Text

Safety Evaluation Supporting Amends 232,232 & 231 to Licenses DPR-38,DPR-47 & DPR-55,respectively
	ML15261A468
Person / Time
Site:	Oconee
Issue date:	09/04/1998
From:	; Office of Nuclear Reactor Regulation
To:	; Duke Energy Corp
Shared Package
ML15261A466	List: ML15261A464; ML15261A468;
References
	NUDOCS 9809140155
	Download: ML15261A468 (47)
	v • d • e

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20556-4001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 232 TO FACILITY OPERATING LICENSE DPR-38 AMENDMENT NO. 232 TO FACILITY OPERATING LICENSE DPR-47 AND AMENDMENT NO. 231 TO FACILITY OPERATING LICENSE DPR-55 DUKE ENERGY CORPORATION OCONEE NUCLEAR STATION. UNITS 1. 2. AND 3 DOCKET NOS. 50-269, 50-270, AND 50-287

1.0 INTRODUCTION

By letter dated March 11, 1993, as supplemented August 26, October 26, November 29, and December 6, 1993, October 3, 1995, February 27, May 2, and September 3, 1997, and May 7, 1998, Duke Energy Corporation (Duke, the licensee) submitted a request for changes to the Oconee Nuclear Station, Units 1,2, and 3, Technical Specifications (TS). The requested changes would completely revise the current TS related to the electrical distribution system and incorporate new requirements for system operation, limiting conditions for operation, and surveillance requirements. These amendments also provide the technical basis for similar provisions related to the electrical distribution system that were included in your submittal dated October 28, 1997, and supplements, to convert the present TS to the Improved TS (ITS), which are under separate review (TAC Nos. M99912, M99913, and M99914) and will be relabeled Section 3.8 in the ITS.

The May 2, 1997, and May 7, 1998, letters provided clarifying information that did not change the initial proposed no significant hazards consideration determination.

2.0 BACKGROUND

As a result of events described and commitments specified in Licensee Event Report Numbers 50-269/89-09, 89-11, and 90-04, the decision was made to completely rewrite Section 3.7 "Electrical Power Systems" of the Oconee Nuclear Station (ONS, Oconee) TS. The TS rewrite makes use of the format of the revised Standard TS (STS) (NUREG-1430) and is expected to produce an improvement in safety due to more operator-oriented TS.

By letter dated March 11, 1993, the licensee submittal the complete rewrite of the current ONS TS. By letter dated September 29, 1993, the staff provided a request for additional information (RAI). This RAI requested specific information regarding the proposed TS Section 3.7 submittal. On October 7, 1993, a meeting between the staff and licensee personnel was held to discuss the proposed TS changes and the information requested in the RAI. The licensee 9809140155 980904 PDR ADOCK 05000269 P PDR

-2 responded to the RAI and TS concerns in letters dated November 29 and December 6, 1993.

Additional discussions of staff concerns relating to the proposed electrical TS occurred between the staff and the licensee during the fourth quarter of 1994 and the first quarter of 1995. A conference call was conducted between the staff and the licensee on March 8, 1995, to discuss unresolved issues and related RAls. A written response for the issues discussed during the March 8, 1995, conference call was provided by the licensee by letter dated October 3, 1995.

During the second quarter of 1995, it was determined that the NRC staff would perfprm a special review of the Oconee emergency power system. As a result, it was determined that completion of the proposed electrical TS Section 3.7 amendment would be delayed until the completion of the major portion of the special review. As the special review was nearing completion, additional discussions regarding the proposed electrical TS Section 3.7 amendment were held with the licensee on December 5, 1996, and April 2, 1997. These discussions focused on specific staff concerns and additional information requests related to the proposed amendment. Licensee responded to staff concerns and additional information requests by letters dated February 27, 1997 and September 3, 1997. A supplemental electrical TS was submitted by letter dated February 27, 1997. By letter dated September 3, 1997, the licensee replaced the initial submittal and the February 27, 1997, supplemental TS submittal[ Due to the numerous changes in the revised TS submittal, along with previously identified concerns, the staff issued an additional RAI by letter dated November 14, 1997. The licensee provided a response to this RAI by letter dated May 7, 1998. The licensee supplemented the revised TS submittal in the May 7, 1998, letter. The staff and licensee discussed additional issues relating to TS Section 3.7 on May 11 and 12, 1998, and on June 9, 1998.

3.0 EMERGENCY ELECTRICAL SYSTEM DESIGN DESCRIPTION An offsite power system and an onsite power system are provided for each ONS unit to supply the unit auxiliaries during normal operation and the reactor protection and engineered safeguards protection systems during abnormal and accident conditions. Each of the three Oconee units is designed to have six available sources of power to the engineered safeguards systems. These are the 230 kv transmission system, the 525 kv transmission system, two Keowee hydro units, the 100 kv transmission system, and the two other nuclear units.

ONS Unit 3 generates electrical power at a nominal 19 kv that is fed through an isolated phase bus to a unit main step-up transformer where it is stepped up to the nominal transmission voltage of 525 kv. From the step-up transformer an overhead transmission line feebs power to the 525 kv switching station through two circuit breakers connecting the unit to the 525 kv transmission network. For Units 1 and 2, each unit generates electric power at a nominal 19 kv that is fed through an isolated phase bus to each unit's main step-up transformer, where it is stepped-up to a nominal transmission voltage of 230 kv. From the step-up transformers, overhead transmission lines feed power to the 230 kv switching station through circuit breakers that connect the units to the 230 kv transmission network. The 525 kv and 230 kv transmission networks are electrically cross-connected by an auto-bank transformer, circuit breakers, and attendant transmission lines.

The normal power supply to a unit's auxiliary load is provided through its auxiliary transformer connected to the generator output bus. If power is not available from a unit's generator through W

-3 the unit auxiliary transformer, power is supplied to the unit through its startup transformer fed from either or both of the buses in the 230 kv switching station. If adequate power is not available from any of the generating units, the 230 kv switching station, or the hydro units, power is available to the standby buses from a Lee gas turbine via a 100 kv transmission line connected to transformer CT-5. This transformer is located on the opposite side of the station from the 230 kv facilities.

The Keowee Hydro Station contains two units, rated 87.5 MVA each, that generate electrical power at a nominal 13.8 kv. The design is such that, upon loss of power from the Oconee generating unit and the 230 kv switchyard, power is supplied from both Keowee units through two separate and independent paths, each path predesignated for each Keowee unit. One path is an overhead 230 kv transmission line to the 230 kv switchyard yellow bus, which, in turn, supplies each unit's startup transformer. The overhead transmission line pathway contains air circuit breakers (ACBs) 1 or 2, and a main step-up transformer so that it can be connected to either of the Keowee generators. The second path is an underground feeder cable to transformer CT-4, which supplies the redundant standby power buses. The underground feeder contains ACBs 3 or 4, so that it can be connected to either of the Keowee generators.

The underground feeder is connected to one hydroelectric generator on a predetermined basis and is energized along with transformer CT-4 whenever that generator is in service in either the

. emergency or normal mode. The underground feeder and associated transformer are sized to carry full engineered safeguards auxiliaries of one ONS unit plus auxiliaries for safe shutdown of the other two ONS units.

Each Keowee unit is provided with its own automatic startup equipment. On an External Grid Trouble Protection System actuation, an engineered safeguards actuation, or a main feeder bus monitor undervoltage actuation, both units start automatically and simultaneously, and run on standby. The output breaker closes on unit designated to supply the underground feeder and the other unit is available to supply the ONS 230 kv switching station, if needed. If there is a system disturbance, this unit is connected automatically to the Oconee 230 kv yellow bus only after the Oconee 230 kv yellow bus is isolated automatically from the system and a preset time delay has elapsed. An External Grid Trouble Protective System is designed to isolate the 230 kv yellow bus upon failure of the external transmission network. A Degraded Grid Protection System monitors the 230 kv yellow bus for degraded voltage conditions. By design, actuation of this system and the presence of an engineered safeguard signal also results in isolating the 230 kv yellow bus. Thus, on separation from the external transmission network, both of the Keowee hydro units provide emergency power to the ONS units by way of either the 230 kv switching station and a unit's respective startup transformer or the underground feeder, transformer CT-4, and the standby buses.

The 4.16 kv auxiliary power system for each unit includes two main feeder buses. Each bus is provided with a circuit breaker switching arrangement to permit connecting it to one of three power sources. These sources are (1) a unit auxiliary transformer, (2) a startup transformer, and (3)two standby power buses. These sources feed each of the main feeder buses by a double circuit breaker arrangement. Each of the two redundant 4.16 kv main feeder buses provide power to each of the three engineered safeguards switchgear bus sections that serve the engineered safeguards loads.

-4 4.0 DISCUSSION AND EVALUATION 4.1 TS 3.7.0, "Electrical Power Systems" 4.1.1 Proposed Change The licensee has proposed the following change:

Entry into operational conditions (e.g., HOT SHUTDOWN, COLD SHUTDOWN) specified in the Applicability shall not be made when the requirements of TS 3.7 are not met, unless the associated Actions for the operational conditions to be entered permit continued operation in the specified condition for an unlimited period of time.

4.1.2 Evaluation This specification does not prevent changes in the operational conditions specified in the Applicability that are required to comply with Actions. In addition, other exceptions to proposed TS 3.7.0 are identified in the individual specifications addressed below. These exceptions allow entry into operational conditions in the Applicability when the associated Actions to be entered allow operation for only a limited period of time.

The above restriction regarding entry into operational conditions and the exception to this restriction are consistent with those contained in the revised STS.

4.2 TS 3.7.1, "AC Sources - Operating" 4.2.1 Background The alternating current (ac) power system consists of the offsite power sources (preferred power) and the Keowee hydro onsite standby power sources. This system is designed to supply the required engineered safety features (ESF) loads of one unit and safe shutdown loads of the other two units and is so arranged to preclude a single failure from disabling enough loads to jeopardize plant safety. The Keowee hydro turbine generators are powered through a common penstock by water taken from Lake Keowee.

The preferred power source is provided from offsite power to the red or yellow buses in the 230 kv switchyard to the unit startup transformers and the E breakers. The 230 kv switchyard is electrically connected to the 525 kv switchyard via the autobank transformer. The standby buses may receive offsite power from a 100 kv transmission system through CT-5 and the SL breakers. The two emergency power paths are the overhead path and the underground path. The underground emergency power path is from one Keowee hydro unit through the S breakers. The overhead emergency power path is from the other Keowee hydro unit through the E breakers. In addition to supplying emergency power for Oconee, the Keowee hydro units provide power to the generation system. During periods of commercial power generation, the Keowee hydro units are operated within the acceptable region of the Keowee hydro operating restrictions. This is to ensure that the Keowee units will be able to perform their emergency power functions from an initial condition of commercial power generation. The Keowee hydro

-5 operating restrictions for commercial power generation are contained in the Selected Licensee Commitment (SLC) manual. Since this manual is Chapter 16 of the Oconee Final Safety Analysis Report, changes to these operating restrictions, if needed, would be performed in accordance with the provisions 10 CFR 50.59, which would include an evaluation to determine if any unreviewed safety question exists. The standby buses can also receive power from a combustion turbine generator at the Lee Steam*Station through a dedicated 100 kv transmission line, transformer CT-5, and both SL breakers. The 100 kv transmission line is electrically separated from the system grid and offsite loads.

4.2.2 Proposed TS Changes The limiting conditions for operation (LCO) for proposed TS Section 3.7.1 requires that the following ac electrical power sources be OPERABLE: (1) one underground emergency power path from one Keowee hydro unit through the S breakers; (2) one overhead emergency power path from a second Keowee hydro unit through the E breakers; (3) one underground emergency power path from a second Keowee hydro unit through the S breakers; (4)two offsite sources on separate towers connected to the 230 kv switchyard; and (5)one Lee gas turbine.

The proposed TS Section 3.7.1 contains 11 conditions addressing equipment that must be O operable in order to comply with the LCO. Each of these conditions describes a level of degradation (below the LCO) and is provided with a required action or actions and attendant completion time or times. The completion times provided are the times permitted to complete the required actions. Two other conditions are also provided in this proposed TS section. One of the two was added as a result of the NRC staffs special review and addresses the condition of required action and associated completion time for energizing a standby bus from a Lee gas turbine not met. The other condition addresses specific situations involving not meeting the provided required actions and associated completion times and requires placing a unit in hot and/or cold shutdown conditions.

This proposed TS section also includes three notes. One note states that the underground emergency power path specified in LCO 3.7.1.3 (one underground emergency power path from a second Keowee hydro unit through the S breakers) is not required to be operable when overhead electrical disconnects for the underground emergency power path specified in LCO 3.7.1.1 (one underground emergency power path from one Keowee hydro unit through the S breakers) are open. Another note states that one Lee gas turbine is only required to be operable when: (a) underground emergency power path is inoperable > 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , (b) overhead Keowee hydro unit is inoperable > 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , (c) Keowee main step-up transformer is inoperable

> 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , (d) both emergency power paths are inoperable for planned reasons, (e) both emergency power paths are inoperable > 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months for unplanned reasons, and (f) one or more required offsite sources are inoperable > 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The remaining note states that during periods of commercial power generation, the operability of the Keowee hydro units shall be based on the lake levels and the power level of the Keowee hydro units. This note also states that the

. Keowee hydro operating restrictions for commercial power generation shall be contained in the ONS SLC manual. The following paragraphs contain the thirteen conditions for this propose TS section and address staff concerns related to this section.

4.2.3 Conditions Condition A of proposed TS Section 3.7.1 concerns one or more required offsite sources and overhead emergency power path being inoperable due to an inoperable startup transformer.

For this condition, the required actions and associated completion times are to perform surveillance requirement (SR) 3.7.1.4 in 1 hourif not performed in previous 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter, share another unit's startup transformer in 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , and designate shared startup transformer to one unit in 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

Condition B of this proposed TS section concems the sharing of a startup transformer designated to another unit or required actions and associated completion times not being met for Condition A. The required actions and completion times for Condition B are that the unit be in hot shutdown in 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and be in cold shutdown in 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The proposed requirement to perform the required surveillance up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months prior to inoperability of the startup transformer, is considered to be a clarification to the current TS completion time requirements that permits testing of the underground emergency power path prior to a planned outage of a startup transformer and to potentially credit routine testing of the underground emergency power path.

EG&G Technical Letter Report, "Adequacy of Station Electric Distribution System Voltages, Oconee Nuclear Station, Units 1,2, and 3," dated January 1983, noted that: "The present Technical Specifications permit the alignment of one startup transformer to two units. However, their analyses of June 4, 1980, and February 5, 1982, show that under degraded grid conditions, the Class 1E equipment would be required to operate below their minimum ratings.

Therefore, Duke Power Company (DPC) has proposed to change their technical specifications to limit the use of a startup transformer to one unit. This will insure adequate voltage for the Class 1E equipment." Since this commitment appeared to preclude sharing of a startup transformer under any conditions, and the proposed TS permit sharing, the licensee was requested to address how the initially proposed TS conform to this commitment. In response to this request, the licensee noted that the voltage adequacy concerns raised in the EG&G Technical Evaluation were identified by the licensee in response to an NRC letter dated August 8, 1979. This letter required that all licensees review the electrical power systems to determine if sufficient capacity existed to start and operate all required safety loads under degraded conditions. In a safety evaluation addressing the Duke electrical power system analysis, the analysis was found to be acceptable subject to implementation of a change to the TS that prohibits the use of one startup transformer for more than one unit. The TS revision that implemented the requirements of the EG&G Technical Evaluation was submitted and approved on March 17, 1983, and March 2, 1984, respectively. In the cover letter that accompanied Amendment Nos. 127, 127, and 124, it was stated that the open issue (distribution of voltages at the safety buses when one unit startup transformer is shared between units) is considered closed with the issuance of these amendments. Amendment Nos.

127, 127, and 124 are included in the current TS that allows the sharing of a startup transformer by two units under limited conditions. Further, the response from the licensee notes that the sharing of a startup transformer is allowed in order to shut down a unit with an inoperable transformer using the preferred method. Shutting down with an operable startup transformer will allow the use of the reactor coolant pumps for the preferred shutdown path rather than natural circulation for the limited time described in the TS. This response adequately addresses the issue.

-7 Condition C of this proposed TS section is the overhead emergency power path inoperable due to reasons other than Condition A or B, and with the underground emergency power path operable. For this condition, the required actions and completion times are to perform SR 3.7.1.4 in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months if not performed in the preceding 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter unless two standby buses are energized by an operable Lee gas turbine, and to enter applicable conditions and required actions for overhead emergency power path inoperable for

> 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months in 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . A note provided for Condition C states that required actions must be completed prior to entering the applicable conditions. These required actions are to energize two standby buses by an operable Lee gas turbine with the 100 kv transmission circuit electrically separated from the system grid and all offsite loads, and verify, by administrative means, that the operability status of: (a) two offsite sources and underground emergency power path; and (b)overhead Keowee hydro unit or overhead emergency power path excluding Keowee hydro unit; distribution systems; emergency power switching logic (EPSL); dc (direct current) sources; and vital inverters.

Condition D of this proposed TS section addresses operability of the underground emergency power path inoperable and overhead emergency power path. For this condition, the required actions and completion times are to perform SR 3.7.1.5 in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months if not performed in the preceding 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter unless two standby buses are energized by an operable Lee gas turbine, and energize a standby bus by an operable Lee gas turbine O with the 100 kv transmission circuit electrically separated from the system grid and all offsite loads in 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from subsequent discovery of deenergized standby buses, and restore underground emergency power path to operable status in 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . Proposed Conditions C and D were initially proposed by the licensee as a single condition. This single condition was one emergency power path inoperable due to reasons other than an inoperable startup transformer (Condition A). For this single condition, the required actions and completion times were the same as provided above for Condition C. During the NRC staff special review, it was determined from a risk perspective that additional measures should be applied to an inoperable underground emergency power path. This determination included factors such as single Keowee unit maintenance is not performed on the Keowee unit assigned to the underground power path and establishing the overhead power path is dependent upon successful operation of the switchyard isolation function. In addition, the overhead emergency power path would likely be lost'for severe weather conditions. In response to this determination, the licensee proposed Conditions C and D, which address separately the overhead and underground emergency power paths with the additional measure to energize a standby bus by an operable Lee gas turbine with the 100 kv transmission circuit electrically separated from the system grid and all loads in 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months if the underground power path is inoperable.

For the initially proposed single condition, the staff expressed concern regarding verifying the remaining emergency power path once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months versus the current TS requirement of once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . In response to this concern, the licensee provided the following reasons. The schedule would align with the current operating shift schedule of 12-hour shifts. When the

. original TS limit of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months was provided, the operators were working 8-hour shifts. Another reason is that it will reduce unnecessary testing requirements. In support of this reason, the licensee response is that the STS includes a testing requirement for verification of diesel generator operability within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of determining that the redundant diesel generator is

-8 inoperable. Also, the STS indicate that verification of diesel generator operability without testing is allowed to avoid unnecessary testing of operable diesel generators. However, operability of the Keowee unit is to be determined by test rather than allowing the option for verification without testing. The two reasons provided for the change are not viewed as acceptable technical reasons since the first addresses an administrative matter and the other is applicable to a design that is significantly different from that for the Keowee units. However, to technically support the change, it is noted that operability of a Keowee unit is to be established by actual testing versus allowing the option of verification without testing. This, along with the low increase in risk due to the additional 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , resolved this concern. This discussion also applies to Condition A (previously discussed).

The current TS allow one single string or single component of the Keowee 125 vdc power system to be inoperable for periods not exceeding 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . However, Condition C or D of this proposed TS section allows one emergency power path to be inoperable (due to reasons other than an inoperable startup transformer) for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months provided the identified required actions and completion times are met. Since, when a Keowee 125 Vdc power system is inoperable, the associated Keowee unit and emergency power path would be considered inoperable, this proposed TS section revises the allowed outage time (AOT) for the Keowee 125 Vdc power system. Thus, the staff requested a technical discussion that explains and supports the less restrictive AOT. The licensee's response to this concern was that the Keowee 125 Vdc system consists of two separate and independent power strings (one per unit). Inoperability of a string or single component in the Keowee 125 Vdc power system will result in entering an action statement due to the inability of Keowee to meet the single failure criterion. The response also indicates that during the 72-hour period both Keowee units would be physically available since the dc buses would be cross-tied and fed from a single battery. Further, the Keowee battery system will not impair the ability of the degraded grid or external grid protection systems to operate. This system cannot impair the ability of the EPSL to function and seek alternate power sources. In addition, an AOT of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months will align the time restriction for an inoperable emergency path and the Keowee 125 Vdc power system. While it is recognized that the proposed TS align the time restriction, the staff continued to express concern that the proposed less restrictive AOT could negate the expectation that the Keowee unit availability will not decrease significantly. Thus, the staff requested the licensee to provide a discussion addressing the expectation that the Keowee unit availability will not decrease significantly because of the change in AOT and why common cause implications resulting in inoperability of both units are not viewed to be significant when the dc buses are cross-tied. The licensee's response to this request is that the Keowee unit availability is not expected to decrease significantly as a result of the AOT change since planned maintenance activities are not expected to be changed in a manner which would result in increased outages of the Keowee 125 Vdc system. In addition, unplanned maintenance activities are not expected to significantly increase above past levels. Further, the Keowee units are included in the maintenance rule program and as such any significant increase in the unavailability of the units will be identified.

If the unavailability for the units is below the maintenance rule program requirements, corrective actions will be taken to restore the availability of the units. The response also notes that when the Keowee 125 Vdc buses are cross-tied, both Keowee units are available to supply power during an emergency since Oconee calculations demonstrate that a single Keowee battery can supply the loads for both units during an emergency. If the Keowee 125 Vdc buses are not cross-tied, only one unit would be available to supply power. In addition, when the Keowee 125

-9 Vdc buses are cross-tied, Oconee operates under a TS action statement because the units are not single failure proof. While operating under the TS action statement, no other failures are postulated to occur. This response resolved the concern.

Another concern regarding Condition C is that it does not provide an explicit completion time requirement to restore the overhead emergency power path to operable status if this path is inoperable due to reasons other than an inoperable startup transformer, no designated startup transformer, an inoperable Keowee hydro unit, or an inoperable Keowee main step-up transformer. The staff requested the licensee to provide a discussion that explains why an explicit restoration completion time requirement is viewed to be unnecessary or revise the section to include such a requirement. The licensee's response to this request was that the ability to restore a component to operable status is always an option that will allow for the plant to exit the associated condition. The requirement to restore a component to an operable status is specified in the STS in cases where the information defines the length of the completion time for a condition. If other actions define the length of the completion for a condition, the option for restoration of the component to an operable status does not need to be contained in the TS.

For an inoperable overhead emergency power path in Condition C, the conditions for an extended outage of the overhead emergency power path can be entered at the end of the 72-hour completion time. This requirement defines the length of the completion time for the

. condition and a separate restoration requirement is not necessary. Inthis regard, the emergency power path must be restored to operable status in 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , or the condition for an extended outage of the overhead path must be entered in 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , or a controlled shutdown must be initiated in accordance with TS 3.7.1 at the end of the 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This response resolved the concern.

Condition E of this proposed TS section relates to the required action and associated completion time for required action D.2 (energize a standby bus by an operable Lee gas turbine with the 100 kv transmission circuit electrically separated from the system grid and all offsite loads in 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ) not being met. For this condition, the required actions and completion times are to be in hot shutdown in 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for the first ONS unit shutdown and 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for subsequent ONS unit(s), and be in cold shutdown in 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months . Required actions and completion times for this condition provide a cold shutdown path (for the ONS units) that is consistent with the current TS. Further, Condition E is consistent with the commitment established during the staffs special review since it requires additional actions to be taken if the added measure provided for an inoperable underground power path is not met.

Condition F of this proposed TS section is one inoperable E breaker and one inoperable S breaker on the same main feeder bus. The required action and completion time for this condition is to declare the associated main feeder bus inoperable immediately. The staff noted that degradation occurs with one inoperable E breaker and one inoperable S breaker on different main feeder buses and that the proposed TS do not specifically address this situation.

The response from the licensee for this item was that both E breakers are needed for overhead power path operability and both S breakers are needed for underground power path operability.

. Thus, for the situation with one E breaker inoperable on one main feeder bus and one S breaker inoperable on the other main feeder bus, the overhead emergency power path and the underground emergency power path would be declared inoperable. Inoperability of both emergency power paths is provided as proposed Conditions G and H and is specifically

-10 addressed. Another related item not specifically addressed involved the situation of one inoperable E breaker and an operable startup transformer. For this situation, the response from the licensee notes that when one of two E breakers is inoperable and the startup transformer is operable, the overhead path is inoperable. Thus, in order for the overhead emergency power path and the underground emergency power path to be considered operable, the two E breakers and the two S breakers must be operable. These responses resolved these concerns.

Condition G of this proposed TS section concerns the condition when both emergency power paths are inoperable for planned reason other than Condition F. For this condition, the required actions and completion times are to energize two standby buses by an operable Lee gas turbine with the 100 kv transmission circuit electrically separated from the system grid and all offsite loads as a prerequisite and 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from subsequent discovery of deenergized standby buses, and verify by administrative means the operability status of two offsite sources, distribution systems, EPSL, dc sources, and vital inverters as a prerequisite. In addition, restore inoperable components to two offsite sources, distribution systems, EPSL, dc sources, and vital inverters to operable status in 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from discovery of inoperable component, and restore one emergency power path to operable status in 60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months . A note for Condition G states that TS 3.7.0 is not applicable when both standby buses are energized by an operable Lee gas turbine.

Condition H of this proposed TS section concerns the condition when both emergency power paths are inoperable for unplanned reason other than Condition F. For Condition H, the required actions and completion times are to energize two standby buses by an operable Lee gas turbine with the 100 kv transmission circuit electrically separated from the system grid and all offsite loads in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from subsequent discovery of deenergized standby buses, and verify by administrative means the operability status of two offsite sources, distribution systems, EPSL, dc sources, and vital inverters in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . In addition, restore inoperable components totwo offsite sources, distribution systems, EPSL, dc sources, and vital inverters to operable status in 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from discovery of inoperable component, and restore one emergency power path to operable status in 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

Conditions G and H were initially proposed as the single condition of both emergency power paths inoperable. The staff expressed concern regarding this initially proposed single condition in that the proposed completion time of 60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months to perform required actions was not consistent with that provided in the current TS. The current TS allow 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for the reactor to remain critical if both Keowee hydro units become unavailable for unplanned reasons. The licensee's response to this concern is that current TS provide an AOT of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months if both emergency power paths are inoperable due to an unplanned situation. For a planned outage of both emergency power paths, the current TS has an AOT of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . The licensee's response also noted that the combination of these two situations into one requirement is viewed necessary to eliminate the determination of what is planned and unplanned. In practice, there has beeh confusion in defining the difference between a planned and an unplanned outage. In discussing this issue with the licensee, the staff noted that this basis is not viewed as a good technical one to support the change. Subsequently, in the revised TS submittal, the licensee provided proposed Conditions G and H, which are in accordance with the current TS requirements.

These actions resolved the concern.

Another staff concern involved permitting up to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months to reenergize the standby buses from a Lee gas turbine. The current TS Section 3.7 does not explicitly address the situation where the standby buses are discovered not to be energized when both Keowee hydro units are inoperable. For this situation, the current TS could be interpreted as requiring an immediate unit shutdown and/or a report to the NRC and as such, the proposed TS are not consistent with this requirement. In discussing this issue with the licensee, additional documentation containing information that provides justifications for the 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months to reenergize the standby buses subsequent to discovering they are deenergized was requested. The licensee's response to this request was that to allow an additional hour to reenergize the standby buses subsequent to the buses becoming deenergized has been reviewed by using the ONS probabilistic risk assessment. This evaluation assumed that both Keowee units were unavailable and the Lee unit on the standby buses had failed. If offsite power is lost while in this situation, the potential recovery methods include starting another Lee unit, recovery of offsite power, and utilizing the standby shutdown facility. The hourly increase in risk of a core damage event for the situation was determined to be less than 1.0 E-7 to the annual core damage frequency. Thus, the additional risk incurred by allowing 1 additional hour prior to entry into a unit shutdown path is insignificant. In addition to this response, it is noted that the 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is reasonable to diagnosis the Lee power path and take necessary corrective actions to restore this power path prior to entry into a unit shutdown path. The licensee response and the deterministic information addressing the Lee power path restoration resolved the concern. This discussion also applies to the 1-hour completion time (for reenergizing the standby buses subsequent to discovering they are deenergized) provided in Conditions D,G, H,and I of proposed TS Section 3.7.1.

Conditions as initially proposed for TS Section 3.7.1 relocated to the Bases section the current TS requirement for the Lee gas turbine and 100 kv transmission circuit to be separated from the system grid and offsite nonsafety-related loads if the standby buses are energized by a Lee gas turbine. In view of this, the staff requested a discussion that included technical bases and a description of how the mode of operation for the Lee Gas Steam Station power path is considered equivalent to the current one. The response by the licensee for this request was that the use of Lee as a backup power source has not changed from the current TS. Under the initially proposed TS, the connection of the Lee Station to the standby bus would be the same as in the current TS. The licensee's response also noted that connection of the Lee gas turbine to the standby bus by way of a path that is electrically separate from the system grid and the offsite loads, would be added to the specification sections where the Lee Station is required to be operable by the proposed TS. In a supplemental TS submittal, the licensee added to Conditions D,G, H, and I of the proposed TS Section 3.7.1, the required action that the 100 kv transmission circuit will be electrically separated from the system grid and all offsite loads. The revised TS submittal retained this required action and resolved the concern.

The staff also noted that for planned test or maintenance resulting in both Keowee hydro units being inoperable, the initially proposed Condition G retains the requirement that the standby buses be energized by a Lee gas turbine. However, for this case, the initially proposed Condition G changed the required action (energize the standby buses from the Lee Station) completion time from being a prerequisite (current TS requirement) to be performed within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The licensee's response for this concern was that there is no significant difference in the probability or the consequences of postulated events requiring emergency power during this 1-hour period if inoperability of both Keowee hydro units is due to planned or unplanned

-12 reasons. In addition, although not required by the TS, the licensee's response noted that good engineering practice will be followed and that the standby buses will be energized by the Lee gas turbine prior to future preplanned outages of both Keowee hydro units. However, the staff continued to express concern regarding this change and in the revised TS submittal, the licensee revised the TS requirement such that energizing two standby buses by an operable Lee gas turbine is a prerequisite for entering Cdndition G. This revised TS requirement is consistent with the current TS and also resolved the concern.

Condition I of this proposed TS section is one or more required offsite sources inoperable due to reasons other than Condition A (inoperable startup transformer) or Condition B (shared startup transformer). Required actions and completion times for this condition are to energize two standby buses by an operable Lee gas turbine with the 100 kv transmission circuit electrically separated from the system grid and all offsite loads in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from subsequent discovery of deenergized standby buses; and verify by administrative means the operability status of two emergency power paths, distribution systems, EPSL, dc sources, and vital inverters in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . In addition, restore inoperable components to two emergency power paths, distribution systems, EPSL, dc sources, and vital inverters to operable status in 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from discovery of inoperable component, and restore required offsite sources to operable status in 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The current TS requirement for restoration of inoperable offsite sources is retained with a 24-hour completion time. This completion time in proposed Condition I applies to restoration of all required offsite sources, rather than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to restore one source. This change is a restriction not presently included in the current TS. The current TS requirement to be in hot standby within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months if one of the required offsite sources is not restored has been replaced with the requirement to be in hot shutdown in 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The current TS requirement to be in cold shutdown within a total of 108 hours0.00125 days 0.03 hours 1.785714e-4 weeks 4.1094e-5 months after initial loss has been reduced to 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months . These changes are provided in Condition M and are consistent with the.

shutdown path required for the remainder of proposed TS Section 3.7.

Condition J addresses a condition when the overhead emergency power path is inoperable for

> 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months due to an inoperable Keowee hydro unit. For this condition, the required actions and completion times are to energize two standby buses by an operable Lee gas turbine with the 100 kv transmission circuit electrically separated from the system grid and all offsite loads.

This is a prerequisite for entering the condition and within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from subsequent discovery of deenergized standby buses, verify by administrative means the operability status of two offsite sources and underground emergency power path, overhead emergency power path (excluding Keowee hydro unit), distribution systems, EPSL, dc sources, and vital inverters as a prerequisite. In addition, restore inoperable components to.two offsite sources and underground emergency power path, overhead emergency power path (excluding Keowee hydro unit), distribution systems, EPSL, dc sources, and vital inverters to operable status within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from discovery of inoperable component. Also, perform SR 3.7.1.4 once per 7 days, and restore Keowee hydro unit to operable status in 42 days. This condition may once in a 3-year period for each Keowee hydro unit.

Four notes are provided with Condition J. One of these notes indicates that Condition J is only applicable once in a 3-year period for each Keowee hydro unit. Another is that the Keowee hydro unit generation to the system grid is prohibited except for test. An additional note is that the operable Keowee hydro unit may be inoperable for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months if required to restore both 0

-13 Keowee hydro units to operable status. The remaining note is that TS 3.7.0 is not applicable when both standby buses are energized by an operable Lee gas turbine.

Condition K concerns the overhead emergency power path being inoperable > 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months due to inoperable Keowee Main Step-up transformer. For Condition K, the required actions and completion times are to energize two standby buses by an operable Lee gas turbine with the 100 kv transmission circuit electrically separated from the system grid and all offsite loads as a prerequisite. Within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from subsequent discovery of deenergized standby buses, and verify by administrative means, the operability status of two offsite sources and underground emergency power path, overhead Keowee hydro unit, distribution systems, EPSL, dc sources, and vital inverters as a prerequisite. Also, restore inoperable components to two offsite sources and underground emergency power path, overhead Keowee hydro unit, distribution systems, EPSL, dc sources, and vital inverters to operable status within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from discovery of inoperable component, and restore Keowee main step-up transformer to operable status in 25 days.

A note for Condition K states that TS 3.7.0 is not.applicable when both standby buses are energized by an operable Lee gas turbine. Conditions J and K were initially proposed as one condition with required actions, completion times, and notes. This condition was a Keowee hydro unit or Keowee main step-up transformer inoperable for greater than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . For this single condition, the staff expressed concern regarding the note permitting an operable Keowee unit to be made inoperable for a period of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months inorder to make both Keowee units operable. Regarding this issue, the licensee was requested to provide a technical discussion including detailed explanations of why this action may be necessary. The response to this request was that when one Keowee unit has been removed from service to perform turbine and generator maintenance, it is necessary to make the other Keowee unit inoperable due to the sharing of the intake structure and a common penstock. In order to perform turbine and generator maintenance on a Keowee unit, a plug must be installed at the inlet penstock for that Keowee unit. This is performed by closing the intake gate and dewatering both Keowee units.

After dewatering, a plug is installed at the inlet of the penstock for the Keowee unit that is to undergo maintenance. The inlake gate is then opened, which restores the Keowee unit that is not in a turbine/generator maintenance outage to service. When restoring the inoperable Keowee unit to service from a maintenance outage, it is necessary to perform the same dewatering evolution again. This activity requires approximately 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to complete and makes both Keowee units inoperable while it is being performed. To accomplish this, the licensee modified the note to change the 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months in the revised TS submittal and noted that the allowed time change was due to a planned modification for the Keowee penstocks. This planned modification -ofthe Keowee penstock will allow the insertion of a bulkhead into the penstock of a Keowee unit after both Keowee units are dewatered. Once the bulkhead is inserted, the penstock for the Keowee unit, which is not being inspected, is refilled with water. The insertion of the bulkhead will allow for inspection of the penstock and the exterior of the turbine on the dewatered Keowee unit. In response to this change, the staff requested additional detailed information as to why the longer period of time is necessary and why this planned Keowee penstock modification is not viewed as an unreviewed safety question. The licensee's response to this request is that the planned Keowee penstock isolation modification is currently inthe conceptual design phase and that a safety evaluation has not been performed for the modification to determine if an unreviewed safety question

-14 exists. In addition, in the revised TS submittal provided by letter dated May 7, 1998, the licensee revised the TS note and associated TS Bases to allow 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for inoperability of both Keowee hydro units in order to restore a Keowee hydro unit from an extended outage.

The licensee also noted that this change is planned to be submitted in the Oconee ITS. During the design and implementation of the planned Keowee penstock isolation modification, a TS amendment or unreviewed safety question subnittal would be provided. These actions resolved the concern for this amendment.

The staff expressed an additional concern for the initially proposed condition of a Keowee hydro unit or Keowee main step-up transformer inoperable for greater than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This concern noted that the current TS permit a Keowee unit to be inoperable for greater than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months only once in a 3-year period without prior NRC approval. Both the current and initially proposed TS require that inoperability of each Keowee unit in excess of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is not to exceed 45 days in a 3-year period. However, the initially proposed TS condition removed the requirement that a Keowee unit is to be made inoperable for greater than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months only once in a 3-year period without prior NRC approval. Thus, this permitted a Keowee unit to be inoperable for greater than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months more than once in a 3-year period without prior NRC approval provided the 45 days are not exceeded. In discussing this issue with the licensee, the staff suggested that the current TS requirement should be retained or additional information containing technical justifications for its removal provided. Inthe revised TS submittal, the licensee revised the initial proposal such that Condition J does not permit a Keowee unit to be inoperable for greater than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months more than once in a 3-year period. In addition, in the revised TS submittal, the licensee changed the previously proposed 45-day completion time to 42 days. The guidelines for the STS require the addition of the completion times when moving from one condition to another condition. Proposed Condition C allows 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months for an outage of the overhead emergency power path and as such, the 45 days were reduced to 42 days. These actions resulted in requirements that are consistent with current TS and STS requirements and also resolved the concern.

The initially proposed condition of a Keowee hydro unit or Keowee main step-up transformer being inoperable for greater than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months also did not contain the current TS requirement that the remaining Keowee hydro unit be available to the overhead transmission line if one of the two Keowee hydro units is expected to be unavailable for longer than the test or maintenance period of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . Regarding this issue, the licensee was requested to explain how the current TS requirement was determined to be unnecessary. The licensee's response to this request was that the requirement for the operable Keowee unit to be aligned to the underground and available to the overhead means successive LCOs must be entered into when a Keowee unit is inoperable for maintenance for more than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and the Keowee main step-up transformer needs to be taken out of service for maintenance. With one Keowee unit in an extended outage, this is viewed to be the best time to do major work on other overhead power path components. These activities cannot be performed simultaneously under the current TS. In addition, the licensee's response noted that the scenario for needing the overhead path would require an emergency start event, a loss of offsite power, failure of the Lee combustion turbine power path, and the underground power path excluding the Keowee unit. This scenario is viewed as one that goes beyond the single failure criterion. Further, the probabilistic risk assessment of loss of offsite power events indicates the risk of core damage from a loss of offsite power event during a 72-hour period is approximately 3.OE-08, assuming normal

-15 availability of the Keowee overhead and underground path components. With the overhead path and an associated Keowee unit inoperable, the increase in risk is approximately 3.OE-08.

These results can be compared to a nominal risk of core damage of approximately 1.OE-04 per reactor year considering all accident initiators. Inthis regard, the proposed 72-hour inoperability time period seems reasonable. However, regarding the initially proposed TS requirement, the staff continued to express concern since a Keowee unit is allowed to be inoperable for greater than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months simultaneously with the removal of an emergency power path from service. Inthe revised TS submittal, the licensee changed the specification to require the overhead emergency power path to be operable during an extended outage of a Keowee unit. This change resulted in the proposed TS requirement being consistent with the current TS requirement and resolved the concern.

For the initially proposed condition of a Keowee hydro unit or Keowee main step-up transformer inoperable for greater than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , the staff expressed an additional concern regarding the 28-day AOT to restore the inoperable Keowee main step-up transformer. While this is consistent with the current TS, the licensee was requested to provide additional bases for this length of time. The licensee's response for this request was that in order to replace the Keowee main step-up transformer, the Jocassee main step-up transformer will be transported to Keowee and installed as the replacement transformer. The necessary modification to perform this replacement is ready to use if the need arises. Current estimates for O implementation of the modification indicate that 28 days would allow a reasonable period of time for the installation and testing of the replacement transformer. However, Condition K of the revised TS submittal changes the 28-day completion time to 25 days. This change is due to the STS guidelines that require the addition of the completion times when moving from one condition to another condition. In view of the STS guideline requirement, and since the overhead power path has a 3-day completion time, the 28-day completion time was revised to 25 days. For the transformer AOT issue, the licensee's response resolved the concern. The change in required completion time is consistent with requirements in the STS guidelines and is satisfactory.

Condition L of this proposed TS section is one trip circuit in one or both closed N breakers inoperable or one trip circuit in one or both closed SL breakers inoperable. For this condition, the required action and completion time is to restore each trip circuit to operable status in 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The staff expressed concern that this condition was not related to the limiting conditions of operation for proposed TS Section 3.7.1. Further, the staff noted that the STS guidelines require the conditions to be related to the LCOs. In response to this concern, the licensee noted that the N breaker trip circuit operability requirements are tied to the overhead and underground emergency power path requirements. The N breaker trip circuit must be operable for the Oconee unit to be able to align to the overhead or underground emergency power paths. The SL breaker trip circuit operability requirements are tied to the underground emergency power path requirements. The SL breaker trip circuit must be operable for the Oconee unit to be able to align to the underground emergency power path. In addition, the licensee revised the Bases for TS Section 3.7.1 to clearly define that the N breaker trip circuits are related to the overhead emergency power path and that the N and SL breaker trip circuits are related to the underground emergency power path. The licensee's response and the revisions to the Bases for TS Section 3.7.1 resolved the concern.

-16 Condition.M of this proposed TS section addresses required actions and associated completion times when Conditions C, F, G, H, I, J, K, or L are not met. For this condition, required actions and completion times require the unit to be in hot shutdown in 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and cold shutdown in 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months . These required actions and associated completion times are consistent with those in the current TS and the shutdown path for proposed TS Section 3.7.

4.2.4 Proposed Surveillance Requirements (SRs)

The proposed TS Section 3.7.1 contains 18 SRs. SR 3.7.1.1 provides surveillances for the Keowee batteries. These include weekly verifying battery float voltage is> 125 Vdc, annually verifying battery capacity is adequate to supply and maintain in operable status the required emergency loads for the design duty cycle by performing a battery service test, annually verifying cells and end cell plates along with battery racks show no visual indication of structural damage or degradation, and annually verifying cell to cell and terminal connections are clean/tight, and coated with anti-corrosion grease.

SR 3.7.1.2 requires verifying monthly that each Keowee hydro unit starts automatically and energizes the underground emergency power path. SR 3.7.1.2 has two notes. One of these notes is that energizing standby buses is not required to be performed when the standby buses are energized by an operable Lee gas turbine. The other note is that the surveillance is not required to be met for the Keowee hydro unit associated with the overhead emergency power path when the overhead electrical disconnects for the Keowee hydro unit associated with the underground emergency power path are open.

SR 3.7.1.3 requires verifying monthly that each Keowee hydro unit starts automatically and synchronizes to the yellow bus in the 230 kv switchyard. A note indicates that the surveillance is only required to be met for the Keowee hydro unit associated with the overhead emergency power path.

SR 3.7.1.4 requires verifying monthly that the hydro unit associated with the underground emergency power path starts automatically and energizes the underground emergency power path. SR 3.7.1.4 has two notes. One of these notes states that SR 3.7.1.2 may be performed in lieu of SR 3.7.1.4. The other note states that energizing standby buses is not required to be performed when standby buses are energized by an operable Lee gas turbine.

SR 3.7.1.5 requires verifying monthly that the hydro unit associated with overhead emergency power path starts automatically and synchronizes with yellow bus in 230 kv switchyard. A note for SR 3.7.1.5 states that SR 3.7.1.3 may be performed in lieu of SR 3.7.1.5.

SR 3.7.1.6 requires verifying monthly each N and SL breaker opens on an actual or simulated actuation signal. Two notes are related to this surveillance. One note states that the surveillance is only required to be met when the associated breaker is closed and the other note states that the surveillance is not required to be performed for SL breakers when overhead emergency power path is inoperable > 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

-17 SR 3.7.1.7 requires verifying monthly that the S and E breakers are operable by full cycling. A note states that the surveillance is not required to be performed for S breakers when the overhead emergency power path is inoperable > 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

SR 3.7.1.8 requires verifying annually the operability of the underground feeder breaker interlock and the underground to overhead ACB (Air Circuit Breaker) interlock.

SR 3.7.1.9 requires verifying annually that the dedicated 100 kv line is operable by energizing both standby buses using a Lee gas turbine. A note states that this surveillance is only required to be performed when a Lee gas turbine is energizing the standby buses.

SR 3.7.1.10 requires verifying annually that a Lee gas turbine can be started, placed on the system grid, and supply the equivalent of a single unit's maximum safeguard loads and two unit's hot shutdown loads on the system. A note states that this surveillance is only required to be performed when a Lee gas turbine is energizing the standby buses.

SR 3.7.1.11 requires verifying annually that each hydro unit can emergency start from each control room, attain rated speed and voltage within 23 seconds of an emergency start initiate signal, and be synchronized to the grid and loaded at the maximum practical rate to a value

. equivalent to one unit's safeguard loads plus two unit's hot shutdown loads.

SR 3.7.1.12 requires verifying annually the ability of the unit ACBs to close automatically to the underground path. A note for SR 3.7.1.12 states that the surveillance is not required to be performed when the overhead electrical disconnects for the hydro unit associated with the underground emergency power path are open.

SR 3.7.1.13 requires verifying on an 18-month frequency that a Lee gas turbine can be started and connected to the isolated 100 kv dedicated line and carry the equivalent of a single unit's maximum safeguard loads within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . A note states that this surveillance is only required to be performed when a Lee gas turbine is energizing the standby buses.

SR 3.7.1.14 requires performing on an 18-month frequency an automatic transfer of the main feeder buses to the startup transformer, standby buses, and retransfer to the startup transformers.

SR 3.7.1.15 requires verifying, on an 18-month frequency, the ability of the hydro units to supply emergency power from the initial condition of commercial power generation. A note states that this surveillance is only required to be performed during periods of commercial power generation using the hydro units.

SR 3.7.1.16 requires verifying on an 18-month frequency that the hydro units load rejection response is bounded by the design criteria used to develop the operating restrictions. A note for SR 3.7.1.16 states that the surveillance is only required to be performed during periods of commercial power generation using the hydro units.

SR 3.7.17 requires verifying on an 18-month frequency that each N and SL breaker opens on an actual or simulated actuation signal to each breaker trip circuit. Two notes are associated

- 18 with SR 3.7.1.17. One note states that the surveillance is only required to be performed when an associated breaker is closed. The other note states that the surveillance is not required to be performed for SL breakers when the overhead emergency power path is inoperable

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

SR 3.7.1.18 requires verifying on an 18-month frequency that each 230 kv switchyard circuit breaker actuates to the correct position on an actual or simulated switchyard isolation actuation signal. A note with SR 3.7.1.18 states that redundant breaker trip coils may be verified on a staggered test basis.

The current TS SRs require monthly verification that each hydro unit can be synchronized through the 230 kv overhead circuit to the startup transformers and can energize the 13.8 kv underground feeder. As initially proposed, TS SRs 3.7.1.2 and 3.7.1.3 required monthly verification that the hydro unit preselected for the underground power path can energize this path and both standby buses and that the hydro unit preselected for the overhead power path can be synchronized with the switchyard yellow bus. The licensee was requested to provide a discussion including technical bases for justifying why it is no longer considered necessary to verify monthly that each hydro unit can be synchronized to the overhead power path and that each unit can energize the underground power path. The licensee's response to this request was that the current TS SRs for the units require that one unit be tested to the overhead path and the other unit tested to the underground path. After completion of this part of the test, the breaker connecting the unit to the underground path will be manually opened. The interlock between the underground breakers will then allow the underground breaker to the unit that had just been tested to the overhead path be manually closed. The auxiliaries will have to be aligned so that they are powered by the appropriate unit. At this point, the test will be repeated for the new alignment of the units.

The first part of the test proves the operability of the overhead path and the underground path with that particular alignment of the units. Once this part of the test has been completed, the emergency power paths are operable until the existing alignment of the units to the overhead and underground power paths is changed. The initially proposed monthly tests of the emergency power paths verify the operability of the unit to its preselected emergency power path. Verification that an individual Keowee unit can meet the surveillance requirement for both emergency power paths is not specified, as this function is not required for emergency power path operability. However, the staff continued to express concem since the initially proposed SRs did not require verifying each Keowee hydro unit could meet the surveillance for both emergency power paths and did not appear to be consistent with design requirements for the zone overlap protective control circuitry. This circuitry is designed to automatically realign the preselect overhead power path Keowee unit to the underground power path if a fault occurs at a location in the overhead power path circuit within the protective circuitry overlap zone of the Keowee unit selected for the underground power path. This circuitry is required to be operable if the overhead power path circuit disconnects are closed for the Keowee unit selected for the underground power path. In the revised TS submittal, the licensee revised the initially proposed SRs to the proposed SRs 3.7.1.2, 3.7.1.3, 3.7.1.4, and 3.7.1.5 (provided above). These surveillances required demonstrating the operability of each Keowee unit with its aligned power path. These surveillances also required demonstrating the operability of each Keowee unit with the underground power path if the overhead power path circuit disconnects are closed for the

-19 Keowee unit aligned to the underground power path. Further, these surveillances included provisions to demonstrate the operability of each Keowee unit to the overhead power path.

Thus, the licensee's response and the revised proposed SRs resolved the concern.

The surveillance that was initially proposed for SR 3.7.1.8 revised the current TS frequency for verifying the operability of the Keowee underground feeder breaker interlock and the underground to overhead breaker interlock from monthly to semiannually. As a result, the staff requested a discussion concerning the evaluation of previous test data and interlock design used to support this revision. The response by the licensee to this request was that past testing of the Keowee underground feeder breaker interlock and the underground to overhead breaker interlock did not identified any failures. During the past 5 years, the underground power path interlocks between ACBs 3 and 4 have not failed during any of the surveillances. In addition, the underground to overhead power path breaker interlocks have not failed during past surveillances. The reliability of the interlocks is due to their type and manufacturing. The control interlocks, which prevent one Keowee underground breaker from closing if the other breaker and associated disconnects are closed, use breaker and disconnect auxiliary "b" contacts. These contacts are part of the breaker and disconnects, which are both located within the Keowee breaker vault.

. The staff also noted that the initially proposed semiannual surveillance testing frequency for these interlocks was not consistent with the annual surveillance testing frequency required for those addressed inthe initially proposed surveillance for SR 3.7.1.12 and that similar ACB interlock circuitry would appear to require similar surveillance testing intervals. The licensee agreed that the two surveillance intervals should be identical. Inthe supplemental and revised TS submittals, the initially proposed surveillance testing frequency for proposed TS 3.7.1.8 was changed from semiannually to annually. In addition, proposed SR 3.7.1.12 had been previously proposed in a licensee submittal that used the current TS format. The staffs Safety Evaluation (SE) for this previously proposed TS SR is contained in License Amendment Nos. 210, 210, and 207 that were issued on August 15, 1995. This evaluation, in conjunction with the preceding response, resolved the concern.

The staff further noted that the SRs for proposed TS Section 3.7.1 do not include an SE for the revised Keowee Auxiliary Bus Transfer design scheme, which transfers Keowee auxiliary buses 1X and 2X between normal and alternate power sources. In addition, the NRC Augmented Inspection Team report dated November 27, 1992, indicated that the periodic testing performed for the undervoltage relays and transfer timers associated with Keowee auxiliary bus feeder ACBs 5, 6, 7, and 8 does not include verification of time delays. As a result, the licensee was requested to provide a technical basis explaining why verification of time delays associated with these ACBs in the revised Keowee Auxiliary Bus Transfer design scheme is not considered necessary. The licensee's response to this request was that the proposed TS require a surveillance that removes power from the main feeder buses to verify that Keowee starts and operates correctly. During this testing, the auxiliary equipment is required to function properly, thus any malfunctions in the auxiliaries would be discovered. The response also noted that since the Keowee units are designed to start and run for greater than 30 minutes without ac power to the auxiliaries, credit is taken for operator action to ensure that power is restored to the Keowee auxiliaries after a design basis event. The operators have procedural guidance to take manual control of ACBs 5, 6, 7, and 8 and align the Keowee auxiliaries to an operable

p power source. An operable power source for the Keowee auxiliaries is required by both the current and proposed TS. In addition, the revised design for the automatic transfer scheme is considered to be an enhancement and is to be tested periodically and maintained quality assurance group 1 (QA-1). However, no credit is taken for the system for Keowee operability.

This response resolved the concern.

An additional concern identified by the staff related to the initially proposed surveillances for proposed SRs 3.7.1.7, 3.7.1.9, 3.7.1.10, and 3.7.1.13. The initially proposed SRs replaced three current TS SRs. Current TS SR 4.6.6 requires demonstrating annually, and prior to planned extended Keowee outages, that a Lee station combustion turbine can be started and connected to an isolated 100 kv line and supply power to the main feeder buses (MFBs).

Current TS SR 4.6.7 requires demonstrating every 18 months that a Lee station combustion turbine can be started and connected to the isolated 100 kv line and will carry the equivalent of the maximum safeguard load of one ONS unit (4.8 MVA) within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . Current TS SR 4.6.8 requires demonstrating annually that a Lee station combustion turbine can be started and will carry the equivalent of the maximum safeguards load of one Oconee unit plus the safe shutdown loads of two Oconee units on the system grid. As initially proposed, the TS SRs did not retain the current TS SRs in that they did not require that a Lee station turbine be started and connected to the isolated 100 kv line and carry the equivalent of the maximum safeguards load of one Oconee unit (4.8 MVA) within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . Thus, for the isolated 100 kv line, the initially proposed SRs did not require the manner of verification that is required by the current TS or a manner of operation similar to that likely required if needed. The licensee's response for this concern was that the existing TS SR 4.6.6 had been replaced with an initially proposed SR 3.7.1.6 that did not require connection to the MFBs. The response also noted that monthly surveillance testing of the S breakers that connect the standby buses and MFBs, assures that voltage can be provided from the standby buses to the MFBs during an emergency. In a supplemental TS submittal, a revised SR 3.7.1.10 was submitted to demonstrate that a Lee gas turbine can be started, connected to the isolated 100 kv line, and carry the equivalent of a single ONS unit's maximum safeguard loads. This SR is consistent with the current TS SRs for a Lee gas turbine except the 1-hour requirement was deleted. For this exception, the licensee's response noted that the 1-hour requirement of starting a Lee gas turbine and supplying power to Oconee by way of the dedicated line can be demonstrated by energizing the standby buses instead of the MFBs. In addition, this exception is viewed to be necessary by the licensee in order to reduce operator burden while performing the Lee gas turbine test. During the Lee gas turbine test, approximately 30 minutes are required to allow the Lee gas turbine to. reach speed.

As a result, the ONS operators are left with only 30 minutes to connect the Lee gas turbine power path to the ONS MFBs and obtain the required equivalent loading.

However, the staff continued to express concern that the proposed TS SRs did not require a Lee station turbine to be started, connected to the isolated 100 kv line, and loaded to the equivalent of one Oconee unit safeguard load within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or verification of the isolated Lee power path in a manner similar to that likely to be necessary if needed. In discussing this issue further with the licensee, the staff requested additional documentation containing information that supported how the revised proposed TS SRs are equivalent to the current TS SRs.

However, during this discussion, the staff noted that such supporting information is very difficult to provide in view of the above exception. In a revised submittal, the licensee provided proposed changes to SRs 3.7.1.9, 3.7.1.10, and 3.7.1.13. These surveillances now require that

-21 a Lee turbine be started, connected to the isolated 100 kv line, and carry the equivalent of the maximum safeguards load of one Oconee unit within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . These revised proposed SRs resolved the concern.

While reviewing licensing documents containing design information, the staff also noted that in order to establish electrical power to the MFBs,-proper operation of various and numerous electrical control circuit components (such as, relays, interconnecting wiring, potential transformers, and control power supplies) is required. The licensee was, therefore, requested to provide the results of reviews performed to assure that the proposed SRs result in operating the control devices in a manner equal to or similar to that which they are expected to operate for emergency situations. The licensee's response to this request was that a review of the design requirements and associated testing has been performed through the design basis document (DBD) effort. This effort was performed to ensure that all of the design requirements and the applicable TS surveillances were properly tested. The emergency power system devices and circuitry are tested in a manner similar to those that would exist during emergency conditions. Documentation supporting this conclusion is included in the test table of each DBD.

This response adequately addresses the concern.

Proposed SRs 3.7.1.15 and 3.7.1.16 were previously proposed in a licensee submittal that used the current TS format. The staffs SE for these SRs is contained in'License Amendment Nos.

222, 222, and 219 that were issued on March 20, 1997.

Proposed SR 3.7.1.18 did not require verifying redundant breaker trip coils on a staggered test basis, although it permitted such staggered testing. Because of this concern, the staff requested that the licensee provide a discussion of the technical basis for not requiring staggered testing of these trip coils, or revise the surveillance requirement to require staggered testing of the trip coils. In response, the licensee revised the SR by letter dated May 7, 1998, by adding a note stating that redundant breaker trip coils will be verified on a staggered test basis. This action resolved the concern.

The staff found that the proposed TS submittal did not include voltage and frequency surveillance testing acceptance criteria for the Keowee or Lee emergency power sources. The STS include specific voltage and frequency surveillance testing acceptance criteria for the emergency power sources. Therefore, the staff requested that the licensee revise the proposed TS to include specific surveillance testing acceptance criteria for the Keowee and Lee emergency power sources. The licensee's response to this concern was that the proposed SRs for Keowee and Lee are consistent with the current TS requirements, which do not include the voltage and frequency testing acceptance criteria. However, the testing acceptance criteria have been included in the ITS submittal in accordance with the STS requirements. This response resolved the concern.

The remaining TS SRs for the proposed TS Section 3.7.1 are consistent with design requirements and the SRs in the current TS.

p 4.3 TS 3.7.2, "Distribution Systems - Operating" 4.3.1 Background The distribution systems are comprised of two alternating current (ac) MFBs, three Engineered Safeguards (ES) ac power system strings, four125 Vdc vital Instrumentation & Control (I&C) power panelboards, six 230 kv switchyard dc power panelboards, and four 120 Vac vital Instrumentation power panelboards. These systems, which supply the electrical power required to operate unit equipment during normal plant operation, are designed to provide power to the required ESF loads or safe shutdown loads of each unit such that no single failure can disable enough loads to jeopardize plant safety. Only one MFB and two ES power system strings are needed to provide power to the minimum required loads.

The two MFBs are arranged such that each ES power system string can receive power from either of the two buses. Each MFB, which is capable of supplying the entire unit power needs, can receive power from the unit normal auxiliary transformer, startup transformer, and one of the standby buses.

The 125 Vdc vital l&C system includes a 125 Vdc distribution system. This system provides control power for the emergency power system. It also supplies both motive and control power to selected safety-related and nonsafety equipment. It is designed to have sufficient independence, redundancy, and testability to perform its safety functions assuming a single failure.

Four separate 125 Vdc vital I&C panelboards (DIA, DIB, DIC, DID) are provided for each unit.

Each panelboard receives its dc power through an auctioneering network of two isolating diode assemblies. One assembly is supplied from the unit's 125 Vdc distribution system, and the other assembly is supplied from another unit's (the backup unit) 125 Vdc vital distribution system. The diode assemblies permit the two distribution systems to supply current to the vital I&C dc panelboard connected to the output of the diode assemblies, and block the flow of current from one dc distribution system to the other.

In order to provide all safety functions required during an accident, power must be provided from any three of the four vital l&C dc panelboards. During normal operation, the auctioneering network (described above) provides multiple redundancy for assuring that power from the 125 Vdc vital l&C sources would be provided to the vital l&C dc panelboards. Power from any three of the four vital l&C dc sources for a particular unit (two for the unit considered, and two from the backup unit) continues to provide redundancy of power sources for safety functions performed by the vital dc I&C panelboards.

Unit 1 panelboards 1DIC and 1DID provide primary and backup power for SK and SL breakers control power, standby bus protective relaying control power, standby breakers control power for all three units, and retransfer to startup source switching circuits for all three Oconee unit EPSL systems. All other safety-related functions supported by the vital 125 Vdc panelboards are unit-specific.

The 230 kv switchyard, 125 Vdc system includes a 125 Vdc distribution system. This system provides primary and backup direct current power for protective relaying and actuation circuits associated with the 230 kv SY and 230 kv SY power circuit breaker (PCB) operation. It is

-23 designed to have sufficient independence, redundancy, and testability to perform its safety functions, assuming a single failure. Safety functions provided by the 230 kv switchyard 125 Vdc system include (1) connection of onsite power from Keowee to ONS by way of the emergency onsite overhead power path, and (2) isolation of ONS (including Keowee) from degraded grid voltage through action of the degraded grid voltage protection system. With the exception of the functions of the degraded grid protection system, all functions of the 230 kv switchyard direct current sources and distribution system can be considered redundant to those associated with the emergency onsite underground power path.

The outputs of the 230 kv switchyard (SY) dc sources, identified as SY-1 and SY-2, are connected to distribution centers identified as SY-DC-1 and SY-DC-2, respectively. The buses are metal-clad two-conductor assemblies. A bus tie with normally open breakers is provided between the distribution centers to backup a battery when it is removed for servicing. SY-DC-1 supplies DC panelboards identified as DYA, DYB, DYC, and DYD and SY-DC-2 supplies dc panelboards identified as DYE, DYF, DYG, and DYH. Direct current panelboards identified as DYD and DYH provide power for nonsafety functions. The two distribution centers with their associated safety-related direct current panelboards and interconnecting wiring and breakers comprise the 230 kv SY distribution system.

The two distribution centers are redundant, with each providing power to all components necessary for performing the safety functions of the 230 kv SY dc system. The dc panelboard identified as DYA is redundant to DYE, DYB is redundant to DYF, and DYC is redundant to DYG. Redundant panelboards supply power to separate channels of the degraded grid protection system circuits, separate channels of other protective relaying circuits, and separate feeds for each 230 kv switchyard PCB closing and tripping control circuitry. These PCBs are provided with separate dual trip coils. Isolating diodes are provided for redundant power feeds to each PCB's common closing coil circuit.

The ac vital distribution system consists of four redundant 120 Vac vital instrument power panelboards for each unit that provide power to associated vital I&C loads under all operating conditions. Each panelboard is powered separately from a static inverter connected to one of the four 125 Vdc instrumentation and control panelboards. In order to accommodate maintenance on the inverters and supply backup power, a tie line with breakers is provided to each of the 120 Vac vital panelboards from the alternate 120 Vac regulated bus.

Each of the four redundant channels of nuclear instrumentation and reactor protective system equipment on each unit is powered from a separate 120 Vac vital panelboard. Separate 120 Vac panelboards also supply each of the three redundant engineered safeguards system analog channels and each of the two redundant engineered safeguards digital channels for each unit.

-24 4.3.2 Proposed TS Changes The LCO for the proposed TS Section 3.7.2 requires the distribution systems to be OPERABLE as follows: (1)two energized MFBs each connected to two or more ES power system strings; (2)three energized ES power system strings; (3)four 125 Vdc vital I&C power panelboards; (4) for Units 2 or 3, 125 Vdc vital I&C power panelboards 1DIC and 1DID; (5) 230 kv switchyard dc power panelboards DYA, DYB, DYC, DYE, DYF, and DYG; and (6)four 120 Vac vital Instrumentation power panelboards. This LCO is consistent with those in the current TS.

Proposed TS Section 3.7.2 provides seven conditions addressing inoperability of equipment items. This section also provides another condition that addresses not meeting the required actions and associated completion times identified for the seven conditions addressing inoperability of equipment items.

4.3.3 Conditions Condition A of proposed TS Section 3.7.2 addresses one MFB being inoperable. For this condition, the required action with completion time is to restore the MFB to operable status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . Condition B is one ES power system string inoperable. The required action with completion time for this condition is to restore the ES power system string to operable status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . Condition C is one 125 Vdc vital I&C power panelboard inoperable. For Condition C, the required action with completion time is to restore 125 Vdc vital l&C power panelboard to operable status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .' Conditions A, B, and C of this proposed TS section provide requirements that are consistent with those provided in the current TS.

Condition D addresses one or more required 230 kv switchyard dc power panelboards being inoperable. For this condition, the required action with completion time is to restore required 230 kv switchyard dc power panelboards to operable status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . A note states that separate condition entry is allowed for each 230 kv switchyard dc power panelboard.

During its review, the staff requested that the licensee provide additional information describing how the initially proposed condition is consistent with the current TS that only allows inoperable components in one string. The licensee's response to this request was that the current TS allow a complete single string or single component of the 125 Vdc and 230 kv switching station to be inoperable. This could consist of an inoperable battery, charger, distribution center, and all associated panelboards. In this condition, the redundant function of the other string is relied on to provide the safety function of the system. The Bases section of the proposed TS identifies the redundant panelboards. Under the current TS, dc panelboards DYA, DYB, and DYC can be inoperable at the same time since they are in the same string and are not redundant to each other. The accident analysis acceptance criteria can be met with panelboards from both distribution centers inoperable provided that redundant panelboards are not inoperable. For example, simultaneous inoperability of panelboard DYA and DYF is acceptable since the required safety functions are supplied from other panelboards and would be powered. However, simultaneous inoperability of DYA and DYE is prohibited since these panelboards support redundant safety-related loads. Thus, restrictions on panelboard operability have been retained consistent with the single failure criteria. This response satisfactorily addressed the request.

-25 Condition E of proposed TS Section 3.7.2 addresses the need for one 125 Vdc vital I&C power panelboard for LCO 3.7.2.4 (For Units 2 or 3, 125 Vdc vital I&C power panelboard 1DIC and 1DID inoperable). The required action with completion time for Condition E is to restore 125 Vdc vital I&C power panelboards 1DIC and 1DID to operable status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . A note provided for Condition E states that Condition E is not applicable to Unit 1.

Condition F addresses KVIA or KVIB 120 Vac vital Instrumentation power panelboard inoperable. For this condition, the required action with completion time is to restore 120 Vac vital Instrumentation power panelboard to operable status within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

Condition G addresses the condition when KVIC or KVID 120 Vac vital Instrumentation power panelboard is inoperable. The required action with completion time for this condition is to restore 120 Vac vital Instrumentation power panelboard to operable status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

Condition H addresses required actions and associated completion times when Conditions A through G are not met. For Condition H,the required actions with completion times are to be in hot shutdown within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to be in cold shutdown within 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months . Conditions D through G of this proposed TS section provide requirements that are consistent with those contained in the current TS. Condition H provides a unit shutdown path that is consistent with the one

. provided in the current and proposed TS.

Condition I of this proposed TS section addresses conditions where two or more MFBs, ES power system strings, 125 Vdc vital I&C power panelboards, or 120 Vac vital Instrumentation power panelboards are inoperable; or 230 kv switchyard dc power panelboards DYA and DYE are inoperable; or 230 kv switchyard dc power panelboards DYB and DYF are inoperable; or 230 kv switchyard dc power panelboards DYC and DYG are inoperable. Required action with completion time for Condition I is to enter TS 3.0.

4.3.4 Proposed Surveillance Requirements Proposed TS Section 3.7.2 contains two SRs. SR 3.7.2.1 requires verifying correct breaker alignments and voltage to required MFBs on a frequency of 7 days. This SR verifies that the MFBs are functioning properly, with the required circuit breakers closed and the buses energized. The 7-day frequency considers the redundant capability of the MFBs and other indications available in the control room that are to alert the operator to system malfunctions.

SR 3.7.2.2 requires verifying correct breaker alignments and voltage availability to required ES power system strings, 125 Vdc vital I&C power panelboards, 230 kv switchyard dc power panelboards, and 120 Vac vital Instrumentation power panelboards on a frequency of 7 days.

This surveillance is to verify that the required ES power system strings, 125 Vdc vital l&C power panelboards, 230 kv switchyard dc power panelboards, and 120 Vac vital Instrumentation power panelboards are functioning properly with the required circuit breakers closed and the buses energized. The 7-day frequency considers the redundant capability of the required ES power strings and power panelboards and other indications available in the control room to alert the operator to system malfunctions.

These surveillances provide requirements that are consistent with those in the STS.

p 4.4 TS 3.7.3, "Emergency Power Switching Logic (EPSL) Automatic Transfer Functions" 4.4.1 Background The transfer circuits of the EPSL are designed with sufficient redundancy to assure that power is supplied to the unit MFBs and hence to the unit essential loads under accident conditions.

The logic system monitors the normal and emergency power sources and upon loss of the normal power source (the unit auxiliary transformer), the logic seeks an alternate source of power. The EPSL automatic transfer functions consist of the load shed, transfer to standby, and retransfer to startup logic circuitry.

The. load shed and transfer to standby circuits are designed to energize the MFBs from the standby buses powered from either a Keowee or Lee turbine generator. This is designed to occur when voltage from the normal or startup sources is lost or is too low. The load shed signal is provided to separate nonessential loads from the MFBs to ensure that the CT-4 or CT 5 transformers supplying the standby buses are not overloaded.

Retransfer to the startup logic provides the EPSL with the capability to retransfer essential loads from the standby bus to the startup source, if available, should power to the standby bus be lost for more than 5 seconds. The retransfer to startup function is provided to ensure that a single failure, associated with the standby sources, does not cause the MFBs to remain deenergized.

The EPSL transfer functions are designed to perform their function assuming a worst case credible single failure. There are two independent EPSL automatic transfer channels. Each of these channels consists of load shed and transfer to standby and retransfer to startup control logic circuitry and is capable of performing the entire transfer function.

4.4.2 Proposed TS Changes The LCO for this proposed TS section requires that two channels of the EPSL automatic transfer function be OPERABLE.

4.4.3 Conditions Proposed TS Section 3.7.3 contains two conditions. Condition A addresses requirements when one channel is inoperable. For this condition, the required action with completion time is to restore channel to operable status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . Condition B specifies required actions and associated completion times when Condition A is not met. For Condition B, the required actions and completion times are to be in hot shutdown within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to be in cold shutdown within 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months . This proposed TS section provides requirements that are consistent with those contained in the current TS excluding the issues identified and addressed below.

The current TS address the EPSL with eight functional units. These functional units are identified as normal source voltage sensing circuits (one per phase), startup source voltage sensing circuits (one per phase), standby bus voltage sensing circuits (one per phase on each bus), MFB undervoltage relays (three per bus), load shed and transfer to standby circuits

-27 (Channels A and B), Keowee emergency start circuit (Channels A and B), retransfer to startup circuits (Channels A and B), and normal source breakers N1 and N2'control circuitry. Seven of the eight functional units are addressed in the proposed TS Sections 3.7.3, 3.7.4, and 3.7.5.

The N breaker control circuits are addressed in Condition L of proposed TS Section 3.7.1.

Proposed TS Section 3.7.3 addresses three of the eight functional units. These three are the MFB undervoltage relays, load shed and transfer to standby circuits, and retransfer to startup circuits.

During its review, the staff noted a concern involving multiple simultaneous degradation of EPSL functional units. The current TS permit the circuits or channels of any single EPSL functional unit (one of eight) to be inoperable for test or maintenance for a period of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months provided that all other EPSL functional units (remaining seven) are operable, unless inoperability is due to loss of 125 Vdc power. The proposed TS section was not consistent with this since it allowed one channel of one or more circuits to be inoperable regardless of cause.

Thus, the proposed TS permit multiple simultaneous degradation of EPSL functional units. This concern also applies to proposed TS Sections 3.7.4 and 3.7.5. In discussing this issue with the licensee, the staff requested documentation containing information that demonstrates multiple simultaneous degradation of EPSL functions do not result in additional loss/degradation of any single safety function and/or action. The licensee's response to this request was that the restrictions on inoperability of more than one EPSL functional unit have been retained where necessary to satisfy the single failure criterion. The EPSL functional units inTable 3.7-1 of the current TS have been grouped by function and logic dependency in proposed TS Sections 3.7.3 through 3.7.5. These EPSL functional groups separate the functions that are not dependent on the other EPSL functions such that the safety actions/functions are maintained. This response resolved the concern.

4.4.4 Proposed Surveillance Requirement Proposed TS Section 3.7.3 contains one SR. SR 3.7.3.1 requires performing SR 3.7.1.14 (EPSL automatic transfer) on an 18-month frequency. The proposed SR 3.7.3.1 is consistent with the SR contained in the current TS. In addition, this surveillance requires verification of the retransfer to startup logic, which is not required in the current TS. SR 3.7.1.14 addresses performance of a functional verification of the source and MFB voltage sensing Keowee emergency start, load shed and transfer to standby, and retransfer to startup logic of the EPSL system. The testing method for this surveillance is designed to provide actual power failures remote from the MFBs so that the logic may be monitored. For SR purposes, a failed source is defined as the complete loss of voltage. The ramp/rate/time responses for the voltage relays are verified independently as a prerequisite to SR 3.7.1.14. Circuits actuated by the source undervoltage relays are verified per SR 3.7.4.1. To eliminate human or computer error in timing events, critical time setpoints for load shed, transfer to standby, retransfer to startup, and reactor coolant pump trip relays are verified independently during the refueling outage. This test verifies the integrated response of the circuits. Key circuits for verification include the engineered safeguards contacts to the Keowee emergency start, load shed and transfer/retransfer relays, and close permissive for Keowee feeder breakers (SK breakers) to the standby buses. Excessive cycling of equipment may be prevented by using a single action input, verification of the required end result by alarms or visual inspection, subsequent reset of the initiating logic, and then insertion of an alternate input for verification of the required circuits.

p An 18-month frequency for this surveillance is based on operating experience and is to provide reliability verification without excessive cycling of equipment for testing.

4.5 TS 3.7.4, "Emergency Power Switching Logic (EPSL) Voltage Sensing Circuits" 4.5.1 Background The EPSL voltage sensing circuits consist of the voltage sensing circuits for the startup source, standby bus number 1, standby bus number 2, and the normal source. These voltage sensing circuits provide input to the EPSL power seeking logic to actuate breakers and initiate transfer logic sequences. Each phase of each source has an individual potential transformer feeding a two out of three logic for determining the status of the power source. The voltage sensing circuits also provide Class 1E trip signals to the breaker control circuitry for the N, E, and SL circuit breakers.

4.5.2 Proposed TS Changes The LCO for this TS section requires three channels for each of the following EPSL voltage sensing circuits to be OPERABLE: (1) Startup Source, (2)Standby Bus 1, (3) Standby Bus 2, and (4) Normal Source. A note states that if both N breakers are open, normal source voltage sensing is not required.

4.5.3 Conditions This proposed TS section contains two conditions. Condition A provides requirements for one channel of one or more circuits being inoperable. For this condition, the required action with completion time is to restore the channel to operable status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . Condition B contains the required actions and associated completion times if Condition A is not met. For Condition B, the required actions and completion times require the unit to be in hot shutdown within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in cold shutdown within 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months . The safety function of the normal source voltage sensing circuits provides a safety trip signal to the N breakers. Ifthe N breakers are opened, a note states that these circuits are not required to perform this safety function. This note states that a separate condition entry is allowed for each inoperable voltage sensing circuit. Thus, completion times are to be tracked separately for each power bus (normal, startup, standby bus number 1, standby bus number 2).

Proposed TS Section 3.7.3 addresses three of the eight EPSL functional units contained in the current TS, and proposed TS Section 3.7.4 addresses an additional three. The three addressed by proposed TS Section 3.7.4 are normal source voltage sensing circuits (one per phase), startup source voltage sensing circuits (one per phase), and standby bus voltage sensing circuits (one per phase on each bus). With the exception of the issue relating to multiple simultaneous degradation of EPSL functional units, which is addressed above for proposed TS Section 3.7.3, proposed TS Section 3.7.4 contains requirements that are consistent with those in the current TS.

-29 4.5.4 Proposed Surveillance Requirement Proposed TS Section 3.7.4 contains one SR. SR 3.7.4.1 requires performing a channel test on an 18-month frequency. The current TS do hot require a surveillance for the normal source voltage sensing circuits. Thus, this is an additional requirement that is not included in the current TS. Inaddition, SR 3.7.4.1 verifies operability of each sensing circuit of each bus, which can supply the MFBs. A circuit is defined as three channels, one for each phase. Each channel consists of all components from the sensing power transformer on the actual buswork through the circuit auxiliary relays that operate contacts in the EPSL logic and breaker trip circuits. Actual setpoint values for the undervoltage relays for the N and E breakers are to be verified independently as a prerequisite to this SR. Minimum requirements consist of individual channel relay operation causing appropriate contact responses within associated loadshed/breaker circuits, alarm activations, and proper indications for the sensing circuit control power status. The 18-month frequency for this SR considers operating experience and the need to remove the bus from service to perform the required testing.

4.6 TS 3.7.5, "Emergency Power Switching Logic (EPSL) Keowee Emergency Start Function" 4.6.1 Background

. The Keowee emergency start function of EPSL provides a start signal to the two onsite emergency power sources and sets up logic and relaying for their use inthe emergency mode.

There are two independent channels of the emergency start function. Each channel is capable of starting both Keowee units and activating the logic for operating in the emergency mode.

The Keowee emergency start function also disables noncritical protective interlocks and trips associated with the Keowee generators. This design feature is provided to aid to ensure that the generators remain available for emergency power despite minor failures or malfunctions.

Emergency start channels 1 and 2 are actuated from Engineered Safeguard channels 1 and 2 respectively. The emergency start channels can also be actuated manually from the Oconee control rooms or cable spread rooms. There are two independent channels associated with each Oconee unit and only one channel is required to perform the entire safety function. The channels include relays, contacts, and logic that are required to emergency start the Keowee units, bypass specific protective interlocks and trips, and circuitry that separates the Keowee units from the grid. Portions of the two channels affect the Oconee units individually.

4.6.2 Proposed TS Changes The LCO for proposed TS Section 3.7.5 requires two channels of the EPSL Keowee emergency start function to be OPERABLE.

4.6.3 Conditions This proposed TS section provides three conditions. Condition A addresses conditions when one channel is inoperable. The required action with completion time for Condition A require the channel be restored to operable status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . Condition B has the required actions and associated completion times for not meeting Condition A. For this condition, the required

-30 actions with associated completion times are that the unit be in hot shutdown within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to be in cold shutdown within 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months . Condition C requires two channels to be inoperable. For Condition C, the required action with the completion time requires that both Keowee hydro units be declared inoperable immediately for the affected ONS.

The current TS allow one channel of the Keowee emergency start function to be inoperable for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The proposed TS would allow one channel of this function to be inoperable for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . Therefore, the proposed TS are not consistent with the current TS.

However, a configuration with one channel of the Keowee emergency start function inoperable is potentially less significant than one inoperable emergency power path since the remaining operable channel could result in both emergency power paths being established; whereas, with one emergency power path inoperable (due to a reason other than a Keowee Unit), only one power path could be established. The AOT provided in the current and proposed TS for one inoperable emergency power path is 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . Thus, the proposed TS section revises the AOT for one inoperable channel of the Keowee emergency start function to be consistent with that for one emergency power path.

However, the staff expressed concern regarding the revised AOT for one channel of the emergency start function, since this could result in a longer period of time in which one channel is inoperable. The licensee was requested to provide additional information to justify the revised AOT. The licensee's response to this request was that the change in the AOT for the Keowee emergency start function provides AOTs that are consistent with components that impact the emergency power paths, the change in AOT does not increase the amount of time necessary for maintenance or testing, and the current maintenance and testing requirements are not changed. Thus, it is not expected that the future removal of the Keowee emergency start function from service for preventative maintenance and testing to be for periods of time that are significantly longer than the past maintenance and testing activities. In addition, the unavailability time for the emergency power paths is monitored as part of the maintenance rule program. If the unavailability time for the emergency power paths exceeds the maintenance rule requirements, actions will be taken to reduce the unavailability time. This response resolved the concern.

The current TS do not specifically address Condition C. Therefore, for this condition, the current TS do not provide specific plant actions to be taken leading to a unit shutdown path.

For this condition, the proposed TS require entry into Conditions G or H of TS Section 3.7.1, and, thus, require specific actions to be taken.

Proposed TS Section 3.7.5 addresses the EPSL functional unit provided in the current TS as Keowee emergency start circuit. As previously indicated, the issue relating to multiple simultaneous degradation of EPSL functional units also applies to proposed TS Section 3.7.5.

4.6.4 Proposed Surveillance- Requirement Proposed TS Section 3.7.5 contains one SR. SR 3.7.5.1 requires performing SR 3.7.1.11 (Keowee emergency start) annually and SR 3.7.1.14 (EPSL automatic transfer) on an 18-month frequency. SR 3.7.1.11 verifies the response time of the Keowee units to an emergency start signal, which ensures that engineered safeguards equipment will have adequate power for

design accident mitigation. Two locations exist for control room manual initiation of Keowee emergency start logic. These are the ONS Units 1 and 2 combined control room or the Unit 3 control room. Each unit has individual logic which actuates the associate emergency start relays. This provides the ability to verify operability of each control room logic independent of each ONS unit. The annual frequency for SR 3.7.1.11 was determined based on operating experience to provide reliability verification without excessive equipment cycling for testing. The purpose of SR 3.7.1.14 is to verify EPSL automatic transfer functions. These surveillances provide requirements that are consistent with those in the current TS.

4.7 TS 3.7.6, "Emergency Power Switching Logic (EPSL) Degraded Grid Voltage Protection" 4.7.1 Background Two independent levels of protection are provided to assure the degradation of voltage from offsite sources does not adversely impact the function of safety-related systems and components. The first level of protection is provided by the EPSL Degraded Grid Protection System (DGPS). The second level of protection is provided by undervoltage relaying on the E and N breakers (addressed in proposed TS Section 3.7.4), which protects from loss of voltage. Upon indication of inadequate voltage, the DGPS is designed to provide an alarm to the Unit 1 and Unit 2 control room and the Spartanburg dispatcher. If any single engineered S safeguards (ES) Channel 1 or 2 signal from any unit is sensed by the DGPS while the voltage is below acceptable levels, the DGPS is designed to initiate an isolation of the 230 kV switchyard yellow bus to ensure that the onsite overhead emergency power path is available.

Each DGPS actuation logic channel is capable of isolating the overhead emergency power path by a set of actuating relays and the associated switchyard power circuit breaker (PCB) trip coils.

The sets of actuating relays are common to the DGPS and the undervoltage part of another system called the External Grid Trouble Protection System (EGTPS). Isolation of the 230 kV switchyard yellow bus is accomplished by opening nine switchyard PCBs.

There are three undervoltage relays installed to monitor the switchyard voltage, one for each phase of the 230 kV yellow bus. Each of the undervoltage relays is supplied by a single phase coupling-capacitor voltage transformer. The undervoltage relay contacts are arranged in a two out of three logic configuration that feeds two redundant time delay dropout relays. The time delay relays are provided to prevent spurious actuations, as well as providing adequate response time to voltage transients. Either of the two redundant time delay relays is designed to cause either of the two sets of actuating relays to initiate switchyard isolation. A DGPS voltage sensing relay may be considered operable when it is in a tripped condition since this reduces the logic from a two out of three function to a one out of two function, which is conservative with regard to actuation. The two sets of actuating relays are shared with the voltage channels of the EGTPS and the associated switchyard.

PCB trip coils are considered part of the DGPS and are required to be operable. Thus, loss of actuating relays for an undervoltage channel constitutes loss of the attendant channel of the DGPS.

-32 4.7.2 Proposed TS Changes The LCO for proposed TS Section 3.7.6 requires that the following EPSL Degraded Grid Voltage Protection functions be OPERABLE: (1) Three Switchyard Degraded Grid Voltage Sensing Relays, and (2)Two channels of Switchyard Degraded Grid Voltage Protection Actuation Logic.

The proposed TS Section 3.7.0 contains three conditions addressing inoperability of equipment items. This proposed TS section also.contains another condition addressing not meeting the identified required actions and associated completion times.

4.7.3 Conditions Condition A of the proposed-TS Section 3.7.6 addresses inoperability of one voltage sensing relay. For this condition, the required action with completion time requires restoration of the voltage sensing relay to operable status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . Condition B addresses inoperability of one channel of actuation logic. For Condition B, the required action with completion time requires restoration of the channel to operable status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . Condition C addresses the required actions and associated completion times not meeting Conditions A or B. The required action with completion time for Condition C is that the unit be in hot shutdown within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to be in cold shutdown within 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months . Condition D addresses inoperability of two or more voltage sensing relays or two actuation logic channels. For Condition D, the required actions with completion time is to declare overhead emergency power path inoperable immediately.

Conditions A and B in the initial proposal for this TS section allowed a 7-day completion time for the condition required actions. As indicated in the initially proposed TS submittal, the 7-day completion time for Condition A or B required action was based on engineering judgement. The staff requested that the licensee provide a discussion that explained how the use of engineering judgement resulted in the determination of a 7-day completion time for the Condition A and B required actions. The licensee's response to this request was that engineering judgement takes into consideration the infrequency of actual grid system voltage degradation, the probability of a simultaneous ES actuation, and the availability of the other sensing relays or the availability of th e operable actuation channel. In addition, a probabilistic risk analysis (PRA) was performed on the degraded grid protection completion times to return an inoperable voltage sensing relay or one channel of actuation logic to operable status. The PRA conclusion indicated that the probability of accident sequences involving degraded grid conditions and failure of the DGPS, including the suggested inoperability contributions, is insignificant.

However, the staff continued to express concern regarding the proposed 7-day completion time, since it was not consistent with the 3-day required action completion time provided in the revised STS. In a supplemental and revised TS submittals, the licensee changed the 7-day completion times to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (3 days). This action resolved this concern. In addition to the above, it is noted that the DGPS is not addressed in the current ONS TS and during its review, the staff expressed concern regarding other issues. These issues are addressed in the following paragraphs.

-33 The staff noted that the revised STS requires that an inoperable degraded grid voltage protection sensor channel be placed in the tripped condition within a specific period of time.

Further, if the sensor channel cannot be placed in the tripped condition within the specified period of time, the action statement for the associated inoperable emergency onsite power source is to be entered. The initial proposal for this TS section did not require placing an inoperable degraded voltage sensor channel in the tripped condition, nor did it require that the action statement for an associated inoperable Keowee hydro unit be entered.

Another issue identified in relation to the initial proposal was that the required actions provided for proposed specific conditions did not provide actions requiring restoration of the inoperable equipment or a unit shutdown path. Thus, if certain verifications were performed within the specified period of time, plant operations could continue for an indefinite period of time with degraded or no system safety function. In discussions with the licensee regarding these issues, the licensee agreed to either revise the proposed TS to be consistent with the above revisions or to provide additional technical information to justify why such revisions are not necessary. In a revised TS submittal, the licensee revised the proposed TS section to specifically include actions requiring restoration of the inoperable equipment or a unit shutdown path. However, the issue of placing an inoperable sensing relay or actuation channel in a trip condition was not addressed. Thus, the staff requested the licensee to provide additional technical information to justify not including this provision. In response to this concern, in the revised TS submittal dated May 7, 1998, the licensee revised the required action for Condition A. The revised required action for Condition A requires placing voltage sensing relay in trip. The licensee also appropriately revised the Bases for.TS Section 3.7. These actions resolved the concern and result in requirements that are consistent with those in the revised STS.

4.7.4 Proposed Surveillance Requirements Proposed TS Section 3.7.6 contains two SRs. SR 3.7.6.1 requires, performing on an 18-month frequency, a channel calibration of the voltage sensing channel with setpoint allowable value for the degraded voltage > 226 kV and < 229 kV with a time delay of 9 seconds + 1 second. This surveillance verifies that the channel responds to the measured parameter within the necessary range and time limit. The channel calibration surveillance is to leave the channel adjusted to account for instrument drift to assure that the instrument channel remains operational between successive surveillances.

The initial proposal for this TS section did not include trip setpoints with minimum and maximum limits and allowable values for the degraded grid voltage protection sensors and associated time delay devices. The staff requested that the licensee provide justification for not including these specific values in the proposed TS. The licensee's response to this request was that the setpoints are listed in calculations that are reviewed on a periodic basis. Changes in the setpoints as a result of these reviews are possible. The trip setpoints and the allowable limits are not in the proposed TS because changes in the setpoints will require TS revisions, which are an unnecessary burden on the NRC and the licensee. In discussing this issue with the licensee, the staff found that the bases provided by the licensee is not technically adequate to support excluding trip setpoints and allowable values from the proposed TS. The staff felt that the degraded grid voltage issue was identified many years ago and the setpoints and allowable values for electrical systems added to protect against degraded voltage conditions should now

-34 be nearly firm and not changing frequently. In addition, the staff noted that TS provided for numerous other operating reactors included degraded grid trip setpoints and allowable values.

In a supplemental TS submittal, the licensee included a lower limit voltage value of > 219 kV and an upper limit time delay value of < 10 seconds. However, the staff continued to express concern since these values did not provide allowable values for the voltage setpoint and time delay devices. Any voltage value > 219 kV with any time delay value < 10 seconds would satisfy these TS requirements. Thus, voltage values greater than 219 kV with time delay values of less than 10 seconds and an ES signal could result in separation from a capable preferred power source (offsite power) at a time when this source is needed. As a result, the licensee was requested to provide TS-required allowable values with upper and lower limits for the degraded grid voltage protection devices/circuitry or to provide additional technical information to support why such TS-required values are not necessary. Inthe revised TS submittal, the licensee included the identified upper voltage and lower time delay limits. Further, information included with the revised TS submittal notes that the lower voltage limit was changed from 219 kV to 226 kV. This change was the result of a modification that changed the tap settings on the startup transformers. These licensee actions regarding the allowable value issue result in TS requirements that are consistent with the revised STS and resolved the concern.

Another issue noted for this proposed TS section related to the EGTPS. The current TS for the ONS units contain a surveillance requirement for the EGTPS logic. The proposed TS do not include this surveillance requirement. The staff requested the licensee to provide a discussion containing the criteria used and explaining how it was determined that no explicit TS SR is necessary for testing of the EGTPS logic. In addition, the licensee was requested to explain why the frequency portion of this system is to be maintained as safety-related. The licensee's response to these requests was that the SR for the EGTPS logic was not included in the proposed TS because the 230 kV DGPS is credited for the switchyard isolation in DBA (design basis accident) scenarios. In addition, the degraded grid voltage circuitry has a required surveillance in the proposed TS. Further, switchyard isolation can be initiated by the undervoltage or underfrequency relays for the EGTPS. The degraded grid protection replaces the function of the undervoltage portion EGTPS; however, the EGTPS has not been disabled since it provides a backup means of switchyard isolation. The frequency portion of the EGTPS is addressed in the ONS SLC manual because it provides a function that was not replaced by the degraded grid circuitry. In addition, the EGTPS is classified and maintained as QA Condition 1. Further, as a result of an additional staff request, the licensee committed to relocate the periodic SRs for both the voltage and frequency portion of the EGTPS to the SLC manual. Thus, changes regarding these surveillances are to be controlled by the 10 CFR 50.59 regulation. This response and resulting actions resolved the concern.

Proposed TS SR 3.7.6.2 requires performing, on an 18-month frequency, a channel test. This channel test is required to be performed on each DGPS voltage sensing channel and DGPS actuation logic channel, and is necessary to ensure the entire channel can perform its intended function. The test of the DGPS actuation logic channels will include verifying actuation of both channels of the switchyard isolation circuitry. The frequency considers operating experience, which aided in determining that testing on a refueling frequency interval provides assurance that the circuitry is available to perform its function. This surveillance is consistent with STS requirements.

-35 4.8 TS 3.7.7, "Emergency Power Switching Logic (EPSL) CT-5 Degraded Grid Voltage Protection" 4.8.1 Background Two levels of protection are provided for the standby buses to assure that degradation of voltage from the 100 kV transmission system through the central switchyard does not adversely impact the function of safety-related systems and components. The first level of protection is provided by the EPSL CT-5 degraded grid protection system and the second level of protection is provided by undervoltage relaying on the standby buses, which protects from loss of voltage.

Three undervoltage sensing relays are required as a common input device to both channels of actuating logic. In addition to the three phase undervoltage sensing relays, each channel requires one time delay relay, one auxiliary relay, and one associated single phase undervoltage sensing relay. Each channel trip signal passes through a selector switch, which either allows or inhibits the trip signal to actuate one trip coil in each SL breaker. Inoperability of any voltage sensing relay is defined as it being unable to trip. This condition reduces the logic for the given channel to a two of two logic configuration. Loss of the single phase relay makes the affected channel inoperable and loss of two or more voltage sensing relays results in inoperability of both channels of actuation logic.

4.8.2 Proposed TS Changes The LCO for proposed TS Section 3.7.7 requires that the following EPSL CT-5 Degraded Grid Voltage Protection functions be OPERABLE: (1) Three CT-5 Degraded Grid Voltage Sensing Relays, and (2) Two channels of CT-5 Degraded Grid Voltage Protection Actuation Logic. This LCO is applicable above cold shutdown when the Central Switchyard is energizing the standby buses.

4.8.3 Conditions Proposed TS Section 3.7.7 provides three conditions. Condition A addresses one voltage sensing relay being inoperable. The required action and completion time is to restore voltage sensing relay to the operable status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . Condition B addresses one channel of actuation logic being inoperable. Its required action and completion time is to restore the channel to operable status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . Condition C addresses two actuation logic channels being inoperable, or two or more voltage sensing relays being inoperable, or if the required actions and associated completion times cannot be met for Condition A or B.

Required actions and completion times for Condition C are to open SL breakers within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

The current TS do not address the central switchyard energizing the standby buses. In addition, in the initial TS proposal it was not clear what the specific conditions or circumstances were for using the central switchyard to energize the standby buses. In discussing these issues with the licensee, the staff noted that when the proposed TS require the standby buses are to be energized, they are required to be energized using an isolated power path supplied by the Lee Station. Thus, in accordance with proposed TS Section 3.7, the central switchyard cannot be used as a replacement or substitute for the isolated power path from the Lee Station. Thus,

P the proposed TS section is consistent with the other proposed TS 3.7 sections and the current TS.

4.8.4 Proposed Surveillance Requirements This proposed TS section contains two SRs. SR 3.7.7.1 requires performing, on an 18-month frequency, a channel calibration of the voltage sensing channel with the setpoint allowable value for: (a) degraded voltage > 4143 V and < 4185 V with a time delay of 9 seconds

+ 1 second for the first level of undervoltage inputs, and (b)degraded voltage > 3871 V and

< 3901 V for the second level of undervoltage inputs. This SR verifies that the channel responds to the measured parameter within the necessary range and accuracy. The channel calibration is to leave the channel adjusted to account for instrument drift to assure that the instrument channel remains operational between successive tests.

The staff noted that the initial proposal for the TS surveillance did not include trip setpoints with minimum and maximum limits and allowable values for the CT-5 degraded grid voltage protection sensors and associated time delay devices. The licensee was requested to provide these specific values in the proposed TS. In response to this request, the licensee included in a revised TS submittal, lower limit voltage setpoint values of > 4155 V (first level of protection) and > 3874 V (second level of protection) and an upper limit time delay value of < 10 seconds.

However, the staff continued to express concern about being able to meet such TS requirements and if it would result in unnecessary separation of the standby buses from the power path. That is,values above these voltage value limits and below the time delay limit are suggestive of a satisfactory power path (including the power source). The staff indicated that the licensee should strongly consider including trip setpoints with minimum and maximum limits and allowable values in the proposed TS section or provide additional technical justification for not including them. In the revised TS submittal, the licensee included the identified lower and upper voltage and time delay limits. These revisions resolved the concern.

SR 3.7.7.2 requires performing a channel test on an 18-month frequency. This channel test is to be performed on each CT-5 DGPS voltage sensing channel and each CT-5 DGPS actuation logic channel to ensure that the entire channel can perform its intended function. The frequency considers operating experience that aided in determining that testing on an 18-month interval provides assurance that the circuitry is available to perform its function.

4.9 TS 3.7.8, "DC Sources - Operating" 4.9.1 Background For each of the three units, two independent and physically separate 125 Vdc batteries and buses are provided for the 125 Vdc vital l&C sources. Three battery chargers are supplied for each unit, with two serving as normal supplies to the bus sections with the associated 125 Vdc battery floating on the bus. The batteries supply the load without interruption should the battery chargers or the ac source fail.. Each of the three battery chargers is supplied from a separate 600-volt ac engineered safeguards motor control center. One of these three battery chargers serves as a standby battery charger, is provided for servicing the others, and provides back up the normal chargers. A bus tie with normally open breakers between each pair of dc bus

-37 sections can be used to back up a battery when it is removed for servicing. When the distribution centers are cross-tied, the batteries and chargers on that unit are considered to be a single source. One battery can supply both distribution centers and their associated panelboard loads.

As previously noted in Section 3.2 of this report, in order to provide all safety functions required during an accident, power must be provided from any three of the four vital I&C dc panelboards.

During normal operation, the auctioneering network provides multiple redundancy for assuring that power from the 125 Vdc vital I&C sources would be provided to the vital I&C dc panelboards. Thus, power from any three of the four vital l&C dc sources for a particular unit (two for the unit considered, and two from the backup unit) continues to provide redundancy of power sources for safety functions performed by the vital dc l&C panelboards.

The 230 kv switchyard (SY) 125 Vdc sources consist of 125 Vdc battery sources. These sources provide primary and backup dc power for protective relaying and actuation circuits associated with the 230 kv SY, as well as dc control power for 230 kv SY PCB (power circuit breaker) operation. They are designed to have sufficient independence, redundancy, and testability to perform the safety functions assuming a single failure.

There are two 125 Vdc batteries in the 230 kv SY relay house. Each of these batteries is provided with an associated battery charger. There is a spare charger that can be connected to either battery. These components, along with their interconnecting wiring and breakers, comprise the two 125 Vdc sources for the 230 kv SY. Each 125 Vdc source is designed to have stored capacity sufficient to supply the required emergency loads for at least 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . A 1-hour minimum capacity is considered adequate, due to the high probability of restoring power to the charger within this time. Each charger is designed to have a power output capacity sufficient for steady-state operation of connected loads during normal operation, while simultaneously maintaining or restoring the associated battery bank to a fully charged condition.

The outputs of the 230 kv SY sources, identified as SY-1 and SY-2, are connected to distribution centers identified as SY-DC-1 and SY-DC-2, respectively. The buses are metal clad two conductor assemblies. A bus tie with normally open breakers is connected between the distribution centers to backup a battery when it is removed for servicing.

4.9.2 Proposed TS Changes The LCO for proposed TS Section 3.7.8 requires the following to be OPERABLE: (1)three of four 125 Vdc vital 1&C power sources; (2) five of six 125 Vdc vital I&C power sources for operation of two or three units; (3)four of six 125 Vdc vital I&C power sources for operation of one unit; (4) no single 125 Vdc vital I&C power source shall be the only source supplying power to two or more 125 Vdc vital l&C panelboards; (5)for Units 2 or 3, no single 125 Vdc vital l&C power source shall be the only source supplying power to 125 Vdc vital l&C panelboards 1DIC and 1DID; and (6)two 230 kv switchyard 125 Vdc power sources.

Two notes are provided with this LCO. The first note states that the additional 125 Vdc vital I&C power sources required by LCO 3.7.8 part 2 (five of six 125 Vdc vital l&C power sources for operation of two or three units) or part 3 (four of six 125 Vdc vital l&C power sources for

-38 operation of one unit) are not required to be connected to the unit distribution system. The second note states that the 125 Vdc vital I&C power sources required by LCO 3.7.8 part 3 shall include one 125 Vdc vital I&C power source belonging to each unit not above cold shutdown.

The current ONS TS require an operable dc source for an ONS unit when reactor coolant temperature is below 200 0 F. When two ONS units are shut down, the current TS require four of the six station batteries to be operable, and each shutdown unit must have one operable battery. This is necessary to meet dc capacity requirements and single failure criterion for the operating ONS unit. To ensure that this TS requirement is maintained, the proposed TS requires four of six 125 Vdc vital I&C power sources when only one unit is in operation. The second note indicates that when a single unit is in operation, each shutdown unit must have one operable dc source. In this regard, the proposed TS are consistent with the current TS. In addition, the first note is used to indicate that the additional 125 Vdc vital l&C power sources required for operation of one or more of the units are not required to be connected to the unit's distribution system. The LCO requires five of six 125 Vdc vital I&C power sources for operation of two or more units. Each unit has two 125 Vdc vital l&C power sources and can receive dc power through auctioneering diode assemblies from the two batteries for another unit. In order to meet the LCO for five power sources, the fifth source is obtained by crediting a battery that is not directly connected to a unit's distribution system. Therefore, the first note results in proposed TS requirements that are consistent with those in the current TS. However, without inclusion of this note, the STS guidelines would require that five power sources be directly available to each Oconee unit. The LCO for this TS section is consistent with the current TS.

4.9.3 Conditions The proposed TS Section 3.7.8 contains six conditions addressing inoperability of equipment items. This section also contains another condition addressing not meeting the identified required actions and associated completion times. This additional condition also addresses inoperability of multiple equipment items.

Condition A addresses conditions where one 125 Vdc vital l&C power source is inoperable because it cannot perform the equalization charge after performance test or service test. For Condition A, the required action with completion time is to restore the required 125 Vdc vital I&C power source to operable status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

Condition B addresses conditions where one required 125 Vdc vital I&C power source is inoperable for reasons other than Condition A. The required action with completion time for Condition B is to restore required 125 Vdc vital I&C power source to operable status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

Condition C addresses conditions where one 125 Vdc vital I&C power source is supplying the only source of power to two or more 125 Vdc vital I&C panelboards. For Condition C,the required action with completion time is to align 125 Vdc vital I&C power sources such that no one 125 Vdc vital I&C power source is serving as the only power source to two or more 125 Vdc vital l&C panelboards within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

- 39 Condition D addresses conditions where one 125 Vdc vital I&C power source is supplying the only source of power to 125 Vdc vital l&C panelboards 1DIC and 1DID. The required action with completion time is to align 125 Vdc vital power sources such that no one 125 Vdc vital I&C power source is serving as only power source to 125 Vdc vital I&C panelboards 1DIC and 1DID within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . A note for Condition D states that Condition D is not applicable to Unit 1.

Inoperability of some of the auctioneering diode panels or a combination of 125 Vdc vital I&C sources and auctioneering diode panels could cause a single source to become the only source for dc panelboards 1DIC and 1DID. This condition would impact all three Oconee units since these panelboards provide primary and backup control power for the S, SK, and SL breakers, standby bus protective relaying, and retransfer to startup logic for all three units. In this condition, a single failure of that power source or its associated equipment could cause a power lost to both panelboards, so that required automatic EPSL functions for all three units may not be supported. Therefore, within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after such a condition arises, the TS requires that the affected equipment shall be restored and aligned such that no single source is the only source for dc panelboards 1DIC and 1DID. A note is included with Condition D to clarify that this condition does not apply to Unit 1. For the same situation (one power source supplying panelboards 1DIC and 1DID), Condition C applies to Unit 1. In addition, it is acceptable for Units 2 and 3 to be in Conditions C and D simultaneously since panelboards 1DIC and 1DID are not redundant to any Unit 2 or Unit 3 panelboard.

. Condition E addresses conditions where one 230 kv switchyard 125 Vdc power source is inoperable because it cannot perform the equalization charge after performance test or service test. For Condition E, the required action with completion time is to restore 230 kv switchyard 125 Vdc power source to operable status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

Condition F addresses conditions where one 230 kv switchyard 125 Vdc power source is inoperable for reasons other than Condition E. The required action with completion time for Condition F is to restore 230 kv switchyard 125 Vdc power source to operable status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

Condition G addresses required actions and associated completion times not meeting Conditions A through F, or two or more required 125 Vdc vital I&C power sources inoperable, or two 230 kv switchyard 125 Vdc power sources inoperable. For Condition G,the required actions with completion times are to be in hot shutdown within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to be in cold shutdown within 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months .

The initial TS proposal addressing the vital dc power sources did not contain a condition for inoperability of two 125 Vdc vital power sources. Therefore, the staff requested the licensee to provide a technical discussion explaining why the condition of inoperable of two 125 Vdc vital power sources need not be explicitly addressed in the proposed TS. The licensee's response to this concern was that two inoperable required 125 Vdc vital power sources were not specifically addressed because this condition would put the station in TS 3.0 (immediate shutdown). In discussing this issue with the licensee, the staff noted that this level of .

degradation should be addressed by a condition. In a supplemental TS submittal, the licensee provided Condition G that addresses multiple-required vital l&C and/or 230 kv switchyard 125 Vdc power sources. However, this condition allows 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months to place the associated ONS unit in a cold shutdown condition instead of the 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months permitted by TS 3.0. For each of

-40 these cases, the staff requested that the licensee provide a discussion of the technical bases for allowing the additional time to place the associated unit in a cold shutdown condition. Inthe revised TS submittal dated May 7, 1998, the licensee revised Condition G and added a Condition H. The revised Condition G addresses conditions where the required actions and associated completion times are not met. For revised Condition G, the required actions and associated completion times are to be in hot shutdown within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and be in cold shutdown within 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months . The added Condition H addresses inoperability of two or more required 125 Vdc vital I&C power sources or inoperability of two 230 kv switchyard 125 Vdc power sources. The required action and completion time for Condition H is to enter TS 3.0 immediately. The licensee also revised the Bases for TS Section 3.7 to reflect these changes.

Further, the licensee noted that this change would be incorporated in the ONS ITS submittal.

These actions resolved the concern.

4.9.4 Proposed Surveillance Requirements Proposed TS Section 3.7.8 contains five SRs. SR 3.7.8.1 requires verifying weekly that battery float voltage is > to 125 Vdc. Verifying battery voltage while on float charge helps to ensure the effectiveness of the charging system and the ability of the battery to perform its intended function. Float charge is the condition where the charger is supplying continuous charge required to overcome the internal losses of the battery and maintain the battery in a fully charged state. The weekly frequency is consistent with manufacturers' recommendation and information contained in IEEE Standard 450.

SR 3.7.8.2 requires verifying that peak inverse voltage capability of each 125 Vdc vital l&C auctioneering diode is within limits. SR 3.7.8.2 requires this verification on a 6-month frequency. Measuring peak inverse voltage capability of each auctioneering diode ensures the diodes are capable of isolating a fault on one source from the other source.

SR 3.7.8.3 requires verifying on an annual frequency that battery capacity is adequate to supply and maintain in operable status the required emergency loads for the design duty cycle when the battery is subjected to a battery service test. The battery service test demonstrates the capability of the battery to meet the system analyzed response requirements. The annual frequency is based on industry-accepted practice considering the unit conditions required to perform the test, the ease of performing the test, and the likelihood of a change in system or component status.

SR 3.7.8.4 requires verifying on an annual frequency that cells, end cell plates, and battery racks show no visual indication of structural damage or degradation. Visual inspection of battery cells, end cell plates, and battery racks provide an indication of physical damage or abnormal deterioration, which could potentially degrade battery performance. The annual frequency considers operational experience and is viewed sufficient to detect battery degradation on a long-term basis when coupled with other surveillances more frequently performed to detect abnormalities.

SR 3.7.8.5 requires verifying on an annual frequency that cell to cell and terminal connections are clean, tight, and coated with anticorrosion grease. Verification of cell to cell connection

-41 cleanness, tightness, and proper coating with anticorrosion grease provides an indication of any abnormal condition, and assures continued operability of the battery.

SRs 3.7.8.2, 3.7.8.3, 3.7.8.4, and 3.7.8.5, previously addressed, for proposed TS Section 3.7.8 are consistent with ones provided in the current TS.

4.10 Proposed TS 3.7.9, 'Vital Inverters - Operating" 4.10.1 Background The ac vital distribution system includes four redundant 120 Vac vital instrument power panelboards for each unit that provide power to associated vital I&C loads under all operating conditions. Each panelboard is powered separately from a static inverter connected to one of the four 125 Vdc l&C panelboards. In order to accommodate maintenance on the inverters and supply backup power, a tie line with breakers is connected to each of the 120 Vac vital panelboards from the alternate 120 Vac regulated bus.

4.10.2 Proposed TS Changes The LCO for proposed TS Section 3.7.9 requires that four vital inverters be OPERABLE.

4.10.3 Conditions The proposed TS Section 3.7.9 contains four conditions. Condition A addresses conditions when the DIA or DIB inverter is inoperable. For Condition A, the required actions with completion times are to connect associated panelboard to regulated panelboard KRA within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , verify associated panelboard is energized once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , and restore vital inverter panelboard to operable status within 7 days. In the event that an inverter associated with panelboard KVIA or KVIB is inoperable due to an inoperable inverter, a period of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is allowed to connect the associated panelboard to the KRA regulated panelboard. These two panelboards provide power to the two digital engineered safeguards channels that cannot actuate without power. Powering the inverter associated panelboard from KRA ensures that non-load shed power is available in the event of an accident. Connecting to the KRA panelboard will restore power to the KVIA or KVIB panelboard. However, panelboard KVIA or KVIB will still be considered inoperable in this condition and must be verified to be energized once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . In addition, panelboard KVIA or KVIB must be returned to its inverter supply within 7 days.

Condition B addresses conditions where the DIC or DID inverter is inoperable. For Condition B, the required actions with completion times are to connect associated panelboard to regulated panelboard KRA within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , verify associated panelboard is energized once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , and restore vital inverter to operable status within 7 days. Inthe event that panelboard KVIC or KVID is inoperable due to an inoperable inverter, a period of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is allowed to connect the panelboard to the KRA regulated panelboard. This is based on the allowed inoperability period for a 125 Vdc l&C panelboard, which is the normal power source to the vital inverters. Vital inverters DIC and DID supply loads do not necessarily become inoperable upon loss of power; for example, reactor protection and engineered safeguards channels are designed to trip upon

-42 loss of power. Powering the inverter associated panelboard from KRA is needed to ensure non-load shed power is available in the event of an accident. However, panelboard KVIC or KVID will still be considered inoperable in this condition and must be verified to be energized once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and returned to its inverter supply within 7 days.

Condition C addresses required actions and associated completion times for not meeting Condition A or B. For Condition C, the required actions and associated completion times are to be in hot shutdown within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to be in cold shutdown within 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months . If the required actions and associated completion times cannot be met, the unit must be in hot shutdown within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and cold shutdown within the following 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This unit shutdown path is consistent with that provided in the current TS.

Condition D addresses conditions where two or more vital inverters are inoperable. For this condition, the required action with completion time requires entry into TS 3.0 immediately. The inoperability of two or more ac vital panelboards could result in a loss of safety function.

Therefore, the provisions of TS 3.0 apply.

The preceding conditions, required actions, and completion times are consistent with those provided in the current TS.

4.10.4 Proposed Surveillance Requirement The proposed TS Section 3.7.9 contains one SR. SR 3.7.9.1 requires weekly verification of correct inverter voltage, frequency, and alignment to required 120 Vac instrumentation power panelboards. This SR verifies that the inverters are functioning properly with all required breakers closed and ac vital panelboards are energized from the inverter. The verification of proper voltage and frequency ensures that the required power is readily available for the instrumentation connected to the panelboards. This SR is consistent with that provided in the STS.

4.11 TS 3.7.10, "Battery Cell Parameters" 4.11.1 Background The proposed TS Section 3.7.10 delineates the limits on electrolyte temperature, level, float voltage, and specific gravity (or float current) for the Keowee hydro unit 125 Vdc, 125 Vdc vital I&C, and 230 kv 125 Vdc power source batteries.

4.11.2 Proposed TS Changes The LCO for proposed TS Section 3.7.10 requires battery cell parameters for the Keowee hydro unit, 125 Vdc vital I&C, and 230 kv 125 Vdc switchyard batteries to be within limits of.

Table 3.7.10-1.

Two notes refer to the actions section of proposed TS Section 3.7.10. The first note states that separate condition entry is allowed for each battery. This is acceptable since the required actions for each condition provide appropriate compensatory actions for each dc source.

-43 Complying with the required actions for one dc source may allow continued operation, and subsequent dc sources are governed by separate condition entry and application of associated required actions. This is consistent with the current TS and the STS.

Table 3.7.10-1 Battery Cell Surveillance Requirements PARAMETER CATEGORY A: CATEGORY B: CATEGORY C:

LIMITS FOR EACH LIMITS FOR EACH ALLOWABLE DESIGNATED CONNECTED CELL LIMITS FOR EACH PILOT CELL CONNECTED CELL Electrolyte Level > Minimum level > Minimum level Above top of plates, indication mark, and indication mark, and and not overflowing

< 1/4 inch above < 1/4 inch above maximum level maximum level indication indication mark(a)

. Float Voltage Specific Gravity mark(a)

>2.13 V

> 1.200

>2.13

> 1.200 V >2.07 V

> 1.200 (b)(c)

AND Not more than 0.010 below average of all connected cells (a) It is acceptable for the electrolyte level to temporarily increase above the specified maximum during equalizing charges provided it is not overflowing.

(b) Corrected for electrolyte temperature and level. Level correction is not required, however, when battery float current is < 2 amps when on float charge.

(c) A battery float current of < 2 amps when on float charge is acceptable for meeting specific gravity limits following a battery recharge, for a maximum of 7 days. When float current is used in lieu of specific gravity requirements, specific gravity of each connected cell shall be measured prior to expiration of the 7 day allowance.

The second note states that TS 3.7.0 does not apply during entry into one of the action statements for the battery cell parameters. This is acceptable since the entry into any of the associated action statements does not necessarily indicate that the ONS unit is in a degraded mode of operation. If the action statement entry results in declaration of a dc source as inoperable, the appropriate TS action statement for the inoperable dc source is to be entered.

In certain situations, an inoperable vital 125 Vdc I&C source does not result in entry into an action statement since the design provides more vital 125 Vdc I&C sources than is required by

-44 the TS. The TS for the dc sources is to be used to determine if the unit is in a degraded mode of operation.

For situations that result in the entry into an action statement for the dc sources, the unit is under the restrictions of TS 3.7.0 since a similar note does not exist for the actions section of the dc sources TS.

4.11.3 Conditions Proposed TS Section 3.7.10 contains two conditions. Condition A addresses conditions where one or more batteries with one or more battery cell parameters is not within Category A or B limits. For Condition A, the required actions with completion times are to verify pilot cell electrolyte level and float voltage meet Table 3.7.10-1 Category C values within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , verify battery cell parameters meet Table 3.7.10-1 Category C values within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and once per 7 days thereafter, and restore battery cell parameters to Category A and B limits of Table 3.7.10-1 in 90 days.

Condition B addresses the required action and associated completion time if Condition A is not met, or one or more batteries with average electrolyte temperature of the representative cells is

< 60 OF, or one or more batteries with one or more battery cell parameters is not within Category C values. The required action and completion time for Condition B is to declare associated battery inoperable immediately.

The current TS do not specifically address battery cell electrolyte level above the top of the cell plates, cell float voltage below 2.07 volts, or electrolyte temperature less than 60 IF. For these situations, the proposed Condition B requires that the associated dc source be declared inoperable immediately.

As provided in the initial TS proposal for the battery cell parameters, the staff expressed concern regarding the 90-day completion time permitted to complete the required actions identified for electrolyte level, battery cell float voltage, and electrolyte specific gravity. The licensee was requested to provide a discussion containing the technical bases for the permitted 90-day completion times. In its response, the licensee stated that the 90-day completion time for the float voltage and electrolyte specific gravity parameters is necessary to procure a replacement cell. During the completion time for battery cell float voltage and electrolyte specific gravity, the battery is degraded but not inoperable. Further, this is not a change from the current TS or the ONS licensing basis. The licensee's response also indicated that the 90-day completion time for electrolyte level correction is necessary since the electrolyte level corrections are desired to be coordinated with scheduled equalize charging whenever possible.

In addition, the electrolyte level may rise above the full level mark following the discharge test recharge on equalize charge due to gassing and will require time to stabilize. The response indicates that the electrolyte level below the low level mark is not an operability concern.

However, if the level gets below the top of the cell plates, then the associated dc source will be declared inoperable immediately per the proposed TS. The surveillance of the electrolyte level is performed on a weekly basis and would identify any level concerns in the batteries in a timely manner. Any noncritical electrolyte level adjustments would be handled through the work request system, which requires time for planning and scheduling. The response also noted that

-45 the IEEE-450 Standard lists electrolyte level as a parameter that should be checked quarterly and corrected as necessary before the next quarterly surveillance. In addition, the licensee's response stated that during an earlier revision of the TS, the 90-day allowance was added by Amendment Numbers 82, 82, and 79. The NRC's SE that approved the amendments was dated May 2, 1980, and indicates that the proposed changes to TS Section 4.6.9 comply with the criteria of IEEE Standard 450-1975 and Regulatory Guide 1.32. The additional response further noted that the current TS do not contain operability requirements for battery cell parameters, whereas the proposed TS add restrictive operability requirements for cell parameters. These responses resolved the staff concern.

The current TS 4.6.9 requires that any battery or cell not in compliance with the periodic inspection requirements shall be corrected within 90 days or the battery shall be declared inoperable. The initial TS proposal for this section permitted that if a battery cell is inoperable, the battery may be restored to operable status by jumpering out the affected cell. In addition, the initial TS proposal allowed jumpering out two inoperable battery cells. The staff expressed the concern that with two battery cells jumpered out, the battery may not meet its design basis load demand. Further, this initial proposal is not consistent with the current TS in that these specifications do not address restoring an inoperable battery to operable status by jumpering out inoperable cells. As a result, the staff requested additional information to justify how the licensing basis requirements will continued to be maintained with one or two battery cells jumpered in a single battery. The licensee's response to this request was that inorder to ensure that the licensing basis is met when a cell is jumpered in a battery, an engineering evaluation will be performed prior to jumpering any battery cell. The engineering evaluation will analyze the battery capacity and loading with the battery cell jumpered out and a postulated single failure. If necessary, conditions could be placed on the associated battery parameters (such as battery cell temperature) to ensure that the battery remains operable. This response resolved the concern.

4.11.4 Proposed Surveillance Requirements Proposed TS Section 3.7.10 contains three SRs. SR 3.7.10.1 requires verifying weekly that battery cell parameters meet Table 3.7.10-1 Category A limits. This surveillance verifies that Category A battery cell parameters are met and is consistent with IEEE Standard 450 that recommends regular battery inspections including voltage, specific gravity, and electrolyte level of pilot cells.

SR 3.7.10.2 requires verifying quarterly that battery cell parameters meet Table 3.7.10-1 Category B limits. This surveillance requirement is also consistent with recommendations contained in IEEE Standard 450.

SR 3.7.10.3 requires verifying quarterly that average electrolyte temperature of representative cells is > 60 oF. This surveillance verifies that the average temperature of representative cells (at least every sixth connected cell) is > 60 oF and is consistent with a recommendation contained in IEEE Standard 450. This recommendation notes that the temperature of the electrolyte in representative cells should be determined on a quarterly basis. Lower than normal temperatures act to inhibit or reduce battery capacity, while higher temperatures reduce

-46 battery life. This surveillance requirement ensures that the operating temperatures remain within an acceptable operating range.

The proposed SRs provided requirements that are consistent with those contained in the current TS except that the acceptance criterion for cell float voltage has been increased from 2.12 Vdc to 2.13 Vdc. The change is necessary to be consistent with recommendations provided in IEEE Standard 450. The proposed SRs are also consistent with the STS.

5.0

SUMMARY

On the bases of the discussion and evaluation provided in Section 4.0 of this SE, the staff has concluded that the technical requirements contained in TS Section 3.7 are consistent with design requirements, the current ONS TS with differences justified, the Bases for TS Section 3.7, and technical requirements contained in the revised STS. Therefore, the staff has concluded from this review and evaluation that the technical requirements contained in the ONS revised TS Section 3.7 are acceptable.

6.0 ITS INVOLVEMENT The TS addressed by this SE are Section 3.7 of the current TS. However, this SE also provides the review for the technical changes that are included in Section 3.8 of the ONS ITS (that has been prepared per NUREG-1430) that is currently under staff review, but are beyond the scope of the ITS program. Both sets of specifications address the same provisions of the electrical TS. As a result, the staff has determined that it is satisfactory to approve the included TS and delay implementation so that implementation is coincident with the ITS amendments.

Any changes from this amendment will be addressed in the SE to accompany the ITS amendment. Therefore, upon implementation, the TS pages will reflect the ITS amendments only and will be shown by the ITS amendment numbers (i.e., the amendment numbers assigned to these amendments will not be shown on the ITS pages). These amendments form the basis and acceptability of the electrical section of the ITS.

7.0 STATE CONSULTATION

In accordance with the Commission's regulations, the South Carolina State official was notified of the proposed issuance of the amendments. The State official had no comments.

8.0 ENVIRONMENTAL CONSIDERATION

The amendments change requirements with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20 and the surveillance requirements. The NRC staff has determined that the amendments involve no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendments involve no significant hazards consideration, and there has been no public comment on such finding (62 FR 63975 dated December 3, 1997). Accordingly, the amendments meet the eligibility criteria for categorical exclusion set forth in 10 CFR

-47 51.22(c)(9). Pursuant to 10 CFR 51.22(b) no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendments.

9.0 CONCLUSION

The Commission has concluded, based on the considerations discussed above, that: (1)there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendments will not be inimical to the common defense and security or to the health and safety of the public.

Principal Contributors: Frank S. Ashe Duc T. Nguyen Chu-Yu Liang Date: September 4, 1998

ML15261A468

Contents

Text

1.0 INTRODUCTION

2.0 BACKGROUND

SUMMARY

7.0 STATE CONSULTATION

8.0 ENVIRONMENTAL CONSIDERATION

9.0 CONCLUSION

Navigation menu

ML15261A468

Text

1.0 INTRODUCTION

2.0 BACKGROUND

SUMMARY

7.0 STATE CONSULTATION

8.0 ENVIRONMENTAL CONSIDERATION

9.0 CONCLUSION

Navigation menu

Search