no significant hazards to the public health and safety.

During the proceedings, SCE presented information related to certain physical features and administrative controls for restricting use of the beach included within the SONGS exclusion area. The features included the construction of a walkway adjacent to the seawall with an eight-foot high chain link fence that was to be provided along the seaward side of the walkway, and extending to the mean high water line at the northern and southern ends of the exclusion area to minimize recreational activities in the landward portion of the exclusion area between the seawall and the mean high water line.

The NRC Safety Evaluation Report for the operating license stated that a chain link fences extending between the beach passageway and the mean high tide line, would be used to control the population on the beach within the exclusion area.

In response to new criteria used for the Design Basis Threat, enhancements have been made to the San Onofre site features. Part of this enhancement has been placing "rip rap" along the seawall that substantially covers the portion of the exclusion area between the seawall and the mean high water line and limits any recreational use of this portion of the beach. Based on this and the enforcement of the control over use of the landward portions of the exclusion area by security personnel, the eight-foot high chain link fence has been removed.

This commitment change is being reported to the NRC in the Refueling interval summary report per the NEI Guidelines. This is a change to a commitment that was explicitly credited in an NRC SER.

2005FCRchanges