ML15112A554
| ML15112A554 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 01/22/1998 |
| From: | Labarge D NRC (Affiliation Not Assigned) |
| To: | Mccollum W DUKE POWER CO. |
| References | |
| TAC-M93550, NUDOCS 9801270182 | |
| Download: ML15112A554 (8) | |
Text
Mr. William R. McCollu 4
January 22, 8
Vice President, Oconee Site Duke Energy Corporation P: 0. Box 1439 Seneca, SC 29679
SUBJECT:
REQUEST FOR ADDITIONAL INFORMATION RELATED TO DUKE POWER RESPONSE TO THE NRR DRAFT REPORT ON THE OCONEE EMERGENCY POWER SYSTEM (TAC M93550)
Dear Mr. McCollum:
By letter dated October 31, 1996, Duke Energy Corporation (formerly Duke Power Company) responded to the NRR Draft Report on the Oconee Emergency Power System dated July 8, 1996. As a result of our review of this information, we have determined that additional information and clarification is needed to close out open issues and help finalize our report on the Oconee/Keowee emergency electrical distribution system. We request that you respond to the enclosed request for additional information within 30 days of receipt of this letter.
Sincerely, ORIGINAL SIGNED BY:
David E. LaBarge, Senior Project Manager Project Directorate 11-2 Division of Reactor Projects - 1/11 Office of Nuclear Reactor Regulation Docket Nos. 50-269, 50-270 and 50-287
Enclosure:
As stated cc w/encl: See next page DISTRIBUTION w/enclosure:
CDket-Fil@
PD 11-2 Rdg.
OGC PUBLIC BBoger ACRS F. Ashe HBerkow JJohnson, RII D. Nguyen LBerry COgle, RII J. Lazevnick DLaBarae..
9801270182 980122 PDR ADOCK 05000269 F
PDR io receive a copy ot this document, indicate in the box: "C" = Copy without attachment/enclosure "E" = Copy with attachment/enclosure "N" = No copy OFFICE PM:
L A:PDI I-4 DA IIl H H
NAME DLa arge:cn LBerry O
w DATE u
/
/98 I
\\l /98 l /98
/98
/98
/97 DOCUMENT NAME: G:\\OCONEE\\REPORT.RAI OFFICIAL RECORD COPY
~ 11111 11111 11111 1111 1111111111111111111 S S 4
6 F
A
R REG&
UNITED STATES 0
NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 January 22, 1998 Mr. William R. McCollum Vice President, Oconee Site Duke Energy Corporation P. 0. Box 1439 Seneca, SC 29679
SUBJECT:
REQUEST FOR ADDITIONAL INFORMATION RELATED TO DUKE POWER RESPONSE TO THE NRR DRAFT REPORT ON THE OCONEE EMERGENCY POWER SYSTEM (TAC M93550)
Dear Mr. McCollum:
By letter dated October 31, 1996, Duke Energy Corporation (formerly Duke Power Company) responded to the NRR Draft Report on the Oconee Emergency Power System dated July 8, 1996. As a result of our review of this information, we have determined that additional information and clarification is needed to close out open issues and help finalize our report on the Oconee/Keowee emergency electrical distribution system. We request that you respond to the enclosed request for additional information within 30 days of receipt of this letter.
Sincerely, David E. LaBarge, Senior Project Manager Project Directorate 11-2 Division of Reactor Projects - 1/11 Office of Nuclear Reactor Regulation Docket Nos. 50-269, 50-270 and 50-287
Enclosure:
As stated cc w/encl: See next page
Oconee Nuclear Station cc:
Mr. Paul R. Newton Mr. J. E. Burchfield Legal Department (PBO5E)
Compliance Manager Duke Energy Corporation Duke Energy Corporation 422 South Church Street Oconee Nuclear Site Charlotte, North Carolina 28242 P. 0. Box 1439 Seneca, South Carolina 29679 J. Michael McGarry, III, Esquire Winston and Strawn Ms. Karen E. Long 1400 L Street, NW.
Assistant Attorney General Washington, DC 20005 North Carolina Department of Justice Mr. Robert B. Borsum P. O. Box 629 Framatome Technologies Raleigh, North Carolina 27602 Suite 525 1700 Rockville Pike L. A. Keller Rockville, Maryland 20852-1631 Manager - Nuclear Regulatory Licensing Manager, LIS Duke Energy Corporation NUS Corporation 526 South Church Street 2650 McCormick Drive, 3rd Floor Charlotte, North Carolina 28242-0001 Clearwater, Florida 34619-1035 Mr. Richard M. Fry, Director Senior Resident Inspector Division of Radiation Protection U. S. Nuclear Regulatory North Carolina Department of Commission Environment, Health, and 7812B Rochester Highway Natural Resources Seneca, South Carolina 29672 3825 Barrett Drive Raleigh, North Carolina 27609-7721 Regional Administrator, Region II U. S. Nuclear Regulatory Commission Atlanta Federal Center 61 Forsyth Street, S.W., Suite 23T85 Atlanta, Georgia 30303 Max Batavia, Chief Bureau of Radiological Health South Carolina Department of Health and Environmental Control 2600 Bull Street Columbia, South Carolina 29201 County Supervisor of Oconee County Walhalla, South Carolina 29621
REQUEST FOR ADDITIONAL INFORMATION DUKE ENERGY CORPORATION (DEC)
OCONEE NUCLEAR STATION ELECTRICAL DISTRIBUTION SYSTEM The response to open issue No. 7 states that operating the Oconee unit shutdown loads (approximately 2 MW) are block loaded on the Lee combustion turbines, and additional loads are then manually started until approximately 5 MW is obtained. The shutdown loads, therefore, are apparently deenergized prior to initiation of the test in order to subsequently block load them onto the Lee generator. This conflicts with the response to question A8 in DEC's response to staff questions dated January 31, 1996. That response states that during this test, the required startup equipment for the Oconee unit is not lost since the loads are transferred to the Lee generator without a loss of power.
Please clarify which of these responses is accurate.
If the shutdown loads are indeed briefly deenergized during the Lee test, then readdress the staffs original question relative to your January 31, 1996, response. (Question: If this degree of loading can be obtained on the Lee generators during startup, why can the same test not be performed on the Keowee units?
- 2.
The response provided to open issue No. 9 appears to contradict the information in calculation KC-UNIT 1-2-0098 (Keowee Governor Mechanical Single Failure Analysis) dated September 29, 1993, and calculation KC UNIT 1-2-0106, Rev. 1 (Keowee Power Operating Restrictions for NSM-52966) dated May 4, 1995. The information in the referenced calculations indicates that, when the partial shutdown solenoid is deenergized, the wicket gates are limited to 25 percent open, and when the solenoid is energized there is no limit on the wicket gates. The calculations also indicate that on an emergency start from standby there is initially no limit on gate position, then Keowee speed switch 14/1 operates at 52 rpm to limit the gate position to 25 percent, and speed switch 13/1 operates at 122 rpm to remove the gate limit and return control to the governor. The response to open issue No. 9, however, indicates that on an emergency start the partial shutdown solenoid energizes initially to allow the gates to open to 50 percent and the gate limit is set at 50 percent. Please clarify.
- a.
It also appears from this response that the monthly test performed to meet the technical specifications (TS) is actually a modified normal start, since the auto synchronizer is turned off. Are there any other differences between that start and the normal start?
- b. Is the voltage and frequency the only acceptance criteria specified for the monthly test? What is the specified voltage and frequency acceptance criteria? Is the start time to specified voltage and frequency monitored, and what is its acceptance criteria?
- c.
What are the reasons and difficulties associated with performing an emergency start test on a monthly basis instead of a modified normal start? The modified normal start does not test emergency start gate limit operation, immediate closure of the field circuit breaker, or emergency start relay contacts.
Enclosure
-2
- d. The response to open issue No. 9 indicates that the combination of existing and proposed TS results in three emergency start tests from a dead stop, and four from a running Keowee unit every 2 years. Are these numbers consistent with those provided in the response to open issue No. 44? That response indicates that the Keowee units are emergency started (both standby and hot started) three times per 18 months and a total of 13 times over a 3-year period.
- e.
The response to issue No. 9 also indicates that under current TS there is an 18-month emergency power switching logic (EPSL) functional test that is performed with a "start from dead stop on an ONS [Oconee Nuclear Station] unit." What is the relationship of this test to the EPSL functional test provided to the staff in the January 31, 1996, DEC letter? The test provided to the staff was not a Keowee start from dead stop but rather an emergency start from generating to the grid.
How many EPSL functional tests are from a dead stop and how many are from generating to the grid? Are any of the Keowee starts from dead stop performed as a black start?
- 3.
Are any of the Oconee TS electrical tests referenced in the most recent October 31, 1996, DEC letter going to be eliminated in the technical specification 3.7 rewrite? If so, which ones and why?
- 4.
In the response to open issue No. 28, it is indicated that analysis conducted to evaluate the past operability of the electrical system concluded that all required safety functions would have been accomplished with the voltage at 11.9 kV. In the same response it is stated:
Due to different system loading, it is expected that the voltages required at the terminals of the Keowee generator to assure proper operation of safety loads will vary, depending on which failure scenario is being analyzed. The minimum generator voltage that bounds all cases and scenarios for the Keowee analysis is 13.5 kV.
It is not clear what the differences are that would lead to the conclusion that "all required safety functions would have been accomplished" with the Keowee generator at 11.9 kV, and also conclude that "[t]he minimum generator voltage that bounds all cases and scenarios for the Keowee analysis is 13.5 kV." Please clarify. Also, please list the full complement of failure scenarios that are referred to in the preceding quotation.
- 5.
It is not clear in the response to open issue No. 29 what DEC's final position is. The response states that procedure PTIO/A/0620/09, Keowee Hydro Operation, does not put the Keowee unit through a load run; but it does not indicate why it is not a load run. It references a one-time load run test that was run in August 1996, and states that the test data demonstrates that monthly load runs of Keowee are not necessary in light of the fact that Keowee is frequently operated to the grid. However, the final paragraph in the response states that normal operation of Keowee verifies the first two surveillance requirements (synchronization and load acceptance) in standard TS, and DEC plans to trend data monthly on Keowee operation to the grid in order to verify proper
-3 heat exchanger operation. Please indicate why PTIO/A/0620/09 does not meet the criteria of a load run, and what combination of existing Keowee operation and additional verification will be used to demonstrate the load run criteria is met by the Keowee hydro units.
- 6.
The response to open issue No. 30 indicates that the loss-of-coolant accident (LOCA) signal is verified in step 12.35 of the EPSL functional test that was provided to the staff in a January 31, 1996, DEC letter. It further states that subsequent steps 12.36, 12.37, 12.38, and 12.39 demonstrate that this LOCA signal is providing the emergency start to the Keowee units. In fact, it appears from the procedure that at step 12.35 both Keowee units are already operating. Please verify that the LOCA signal of step 12.35 does not actually start the Keowee units but rather is used to verify logic actuation, contact closure, etc., necessary for the emergency start of the Keowee units. If this is not accurate, explain specifically what steps 12.35 through 12.39 are verifying.
- 7.
The item 8 comment in Attachment 2 notes that a single breaker failure will not cause the lockout of both Keowee units during periods of dual Keowee unit grid generation and a simultaneous ground fault. It states that both air-operated circuit breakers (ACB) 1 and 2 would need to fail in order to lockout both Keowee units in the postulated scenario. These statements are made with regard to a statement made in the NRR report that "[a] subsequent single failure of a safety-related breaker to clear a fault on the overhead emergency power path could potentially cause the lockout of both Keowee units if they were generating to the grid."
The circuit breaker the staff was referring to in the NRR report is not ACB 1 or 2 but rather an oil-operated circuit breaker (OCB) in the switchyard. The postulated failure was a failure of a switchyard OCB to isolate a ground fault in the switchyard or on a transmission line, outside the Keowee differential zone of protection. Such an uncleared ground fault would be seen by the ground fault protection scheme (59G relay) of both Keowee hydro units when they were generating to the grid and cause both units to trip.
Please respond whether this scenario is accurate.
- 8.
The item 13 comment in Attachment 2 indicates that the diesel generator hot restart test is not applicable for the Keowee units because the concern associated with the diesel generator's ability to start at high diesel temperatures does not exist at Keowee.
The staff recognizes that the Keowee hydro units do not necessarily have the same vulnerabilities as diesel units; but are there other vulnerabilities that might be peculiar to the hydros relative to hot starting? The staff notes that in the response to open issue No. 30, DEC has indicated that a hot restart test was performed as part of a load run test on August 22 and 23, 1996.
- 9.
The item 15 comment in Attachment 2 indicates that as a result of NSM ON-52966 the reclosure timers for the Keowee ACBs are set at 8.2 to 8.4 seconds, and the acceptance criterion is that they be greater than 4 seconds. What is the basis for the acceptance criterion? Why is there no upper bound on the acceptance criterion?
-4
- 10.
The item 16 comment in Attachment 2 states that during the standby bus source undervoltage sensing test, each logic chain is actuated to ensure that the resulting retransfer to startup signal is achieved. It indicates that the two-of-three verification is not necessary for the standby bus undervoltage logic since a single failure is necessary in order to require actuation of this logic.
It is not clear what portion of the undervoltage sensing logic this test verifies and does not verify. How many logic chains are there, and is the two-of-three undervoltage signal provided to each logic chain? What types of failures would the test not capture and how is the test conducted?
- 11.
Item 57 in Attachment 2 of DEC's letter, indicates that item 18 in the NRR draft report (page 27) incorrectly states that there is no similar TS requirement at Oconee for the standard diesel generator test of reaching rated voltage and frequency within a specified time. It comments that the annual emergency start test verifies that Keowee can obtain the rated voltage and frequency within the test acceptance limits.
The staff notes that the subject standard TS test referred to in the NRR draft report is a 10-year test of the simultaneous start capability of both diesel generators. Is the annual emergency start test of the Keowee units referred to in the comment to item 57 a test of the simultaneous start capability of both Keowee units? If both units are not emergency started simultaneously from a standby condition in that test, it is not comparable to the subject 10-year test. Is a simultaneous emergency start from standby periodically performed on both Keowee units?
- 12.
The final portion of the response to open issue No. 1 discusses the electrical loading that would occur if emergency core cooling system (ECCS) actuation signals were received during a three-unit Oconee loss of offsite power (LOOP). It indicates that if an ECCS actuation were to occur, only one additional high pressure injection (HPI) pump would be started in each unit, over and above the other HPI pumps and essential loads that were energized by other automatic features during the LOOP event. The response states that the load associated with these additional HPI pumps is smaller than the Oconee LOOP or LOCA loads that are currently analyzed to be block loaded onto an overhead or underground Keowee unit. It concludes, therefore, that the emergency power system would perform its intended function and is bounded by the current analyses.
It is not clear why the fact that the load of the HPI pumps is less than the entire LOOP or LOCA load leads to the conclusion that the current analyses bounds the subject scenario. Is this indicating that, because the loads are staggered during the event, the voltage transients seen are less than those analyzed? If so, how does the final steady state load during this scenario compare to the analyses in terms of voltage and CT4 or CT5 loading capability? Has a three-unit LOCA/LOOP event been analyzed, or does the conservatism used in the CYME analyses bound the three-unit LOCA/LOOP event?
-5
- 13.
In the NRR Draft Report, the staff was concerned that the demand frequencies of components such as relays, for which plant-specific data were calculated by combining all components of the same type into a type code, range from daily (for system grid generation) to quarterly to every refueling outage. Ideally, all components in the same group or type code should have the same or similar periodic testing frequencies. At Keowee, some components that are only challenged every refueling outage are applied the same failure probability as components that are demanded daily. Therefore, the staff concluded in the Draft Report that the results of the generic data sensitivity study are more robust than the base case. In the response dated October 31, 1996, DEC agreed that for an ideal and precise characterization of the reliability of a component, the failure rate data should come from identical components with identical operating, service, testing, and maintenance conditions. DEC also stated that the generic data sources contain no statement of limitations for using the data for any specific-test frequency or class of equipment. The staff believes that the purpose of gathering plant-specific data is to understand what kind of failures are contributing to the plant-specific failure data, how they occur, and when they occur. Analysis of plant specific data allows the analyst to determine whether a set of similar components of one type should be statistically modeled as one population.
In Table E3 of the Keowee Probabilistic Risk Assessment (PRA), DEC identified 12 components that are demanded during an emergency operation with a black start but not during normal operation and are tested less than every week, including Air Circuit Breakers (ACBs) 3-8. DEC stated (in the October 31, 1996, submittal) that the Keowee PRA data base had been reviewed and only one failure of an infrequently test/demanded component was identified.
In the Augmented Inspection Team (AIT) report dated July 30, 1997, several ACB failures involving ACBs 7 and 8 (Section E.2.2.b.2 of the AIT report) were listed. The AIT concluded, based on review of the historical data, that fuse and circuitry design interactions may have contributed to breaker failures.
The staff requests that DEC discuss this discrepancy. Since it appears that failure data for the X and Y relays for these ACBs were quantified using pooled data (as described in Tables C.1-3 and C.1-5), the staff requests that DEC requantify the applicable basic events for ACBs 5, 6, 7, and 8 using plant-specific data specific to the ACBs.