ML15112A924

Safety Evaluation Supporting Amends 82,82 & 79 to Licenses DPR-38,DPR-47 & DPR-55,respectively

ML15112A924
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Site:	Oconee
Issue date:	05/02/1980
From:	Office of Nuclear Reactor Regulation
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NUDOCS 8005210489
Download: ML15112A924 (7)

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UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D. C. 20555 SAFETY VALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION SUPPORTING AMENDMENT NO. 82 TO FACILITY OPERATING LICENSE NO. DPR-38 AMENDMENT NO. 82 TO FACILITY OPERATING LICENSE NO. DPR-47 AMENDMENT NO. 79 TO FACILITY OPERATING LICENSE NO. DPR-55 DUKE POWER COMPANY OCONEE NUCLEAR STATION, UNITS NOS. 1, 2 AND 3 DOCKETS NOS. 50-269, 50-270 AND 50-287 I. INTRODUCTION The Duke Power Company (the licensee), by letters dated February 1, 1978, June 12, 1978, October 31, 1978, and August 22, 1979, submitted proposed changes to the Technical Specifications (TSs) related to the auxiliary electrical systems and emergency-power system periodic testing for Oconee Nuclear Station, Units Nos. 1, 2 and 3 (ONS 1, 2 and 3).

The proposed changes would:

1. More clearly define the onsite emergency power transmission paths,

2. Provide flexibility in the limiting conditions for operation (LCO) of the 125 Vdc systems,

3. Permit one of the two independent onsite emergency power paths to be inoperable for a period of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for test or maintenance,

4. Increase the time allowed from 24 to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for one battery in a 125 Vdc system to be inoperable for equalizer charge following a dis charge test,

5. Permit removal of each switchyard battery for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in order to install seismic design battery racks,

6. More accurately describe the.dc system loads, and

7. Modify the annual testing surveillance requirements for the emergency power systems to permit demonstration that the systems are available to and capable of carrying the required load rather than require actual applica tion of engineered safety feature (ESF) loads II. BACKGROUND The offsite power system (see ONS Final Safety Analysis Report (FSAR) Ficure 8-2).

for ONS 1, 2 and 3 consists of six 230 kV transmission lines to the 230 kV station 80052 10 f0

-2 switchyard and two 500 kV transmission lines to a 500 kV switchyard. The 500 kV switchyard is connected to the 230 kV switchyard via an auto transformer.

Offsite power is available to each of the three Oconee units via 230/4.16 kV startup transforn~rs. The switchyards are arranged in breaker-and-a-half con figuration and each circuit breaker is provided with dual trip coils supplied from 125 Vdc station switching power systems which are independent from the Oconee units' Class 1E dc systems. The circuit protection is provided by redundant relaying.

Onsite power is provided by two 87.5 MVA hydroelectric generators. This power is available either through the 230 kV switchyard and the 45/60 MVA startup transformers or through a 13.8 kV underground feeder which utilizes its own 12/16/20 MVA transformer (Transformer No. CT4) and supplies two 4160 V main feeder buses in each of the three units. The maximum emergency power demand upon initiation of accident conditions would be 4.8 MVA per unit.

Three divisional 4.16 kV buses per unit are provided for ESF loads. The divi sional buses of each unit can be connected to either of their respective 4.16 kV main feeder buses. The sources of power which are automatically connected to the main feeder buses, in the order that they are connected, are:

1. The 230 kV switchyard via each unit's startup transformer,

2. The preselected hydro unit via the 13.8 kV underground feeder and the station's standby buses, and

3. The other hydro unit via a 230 kV overhead line, the 230 kV switchyard and each unit's startup transformer.

Also, the following sources of power or startup transformers can be made available manually:

1. One of the gas turbines located 30 miles away at the Lee Steam Station via an independent overhead 100 kV transmission system and the station's standby buses, and

2. The three startup transformers can be cross connected via the station's emergency startup buses.

The use of the Keowee Hydro Station and power supply transmission lines including transformers which have been under the direct control of the ONS was originally reviewed and found acceptable as the standby emergency power supply for the ONS during the operating license review.

III.

ACCEPTANCE CRITERIA The criteria applied in determining the acceptability of the TS changes for the ac anddc onsite power supply systems are:

1. General Design Criterion (GDC 17), "Electrical Power Systems," of Appendix A, )O CFR Part 50;

2. IEEE Std. 308-1974, "Class 1E Power Systems for Nuclear Power Generating Station s";

3. IEEE Std. 338-1975, "Periodic Testing of Nuclear Power Generating Station Class 1E Power and Protection Systems";

4. 10 CFR Part 50, Section 50.36 (c) (2), "Limiting Conditions for Operation"

5. Regulatory Guide 1.93, "Availability of Electric Power Sources";

6. Regulatory Guide 1.108, "Periodic Testing of Diesel Generators Used as Onsite Electric Power Systems at Nuclear Power Plants"; and

7. Regulatory Guide 1.6, "Independence Between Redundant Standby (Onsite)

Power Sources and Between Their Distribution System".

IV. EVALUATION

1. The proposed change to Section 3.7.1(c) of the TSs would improve the defi nition of the two emergency power supply systems to more precisely des cribe the components in the two emergency power paths. One path consists of the Keowee hydro unit, the underground feeder, transformer CT 4, and a 4160 V standby bus. The other path consists of the second Keowee hydro unit, a 230 kV overhead line, breaker PCB 9, and the 230 kV switchyard yellow bus, through each operating unit's startup transformer or the aligned and connected alternate startup transformer. The two paths are independent and redundant and are in accordance with IEEE 308-1974, Section 5.2.4(1) which states "the standby power supply shall consist of all com ponents from the stored energy to the connection to the distribution system's supply circuit breaker."

Each 4160 V main feeder bus of each unit can receive power from the 230 kV switchyard through the unit's startup transformer, through the aligned and connected alternate startp transformer or through the unit's auxiliary transformer back-fed from the main step-up transformer. The 4160 V main feeder bus for each unit can also receive power from the 4160 V standby bus through the 13.8 kV underground feeder supplying transformer CT 4.

Additionally, Specification 3.7.1(g) would be renumbered 3.7.1(e) and revised to allow operation utilizing the redundancy present in the 125 Vdc Instru mentation and Control System (I&C).

The 125 Vdc I&C power system consists of two batteries, three battery chargers, and two I&c distribution centers per unit.

Each of the 125 Vdc I&C distribution (e.g., IDGA or IDCB) centers is normally supplied power from its associated battery charger. One I&C battery and associated charger, however, is capable of supplying two I&C control distribution centers (e.g., IDCA and IDCB) and their associated panel board loads. All reactor protection and ESF loads on this system can be powered from either the Units 1 and 2, Units2 and 3 or Units 3 and 1, 125 Vdc I&C distributi-on centers (see FSAR Figure 8-5). Thus, a maximum of only five I&C batteries, with their respective chargers are required to be operable if all three reactors are operating.

-4 The proposed changes to TS 3.7.1 would satisfy the installed redun dancy and single failure criteria of Regulatory Guide 1.6, Position D.1, "The electrically powered safety loads (ac and dc) should be separated into redundant load groups such that loss of any one group will not pre vent the minimum safety functions." We find the proposed changes to.

Section 3.7.1 acceptable.

2. The proposed changes to Section 3.7.2(a) through (g) of the TSs would provide the LCO on a complete string of power supply, as is done in the current Standard TSs, rather than on individual components of the ac and dc power supply systna. The changes would incorporate the definition of the onsite standby power paths in Specification 3.7.1.

The licensee's proposals would provide more stringent LCO than the LCO in the current TSs.

Allowance would also be made for specific test operations associated with 125 Vdc systems. When the annual discharge test is performed on each battery, the accompanying equalizer battery charges require 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> more than the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />scurrently authorized for inoperability in 125 Vdc systems.

The battery tharger can supply all connected ESF and reactor protection steady state loads while its battery is returned to or maintained in equalizing charge. The battery discharge service test does not affect adversely the capability and availability of the 125 Vdc system during the subsequent 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> when the battery is on equalizing charge. We find the proposed changes to Specification 3.7.2 acceptable.

3. The licensee proposed to change the descriptions of the capacity of dc systems discussed in the bases to Section 3.7 in order to provide the actual maximum load conditions of the dc system capacity. The actual load condition shown in the revised discussion of the basis for the dc capacity is lighter and more practical than that stated in the current TSs. The changes would better define the actual margin in dc capacity. We find these changes acceptable.

4. The proposed changes to Sections 4.6.9 through 4.6.12 of the TSs regarding the periodic surveillance testing for the batteries would improve the surveillance in terms of test procedures. The surveillance requirements would comply with the criteria of IEEE Std. 450 and Regulatory Guide 1.32.

Therefore, we find the proposed changes acceptable.

5. The proposed change to Section 4.6.2 would require a test of the entire emergency underground power path from Keowee hydro unit to verify, without actually supplying the ESF loads, that theuunit would be available to carry and be capable of carrying ESF loads of a shutdown within 25 seconds of a requirement for the ESF. Promptly (within a few minutes) following the above test, the hydro unit would be loaded to at least the combined load of the auxiliaries actuated by ESF signal in one unit and the auxiliaries of the other two units in hot shutdown by synchronizing the hydro unit to the offsite power system and assuming the load at the maximum practical rate. The current TS 4.6.2 requires that a Keowee hydro unit actually

-5 carry the equivalent of the maximum safeguards load of one unit within 25 seconds of a,.simulated requirement for ESF. Under a postulated require ment for emergency power, each Keowee hydro unit is capable of starting and providing necessary power within 25 seconds. If the test were accomplished with a unit shutdown and all of the systems associated with the unit were fully operational, there still would not be sufficient load to run the test. It is not possible to provide the required lnad within 25 seconds for the test without adverse impact on the operating units.

(The test could not be accomplished with a unit operating without causing a reactor trip to occur.)

Based on IEEE 338-1975, Standard Criteria for Periodic Testing of Nuclear Power Generating Station Class 1E Power and Protection Systems, Section 6(2), "the overlap tests are permitted where full functional tests are not practical," the sequen tial tests and overlap tests are acceptable. Furthermore, each hydro unit is started and operated daily at power levels in excess of the worst case requirements of the ONS. The licensee has informed us orally that starting times of 17 to 19 seconds (however loads are not applied within this time) are typically experienced during these operations. In addition to these daily operations, the automatic controls of the 230 kV switchyard have been quali fled as Class 1E and are tested annually for proper operation of the 230 kV switchyard breakers. Therefore, we find that the proposed changes to the TSs which require that the Keowee hydro unit be verified to be capable of carrying and available to carry to the ESF load of a shutdown unit on 4160 V emergency buses within 25 seconds of a simulated requirement for ESF, are acceptable.

6. The licensee proposed to modify the TSs to permit a one time exception to Sections 3.7.1 and 3.7.2 in order to replace the nonseismic design switch yard battery support structures with seismic Category I design support structures. Specifically, the licensee has proposed that each of the two switchyard batteries be allowed to be taken out of service for a period of time not to exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in order to allow sufficient time to make this install ation. This is an extension of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> beyond the present TS limit of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Installation of the seismic Category I design support structure will improve the probability that the 125 Vdc switchyard power system will remain operable following an earthquake-Further, only one of the batteries will be inoperable at a given time and the other battery and its power string will be checked to assure that it is operable immediately prior to removing a battery from service.

We find that the improved capability of the supports to withstand earthquakes warrants the 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> extension of battery down time to allow the installation. We have made the TS a temporary one, 3.7.2T (Temporary), which will expire as soon as both new supports are installed.

-6 Environmental Consideration We have determined that the amendments do not authorize a change in effluent types or total amounts nor an increase in power level and will not result in any significant environmental impact. Having made this determination, we have further concluded that the amendments involve an action which Is insignificant from the standpoint of environmental impact and, pursuant to 10 CFR §51.5(d)(4)9 that an environmental impact statement, or negative declaration and environ mental impact appraisal need not be prepared in connection with the issuance of these amendments.

Conclusion We have concluded, based on the considerations discussed above,.that:

(1) because the amendments do not involve a significant increase in the probability or consequences of accidents previously considered and do not involve a signi ficant decrease in a safety margin, the amendments do not involve a significant hazards consideration, (2) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, and (3) such activities will be conducted in compliance with the Commission4s regulations and the issuance of these amendments will not be inimical to the conon defense and security or to the health and safety of the public.

Dated:

May 2, 1980

-7 VI.

REFERENCES

1. 10 CFR 50, Appendix A, General Design Criterion 17, Electrical Power System.

2. 10 CFR 50, Section 50.36(c)(2) Limiting Conditions for Operation.

3. IEEE Std. 308-1974, IEEE Standard Criteria for Class 1E Power Systems for Nuclear Power Generating Stations.

4. IEEE Std. 450-1975, IEEE Recommended Practice for Maintenance, Testing and Replacement of Large Lead Storage Batteries for Generating Stations and Substations.

5. Regulatory Guide 1.93, Availability of Electric Power Sources, dated December 1974.

6. ONS TSs, Section 3.7 and 4.6.

7. Letter from Mr. W. 0. Parker, Jr. (DPC) to Mr. E. G. Case (NRC) dated February 1, 1978.

8. Letter from Mr. W. 0. Parker, Jr. (DPC) to Mr. E. G. Case (NRC) dated June 12, 1978.

9. Letter from Mr. W. 0. Parker, Jr. (DPC) to Mr. H. R. Denton (NRC) dated October.31, 1978.

10. Letter from Mr. W. 0. Parker, Jr. (DPC) to Mr. H. R. Denton (NRC) dated August 22, 1979.

11.

FSAR -

Oconee Units 2 and 3.