ML19257B459

Safety Evaluation Supporting Amend 16 to License NPF-4

ML19257B459
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Site:	North Anna
Issue date:	12/28/1979
From:	Office of Nuclear Reactor Regulation
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.

'5, UNITED STATES E

NUCLEAR REGULATORY COMMISSION 3.l Q%g j s.

//. E WASHINGTON, D. C. 20555

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• .....c SAFETY EVALVATIO?l SY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENCMENT NO.16 TO LICENSE NO. NPF 4 VIRGI'lIA ELECTRIC POWER COMPANY NORTH ANNA POWER STATION, U!iIT NO.1 DOCKET NO. 50-338 Introduction This Safety Evaluation Report related to Anendment No.16 to Facility Operating License NPF 4 for the North Anna Power Station, Unit No.1 (North Anna, Unit 1) addresses eight license conditions. Six of the license conditions required certain actions be completed by Virginia Electric and Power Company (the licensee) prior to restart after the first refueling outage. One of the eight license conditions has been revised to require additional action be completed by the licensee prior to restart after the second refueling outage. Also, one license condition has been added at the request of the NRC staff. These license conditions are addressed below in our safety evaluation which p.ovides a basis for removal of License Conditions 2.0.(3).g, 2.0.(3).h, 2.0.(3).i, 2.0.(3).k, 2.D.(3).1 and 2.0.(3).m. the revision of License Condition 2.D.(3).j, and the addition of License Condition 2.D.(3).o.

In addition, this safety evaluation acdresses changes to the Technical Specifications.

The basis for our approval of these changes to the license and their Technical Specifications is provided below.

Finally, Appendix A to this Safety Evaluation Raport which is an integral par of our Safety Evaluation Report related to Amendment No.16, addresses the licensee's request dated November 2,1979 as supplemented for revising the Technical Specifications to reflect plant operation for Cycle 2 operations. Our basis for approval of Cycle 2 operation and the associated Technical Specification changes requested is provided in Appendix A.

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. Long Term Protectio-A ainst Reactor Coolant Overpressurization In Amendment No. 3 to acility Operating License NPF 4 issued April 1, 1978, Licensing Con:ition 2.3.(3).3 stipulated that the licensee was required to install a ong tern means of protection against reactor coolant system over:ressurization orfor to restart after the first refueling cycle.

By letters dated April 17, 1979 and April 23, 1979, the licensee proposed a long ter: solution for reactor coolant system overpressuriza-tion. Our evaluaticn of the licensee's proposal is provided below.

Several instances o' reactor vessel overpressurization have occurred in pressurized water reac ors in which the Technical Speciffcations imple-menting Appendix G :o 10 CFR Part 50 have been exceeded. The proposed design modifications are intended to mitigate the consequences of an overpressurization event. Also, the licensee's proposed modification to administrative procedures and additional operator training are intended to reduce the chance of an overpressurization event from taking place.

We have reviewed the licensee's system for overpressure protection when the reactor coolant system is at low temperatures. The system consists of two separate trains eacn containing a power operated relief valve, an isolation valve and associated circuitry.

Each train contains an annunciator which scunds an alarm in the control room to alert the operator when plant conditions require enabling of the overpressure mit'gation system by manually turning a key lock switch.

In addition, an annunciator is provided in the control room to indicate when the overpressure transient is occurring.

Indication lights are provided on the main control board to indicate power c:erated relief valve and power operated relief valve isolation valve position. The power operated relief valves have multiple set points and during reactor coolant systen high temperature operation are contrclied by the containment Instrument air.

During water-solid modes o# coeration, a three-way solenoid is energized and the pneumatic supply is switched to bottled nitrogen.

Redundant nitrogen reserve tanks are aise provided in the event of a loss of bottled nitrogen supply. At temperatures between 320'F and 140*F both trains of the power operated relief valve system will be enabled by the operation of the key lock switch. In this temperature band the power operated relief valve circuitry will automatically select the "high" setpoints for the power operated relief valves.

In this temperature band the power operated relief valve setpoints will be 500 pourds per square inch gauge f:r nunber 1 and 435 pounds per square inch gauge for number 2.

At temperatures bel:w 140*F the pc ver operated relief valve circuitry will select the "lc " se: points fc

ower operated relief valve actuation.

The low setpoints c:rrespond to 423 counds per square inch gauge for number 1 and 410 pc ncs per scuare inch gauge for number 2.

The multiple se: point sys1.em all:ws sufficient ne: positive suction head to operate 1752 033 o**B "o pO@nL

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. the reactor coolant pumps while providing ample protection to prevent exceeding the 10 CFR Fart 50 Appendix G limits.

Technical Specificaticns require that all but one high head safety injection pump be 1:olated during water solid conditions and also require that a reactce coolant pump not be started in a water-solid condition with one or more reacor coolant system cold legs at or below 320*F when the steam generator temperature is more than 50*F higher than the cold leg temp-erature.

The applicart has shown that in either the mass input case for one high head safety injection pump or the heat input case from the starting of a primary coolant pump when the steam generator temperature is 50*F higher thar. the cold leg, that one power operated relief valve would prevent exceeding the 10.CFR Part 50 Appendix G limits.

The system meets the single failure criteria as only one of the two trains is required for overpressure transient mitigation.

The system has been designed in accordance with the Institute of Electrical and Electronics Engineering Standard 279-1971, " Criteria for Protection Systems," and adequate means for testing and calibration have been pro-vided.

The licensee has further committed through operating procedures to isolate the emergency core cooling system accumulators with power removed or locked out to the isolation valves prior to proceeding to temperatures below 320 F.

We have concluded that the licensee's long term solution to reactor coolant system overpressurization protection is acceptable.

Therefore, Licensing Condition 2.D.(3).G is no longer required and should be removed from Facility Operating License NPF-4 Ambient Temoerature Monitoring System Outside Containment In Amendment No. 5 (May 19,1978) to Facility Operating License NPF-4, License Condition 2.0.(3).i was amended to read that the licensee install and have operational the area ambient temperature monitoring system outside containment. Also, the licensee was required to monitor and log the temperature on a daily basis at areas outside containment as specified in Table 1 (attached to Amendment Nc. 3 to Facility Operating License NPF-4).

In addition, should the temperature in these Class IE areas exceed the associated equipment rating during this period, the licensee was required o demonstrate acceptability of the Class IE equipment in that area.

On December 19, 1979, Our Office o' Inspection and Enforcement notified us that the licensee had complied with tne requirements stated in License Condition 2.D.(3).i (as revised by Arendent No. 5). Therefore, Licensing Condition 2.D.(3).i ar: Taole 1 attached to A endment No. 3 should be removed from Facility "serating License NPF 4, 1752 OM

. Low Head Safety Injection and Recirculation Soray Pumos Following several operational problems noted during the testing of the North Anna Unit 1 deep well pumps, we required the licensee to demonstrate by testing the long-term mechanical operability of the low head safety injection and the outside recirculation spray pumps.

These pumps may be required to operate for long per.iods of time (on the order of months) following a loss-of-coolant accident. The basis for our acceptance of test results for the pumpt ir. question is that pump bearing wear and the amplitude of the pump tibrational frequencies remain at low, satisfactory levels when extrapolated over a period of several months.

The evaluation of our previous concerns regarding the short-term mechanical testing of the outside recirculation spray pumps is provided

.in Supplement No. 9 to our Safety Evaluation Report for the North Anna Power Station, Units 1 and 2 (issued June 4,1976).

Supplement No. 9 also specified additional test requirements which we required for the mechanical testing of the inside and outside recirculation pumps and the low head safety injection pumps.

On April 1,1978, Amendment No. 3 to Facility Operating License NPF-4 was issued and specified as licensing conditions the pump test requirements stated in Supplement No. 9.

Licensing Condition 2.D.(3).k specified our requirements for confirmatory testing of the outside recircalation spray pumps and the long-term testing of the low-head safety injection pumps. Licensing Condition 2.0.(3).1 specified the time seques.;e for pump te: ting and Licensing Condition 2.0.(3).m required the licensee to submit o vibrational mode analysis for the inside recirculation spray pumps. By letters dated June 2,1978, July la,1978 and May 1,1978, the licensee submitted the test results specified in Licensing Conditions 2.D.(3).k, 2.0.(3).1 and 2.0.(3).m, respectively. Our evaluation of the licensee's submittals for these matters is presented below.

Evaluation for Outside Recirculation Spray Pumo Tests As required in Licensing Condition 2.D.(3).k and 2.D.(3).1, the mechanical testing of the outside recirculation spray pump consisted of a 450 hour0.00521 days <br />0.125 hours <br />7.440476e-4 weeks <br />1.71225e-4 months <br /> full-flow pump test conducted at a water temperature of 130*F plus or minus 10*F in order to simulate pst loss-of-coolant accident sump conditions. Boron and sodium hydroxide were added to the test water to also simulate pst loss-of-coolant accident conditions.

Water samples were taken throughout the test to determine the debris concentration of the test water. Debris concentrations for the 450 hour0.00521 days <br />0.125 hours <br />7.440476e-4 weeks <br />1.71225e-4 months <br /> test were determined to be consistent with the concentrations noted during a previous 144 hour0.00167 days <br />0.04 hours <br />2.380952e-4 weeks <br />5.4792e-5 months <br /> test.

1752 035

. We and our consultant, the Franklin Research Center, reviewed and evaluated the outside re:irculation spray pump confirmatory test data.

Cur consultants evaluation of the mechanical testing is documented in its report, " Franklin Desearch Center Technical Report F-C5108-1,"

ca ed April 1979. We and our consultant conclude that the pump mechan-ical test conditions as coa. ducted were representative of the expected post loss-of-coolant canditions.

Peasured pump virbratiar.al frequences were well behaved. Measurements of the pump virbratior levels indicated that the measured vibrational amplitudes were bounded and the measured frequencies agreed with those

redicted by nodal analyses.

The bearing and shaft wear observed at the completion of the test was very low. Based on the bearing.and shaft wear measured after the six hour test, six day test, and 450 hour0.00521 days <br />0.125 hours <br />7.440476e-4 weeks <br />1.71225e-4 months <br /> test, the maximum bearing and shaft wear that would be projected over several months of operation was determined to be en the order of 10 mils or less. Stable bearing and r.2chanical pump performance is expected for wear of this mgnitude.

Sone minor scoring of the shaft journals and bearing surfaces was observed at the completion of the 450 hour0.00521 days <br />0.125 hours <br />7.440476e-4 weeks <br />1.71225e-4 months <br /> pump test. This wear was no greater than the scoring noted at the completion of the six day pump test.

In addition, the scoring did not affect pump performance. Based on our evaluation as stated above, we find that for long-term operability the outside recirculation spray pump will perform its required safety function in the event of a loss-of-coolant accident.

Evaluation Low Head Safety Injection pumo Tests The temperature of the water used for the low head safety injection pump test was maintained a: 130'F plus or Jinus 10 F in order to simulate long-tem post loss-of-coolant sump temperatures. Boron and sodium hydroxide were also added to the test water to simulate post loss-of-coolant sump conditiens. The boron concentration was to be maintained at 1800 parts per million clus or minus 100 parts per million. The initial boron concentration was within this band, but samp!es indicated that the baron concentration decreased throughout the test, eventually reaching about 600 parts per million. However, the boron concentration was maintained at a high enough level during the first few days of the test to subject the pump to the test environment desired. Water ;amples were also taken throughout the test to determine debris concent,ation of the test water.

In addition to normally installed instrumentation, accelerometers and pressure transducers were added along the pump column. Measurements of each shaft journal outside diamnter and bearing inside diameter were taken prior to and at tre compl tion of the test run.

1752 036

. Our consultant's review and evaluation of the low head safety injection pump mechanical test data is documented in it's report, " Franklin Research Center Technical Report FC-5108-2," dated May 1979. We and our consultant concluded that the pump test conditions as conducted were representative of the expected loss-of-coolant accident sump conditions. Also, debris concentrations used during the low head safety injection pump test were consistent with the debris concentrations determined during the outside recirculation spray pump tests and were therefore acceptable.

Measured vibrational frequencies were well-behaved throughout the test, and the pump vibrational amplitude indicated that the pump had reached and maintained a level of stable, satisfactory dynamic operation.

Bearing and shaft wear measured after the test indicated that the maximum total wear that would occur over several months of operation would be on the order of 10 mils or less. Stable bearing and pump performance is expected for wear of this magnitude.

Based on our evaluation as stated above, we find that for lono-term operability the low head safety injection pump will perform its required safety function in the event of a loss-of-coolant accident.

Inside Recirculation Spray pumo Due to the similarity in design between the outside and inside recirculation spray pumps, we did not require separate mechanical testing of the inside recirculation spray pump. However, Licensing Condition 2.0.(3).m did require that the licensee conduct a modal analysis of the insi.e recirculation spray pump.

We and our consultant, the Franklin Research Center, reviewed and evaluated the modal analysis of the inside recirculation spray pump. Our consultant's evaluation of the mudal analysis is documented in " Franklin Research Center Technical Report F-C5108-2," dated May,1979 The modal analysis demon-strated that the vibrational characteristics of the inside recirculation spray pumps were sufficiently similar to the vibrational characteristics of the successfully tested outside recirculation spray pump to provide a basis for comparison.

We and our consultant questioned the advisability of the monthly periodic dry start and stop tests required by surveillance testing for the inside recirculation spray pumps. The licensee in discussions with the pump manufacturce stated that the manufacturer reaffirmed the pump capability for testing in the iry mode. However, to provide continuing assurance for the mechanical reliability of these pumps, we requested that the testing interval for tne inside.ecirculation spray pumps be increased from monthly to once every th ee months. We also required that the inside recirculation spray pumps be removed and inspected at the first 1752 037

. planned major outage w

. pump bearings being replaced if necessary and the pumps be opti ally ali.eu prior to installation.

In addition, we required that a similhr inspet. tion of these pumps be made at least once every five years.

In a letter dated September 4,1979, the licensee committed to changing the surveillance testing interval from monthly to once every three months.

The licensee also committed to remove and inspect the inside recirculation spray pumps at the first refueling outage for North Anna Unit 1 and stated that the pump bearings will be replaced if necessary, and the pumps optically aligned, prior to installation.

The licensee further stated that a similar test would be conducted at least once every five years thereafter. On December 27, 1979 our Office of Inspection and Enforcement notified us that this inspection had been completed and found acceptable.

Based on the satisfactory results of the modal analysis, the similarity in design between the outside and th inside recirculation spray pumps.

and the periodic inspections specified in this report, we conclude that the mechanical reliability of the inside recirculation spray pumps is acceptable to fulfill its required safety function in the event of a loss-of-coolant accident.

Based on our evaluations as stated above, we find that the licensee has met the requirements described in Licensing Conditions 2.D.(3).k, 2.D.(3).1 and 2.D.(3).m.

Therefore, we find that these condit';ns should be removed from Facility Operating License NPF-4 Secondary Water Chemistry - Deletion of Specifications 3/4 7.1.6 and Addition of Licensinc Paracraoh 2.D.(3).o The fiP.C staff recognizes that different utilities use different secondary water treatment methods to limit steam generator tube corrosion.

Moreover, we recongize that a licensee's choice of a particular water treatment method, including specific values of operating limits for chemistry parameters, is governed by plant and site characteristics that are unique to each facility.

In addition, we do not believe at this time that sufficient service experience exists to conclude that any particular method is superior to another for controlling impurities that may be introduced into the secondary coolant. Such experience would be necessary to assure that Technical Specifications on secondary water chemistry will ensure minimum tube degradation.

Restricting the amount of chemical additions to control the water chemistry parameters would not ensure the desired steam generator operating conditions. Realizing that meeting the secondar" coolant water quality criteria would not be ocssible during all periods of operation, it is necessary that tha most effective procedure for re-establishing out-of-s:scification chemistry parameters be available without 1752 038

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unduly restiicting plant operations. This can :e accomplished most rapidly by continuing to operate the unit so t"It chemical additives to the secondary water can be made to achieve a balanced chemistry.

During discussions with the licensee personnel, we were advised that permanent records are kept of all chemical additives usec.

Such records would be available if needed for our future evaluaticas. We consider that these permanent plant records on a sampling prc; ram may be useful in the future.

Thus, inecification 6.10.2,9 was added requiring records of secondary water sampling and water qt.. lity ts retained.

In particular, we have concluded that Technical Szecification 3.7.1.6 for secondary water chemistry does not provide adec; ate flexibility to allow desired water conditions to be achieved g-adually or ensure long term tube integrity.

In addition, these s:e:ifications may not limit specific types of severe tube degradatior, :articularly " denting".

Furthermore, the possible adverse effects of ar, secondary water parameter limits on the steam curity that could lead to :-tential failure of turbine components must also be considered befc e specific limits are required.

We believe that other methods for reducing the imourity concentration in the steam generator such as periodic chemical cleaning for long term solution, fluxing or free surface boiling for an intermediate term solution, or the use of chelating agents for tre control of secondary water purity are more practical. These methods are likely to be more effective in limiting corrosion than specific Technical Specifications that may lack the flexibility needed for proper control of secondary water chemistry. The NSSS vendors are now considering these aiternate methods in lieu of restrictive secondary water chemistry for assuring steam generator tube integrity. We have proptsed license condition 2.C.(3).o requiring the licensee to implement a secondary water chemistry monitoring program to inhibit steam generator ;be degradation.

The licensee has agreed to the program and license :endition.

By letter dated September 20, 1979, the licenses croposed deletion of certain secondary water chemistry specifications.

The existing specifica-tions contain a limiting conditica of operation, yet actual limitations do not exist. The licensee was c determine tre limiting values afte.-

about six months of operation. Then, the values would have been reviewed by the NRC staff and put into existing blank ta:les in Specification 3.7.1.6 if appropriate. However, the licensee :roposed not to establish secondary water chemistry limits.

In addition, other existing Technical Specifica-ion limiting conditions for operation and surveillance requirements for secondary water monitoring requirements provide assurance that steam gene a or tube integrity is not reduced below an acceptable level for adec 1 e margins of safety.

These specifications are:

1752 039

. 1.

Technical Specification 3.7.1.4 - Secondary Water Monitoring Requirements 2.

Technical Specification 3.4.6.2 - Primary to Secondary Leakage Rates 3.

Technical Specification 3.4.5 - Steam Generator Tube Surveillance and Plugging Criterien Based on the discussion above we consider that the delet1on of the secondary water chemistry Technical Specifications taken together with the addition of a license condition requiring a secondary chemistry monitoring program is acceptable and will not cause a significant decrease in margin of safety or involve a significant hazard consideration.

Safety Injection Actua-ice on Two out of Three Chierels :f Low Dressus-izer Pressure.

As a result of our ongoir.g review of the events associated with the March 28 accident at Three Mile Island Unit 2, tne NRC office of Inspection and Enforcement issued a number of IE Bulletins describing actions to be taken by licensees.

IE Bulletin 79-06 (April 14,1979) further called for these licensees to trip the low pressurizer level bistables such that, when the pressurizer pressure reaches the low setpoint, safety injection would be initiated regardless of the pressurizer level.

IE Bulletin 79-06A, Revision 1 (April 18, 1979) modified the action called for in 79-06A by allowing pressurizer level bistacles to be returned to their normal (untripped) opera-ing positions during the pressurizer pressure channel functional surveillance ests.

The effect of tripping the pressurizer low level bistables which are normally coincident with the pressurizer low pressure distables, has the effect of reducing this safety injection actuation logic to a one out of three logic.

A single instrument failure of one of the thee low pressure bistable channels could therefore result in an unwanted safety iWction. To prevent this, the licensee proposed in a October 15, 1979 letter, a design modification which would align the existing pressurizer low presare bistables in a two-out-of-three logic.

Evaluation The proposed modification to the safety injection actuation system entails removing the pressurizer level signal from each of the pressurizer level pressure channel trips and converting the system to a two-out-of-three pressurizer low pressure trip. The instrumentation logic takes pressurizer pressure signals from three pressure trans-itters ard initiates a safety injection actuation wnenever two of the three signals reach the low pressure setpoint of 1765 pounds car square inch gauge. Pese modifications will safisfy the requirements of IEEE 279-1971, and otner star.:ards of installation recaired during the plant constr;c-icn stage. We find these ::ifications acceptable.

1752 040

. We have reviewed the instrumentation and controls aspect of the proposed change in accordance with IEEE-279 and other applicable standards and Regulatory Guides.

The modification eliminates pressurizer level as a required initiating signal to actuate safety injection. The licensee proposes to use a two-out-of-three logic on low pressurizer pressure alone.

Separation of trains will be maintained, testability will be maintained, and verification of proper actuation of the first train can be performed prior to modification of the s'econd train.

We have reviewed the instrumentation power sources and determined that the four 115 volt instrument distribution panels are supplied from independent trains. The vital power is provided by inverters that are energized from auctioneered power sources (Batteries /MCC's). We find this acce: table.

The proposed Technical Specifications revise Tables 3.3-3, 3.3-4, 3.3-5, and 4.3-2 to reflect automatic safety injection actuation on a two-out-of-three pressurizer low pressure of 1765 pounds per square inch gauge. We find the changes to the Technical Specifications to be acceptable.

Based on our review of the licensee's submittal, we conclude that the modifications to the safety injection actuation system logic satisfy the requirements of IEEE 279-1971 and that the associated Technical Specifications are correct; and therefore, are acceptable.

We also conclude that the proposed change will be in accordance with the above standards and guides, and that none of the transient and accident analyses are adversely affected by the change. The only effect y be an earlier SI actuation. Therefore, we find the propcsed change to se acceptable.

Removal of Part Lenoth Control Rods By letters dated August 6, 1979 and October 23, 1979 the licensee requested that the North Anna, Unit 1 Technical Specifications be revised to permit the removal of the part length control rods. The removal has been approved for the other Westinghouse reactors.

The five (5) part length control rods were initially installed to give the operator the ability to suppress xenon induced power oscillations in the axial direction.

The Technical Specifications for North Anna, Unit 1, as now written require that these part length rod cluster control assemblies be withdrawn and excluded from the core at all times during reactor operations.

The part lengtn rod cluster control assemblies are not needed, used or assumed to be available to achieve required reactor shutdown conditions. Therefore, the proposed removal will not cause any change in required reactivity characteristics, or safety margins at full power, low power or shutdown.

In fact, the rem 0 val will eliminate the poten-ial f or par; length rods cropping into ne core curing operation which could cause abnormal flux distribution or reacto-shutdown.

1752 041

. In addition, in order to preserve the current dynamic operation characteristics of the reactor (pressure ' drops, coolant flow rates, etc.) which could be affected if just removal of the part length rod cluster control assemblies were to be performed, the licensee will install thimble plug assemblies in the spaces previously occupied by the part length rod cluster control assemblies.

If found to be necessary during future cycles, the licensee may replace these thumble plug assemblies with either burnable poison rods, neutron source rods, or full length control rods.

The thimble plug assembly consists of a flat base plate with short rods suspended from the bottom surface and a spring back assembly. The twenty short rods, called thimble plugs, project into the upper ends of the guide thimbles to reduce the bypass flow area.

Fuel assemblies interface with the upper core plate and with the fuel assembly top nozzles by resting on the adapter plate. The spring pack is compressed by the upper core plate when the. upper internals assembly is lowered into place.

Each thimble plug is permanently attached to the base plate by a nut which is locked to the threaded end of the plug by a pin welded to the nut. All components in the thimble plug assembly, except for the springs, are constructed from type 304 stainless steel.

The thimble plugs will effectively limit bypass flow through the rod cluster control guide thimbles in the fuel assemblies from which the PLRCCAs have been removed, just as they currently limit bypass flow in those assemblies which do not contain control rods, source rods, or burnable paison rods.

Based on the considerations that 1) the part length rod cluster control assemblies are not needed for reactor operation, 2) that the removal of these assemblies will remove the chance for an abnormal flux distribution or reactor shutdown because of a dropped part legnth rod and 3) that insertion of the thimble plug assemblies will preserve the current dynamic operating characteristics of the reactor, we conclude this change is acceptable.

Therefore, we find acceptable the recoval of the part length control rod requirements from the Technical Specifications.

Environmental Qualification of Barton Models 763 and 764 Lot 1 Transmitter.

In Amendment No. 7 to Facility Operating Licensee NPR-4 (issued July 3,1978),

license condition 2.D.(3)j was revised to redesignate Barton transmitters No. 393 and No. 386/752 to Barton Models No. 763 and No. 764 Lot 1 transmitters respectively. Also, license conditiuns 2.0.(3)j, as amended, further stated the licensee would provide for staff review the test results of qualification testing for the Barton transmitters by October 1, 1978.

On September 29, 1978, Westinghouse provided the restits of the environmental qualification of Barton Models 763 a.1d 764 Lot 1 transmitters.

(Letter Report NS-TMA-1950).

Our conclusions based on these tests, was that the instruments wculd cerform their short term safety functions.

However, we indicated that acditicnal testing should be conducted to ccnfirm their capability for longer terr cost accident monitoring.

1752 042

. On September 14, 1979, Westinghouse orovided the results of these supplemental tests (Letter Report US-TMA-2120). The original tests attempted to demonstrate the qualification of these transmitters by subjecting them to high radiation levels corresponding to sost loss-of-coolant accident conditions and subsequently exposing them to the higher steam temperature conditions, typical of a main steam line break accident. This ccmbination of high radiation and temperature conditions, while not causing the transmitters to fail, resulted in excessive instrument errors. The supplemental tests which followed were based upon radiation levels and subsequent exposure to a steam environment corresponding to loss-of-coolant-accident and main steam line break conditions separately. Acditional tests were also conducted to investigate the effects of radiation and temperature separately and in combination. This was done to promote an understanding of the phenomena which caused the errors and further to provide a bas 1s to support the. conclusion that the transmitters are qualified to operate satisfactorily under the required service conditions. These tests also led to a recall of a number of differential pressure transmitters to correct their temperature compensation.

While the supplemental test results support the conclusions that the instrument will fulfill their required safety function in an accident environment, they do not provide an adequate margin of safe'y with respect to the magnitude of t

observed arrors and time at which they occur.

To reduce the impact of harsh environments on these transmitters, a modified circuit board has been developed.

The modified units, designated as Lot 2, have been tested and pr.liminary results demonstrate an improvement in their response to harsh environments. These units are less susceptable to compensation errors due to their more linear response to temperature changes.

Further, a margin of safety has been provided by testing these instruments to the higher values of temperature and radiation applicable to both loss-of-coolant-accident and main steam line break conditions.

We conclude that the Barton Lot 1 transmitters are accept.iie in the short term to satisfy the Commission requirements. However, further mprovements to obtain a margin to safety are warranted due to tne safety.ignificance of the information provided by these measurements for post accident recovery. Accordingl-y, license condition 2.D.(3)j to Facility Operating Licensee NPF-4 should be revised to require the presently installed Barton Lot 1 tranmitters be modified or replaced with transmitters that have been demonstrated to have a greater tolerance prior to restart after the second refueling outage.

The licensee has agreed to this additional requirement.

1752 043

. Je:raded Grid Volta;e Protection By letter dated August 5, 1979, the licensee submitted proposed Technical Sp2cifications applicable to design modification for degraded grid voltage protection and the interaction off offsite and onsite power systems for N:rtn Anna, Unit 1.

By letters dated Seatecber 12, 1978, October 24, 1978 and January 12, 1979, the licensee provided information in response to our letters dated July 28, 1978, Sept 2mber 27, 1978 and December 1,1978 regarding protection frca degraded grid voltage conditions and the interaction off offsite and onsite power systems for " orth Anna, Unit 1.

Our safety evaluation report for these matters was provided in tne enclosure to car letter to the licensee dated March 20, 1979, wherein we stated that the licensee provisions for protecting North Anna, Unit 1 from degraded grid voltage conditions was acceptedable.

We also stated that the licensee's proposed Technical Specifications were acceatable regarding the design changes for degraded grid voltage protection.

We further stated that implementation of the design changes and associated Technical Specifications should be completed during the first refueling outage for North Anna, Unit 1.

In addition, we required that the tap settings on the plant distribution transformer be optimized and verified by measurements at the earliest available opportunity for worst-case load conditions for two unit operation at Norta Anna, Unit I and Unit 2.

The licensee has demonstrated by analysis that the transformer ta3 settings have been fully evaluated and optimized for worst-case load conditions resulting from two-unit operation. We find this aspect of design to be acceptable.

In addition our office of Inspection and Enforcement will verify the actual in plant measurements at the time of two-unit operation at harth Anna, Unit 1 and Unit 2.

We have reviewed the licensee's proposed Technical Specifications for conformance with our safety evaluation report of March 20,1979 and we fine them to be acceptable.

Qualified Limit Switches for Containment Vahes Within Containment In Amendment No. 3 ( April 1,1979), Licensing Condition 2.0.(3).h specified that the licensee should install qualified stem mounted limit switches for 21 containment isolation valves inside containment prior to startup following the first scheduled refueling outage.

The qualified stem mour.ted limit switches have been installed and the switches are presently being tested to ensure their operability. The operability of the qualified stem mounted limit switches will be verified by car Office of Ins e:: ion and Enforcement prior to plant entry into M:ds 2 operation. Therefore, Licensing Condition 2.D.(3).h should be re 0ved from Facility Caerating License No. NPF 4 1752 044

. Fire Protection 3y letter dated August 6,1979, the licensee proposed revisions to the current

.; orth Anna, Unit 1 Technical Specifications for conformance wi th the corres-

o. ding North Anna, Unit 2 Technical Specifications which are pending.

The current North Anna, Unit 2 Technical Specification 6.2.2 will include

r: visions to allow the fire brigade composition to be less than the ni.imum of at least five members for no more than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> in the event of an unexpected absence. We find this practice acceptable so long as ir ediate action is taken to restore the fire brigade to five members.

The licensee has proposed revising the Unit 1 Technical Specification 6.2.2 by requiring immediate action to restore the fire brigade to a minimum of five members upon the unexpected absence of a fire brigade member.

The licensee's proposed revision for the North Anna, Unit 1 Technical Specification 6.2.2 has been revised and accepted for the pending Unit 2 Te:hnical Specifications. Since the same fire protection provisions are apolicable to both units, we find the change acceptable.

The current North Anna, Unit 1 Technical Specification 3.7.14.2 incorrectly identifies the minimum acceptable low pressure CO2 storage requirement as 10 to 5 tons in the storage tanks. The minimum storage amount should be 3.5 tons as is reflected in the pending Unit 2 Technical Specifications, we find this correction acceptable.

Centrol Room Emercencv Habitability 7"e current North Anna, Unit 1 Technical Specification 3.7.7.1 does not discribe the corrective action to be taken in the event of inoperability of portions of the control room emergency habitability system. The licensee has proposed the revised actions for modes 1,2, 3 and 4 as follows.

a.

With either the emergency ventilation system or the bottled air pressurization system inoperable, restore the inoperable system to operable status within 7 days or be in at least hot standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in at least cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

b.

With both the emergency ventilation system and the bottled air pressurization system inoperable, restore at least one of these systems to operable status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or be in at least hot standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in at least cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />, c.

With one air conditioning s.' stem inoperable, restore the ino:erable system to operable status within 7 days or be in at least hot standby within tne next 6 haurs and in at least cold shutcown witnin the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

1752 045

. d.

With both air conditioning systems inoperable, restore at lust one system to coerable status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or be in at least hot standby witqin the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in at least cold sht tdown within the followinc 33 hours3.819444e-4 days <br />0.00917 hours <br />5.456349e-5 weeks <br />1.25565e-5 months <br />.

The above change has been accepted and incorporated into the pending Unit 2 Technical Specifications.

Since the control room ares is common to both units, we find the licensee's proposed change for updating the North Anna, Unit i Technical Specification 3.7.7.1 to be acceptable.

The current North Anna, 'Jnit 1 Technical Specification 4.7.7.1, specifing the control room emergency habitability systems surveillance requirements, does not include the cross reference to the Technical Specification requirement that the cleanup system oe tested following each replacement of the HEPA or charcoal filter units The licensee's proposed :hange will clarify the system surveillance requirements for the control room area which is common to both units. We have accepted the Technical Specification requirement for pending Unit 2 Technical Specifications and therefore, we fino tne licensee's proposed change for updating the North Anna, Unit 1 Technical Saecifications to be acceptable.

Safeguards Area Ventilation System The current North Anna, 'Jnit 1 Technical Specifications, 4.7.8.1 and 4.7.7.3, for the safeguards area ventilation system, does not include the ;ross reference to the Technical Specifications requirement a t the cleanup system be tested following each replacement of the HEPA or charcoal filter units.

The licensee's proposed change to the North Anna, Unit 1 Technical Specifications 4.7.7.3 and 4.7.3.1 clarify the system surveillance requirements as accepted for the pending Unit 2 Saecifications. Since the safeguards area ventilation system is similar for both Unit I and Unit 2, we find the licensee's proposed change for Nortn Anna, Unit 1 Technical Specifications 4.7.7.3 and 4.7.8.1 to be acceptable.

1752 046

. "cdified Containment Isolation Valve Penetration No. 47 5y letters dated October 25, 1979 and December 10, 1979 the licensee requested a change to the Technical Specifications, Table 3.6.1 (Containment Isolation Valves).

The licensee stated that the present. design of the North Anna Unit i reactor building instrument air system is such that air for instrumentation and control is normally supplied from the reactor contair. ment instrument air ccmpressors. Should this system fail, a manual cross connect valve allows air to be supplied from the auxilary building air compressors. 'Jhen the auxilary building air supply is required an operator must be stationed at the containment penetration to close the manual valve should the need arise.

To avoid the need to continuously station an individual ct the cross connect valve during periods when the auxiliary building air source is being used, the licensee stated that an air operated cross connect / containment penetration valve arrangement will be installed.

The arrangement will consist of two air operated, fail closed containment penetration valves in series installed at penetration No. 47 in place of existing manual isolation valve 1 - IA-54. A phase B signal will initiate containment isolation of the cross connect line.

Also, required control incication will be added in the control room.

The licensee's modification provides automatic containment isolation for system line-up already provided for by use of a manual valve.

Containment isolation is consistent with other systems specified in the Nortn Anna, Unit 1 Final Safety Analysis Report and the requirements of 10 CFR 50 Appendix A, L

Criterion 56.(4).

Installation of tha air operated isolation valves requires revising Technical Specification Table 3.6-1 to delete manual valve 1-IA-54 outside containment.

1-IA-55, is a check valve and qualifies as the automatic valve inside containment for penetration No. 47. The two new air operated fail closed penetration valves, TV-IA-102A and TV-IA-102B, require that TV-IA-10B, which is closest o containment, be listed in Table 3.6.1 as a Phase B valve listing.

In addition, the licensee recuested that valves 1-SA-57 and 1-SA-58, which have seen renumbered be listed as 1-SA-29 and 1-SA-2, respectively, in Table 3.6.1.

'4e find that the replacement of manual isolation valve 1-IA-S4 with the two failed closed valves, TV-IA-102A and TV-IA-102B, will increase the margin of safety over that previously submitted and approved in the North Anna, Unit 1 Final Safety Analysis Report.

Based on the increased margin of safety, we find the licensee's proposed changes to Technical Specification Table 3.6.1 to be acceptable.

1752 047

s

. Reactor Water Storace Level and Alarm Set Points On September 11, 1979, we were informed by the licensee that the Technical Specifications limits for the Reactor Water Storage level and Alarm Setpoints were inconsistent with the Final Safety Analysis Report and the licensee's report on final Net Positive Suction Head dated April 14, 1978.

By letter dated September 13, 1979, the licensee requested that the Technical Specifications be amended to agree with the values specified in the Final Safety Analysis Report. The licensee stated that the current Technical Specification values listed were the necessary " usable" volumes rather than the " contained" volumes called for by the specifications.

The licensee proposed that Technical Specifications 3.1.2.8 and 3.5.5 (Limiting Condition.for Operation) for the _ Reactor Water Storage Tank low volume limit be revised to 475,058 gallons to be consistent with the low level alarm volume specified in the Final Safety Analysis Report. A high volume limit of 487,000 gallons proposed by the licensee will ensure that the Reactor Water Storage Tank Level will remain below the bend line of the tank.

The licensee proposed that tne minimum contained water volume for Technical Specification 3.1.2.7 be revised to 51,000 gallons in order to ensure a backup source at 9,690 gallons for borated water in Mode 5 (Cold Shutdown) and Mode 6 (Refueling). The minimum contained volume takes into account the elevation of the low head safety injection line at a contained volume of 24,742 gallons plus a conservative allowance of 16,568 gallons for required submergence and the 9,690 gallons for a backup source in Mode 5 and Mode 6.

We find the licensee's proposed Technical Specification changes a be acceptable since the proposed changes involve only the correction of values to be consistent with previcusly submitte.! and approved analyses in the

.: orth M.u, ifnic 1 Final Safety Analysis Resort.

Pressure /Temoerature Limits By letters dated August 6,1979 and October 23, 1979, the licensee requested a change to Technical Specification 3/4 4.9.

The licensee's preposed changes in the heatup and cooldown limitations do not decrease the margin of safety against rapidly progating failure required by General Design Criterion 31. Therefore, we find the proposod change to the Technical Specifications to be acceptable.

Environnental Consideration We have determined that the amendment does not authorize a change in effluent types or total anounts nor an increase in power level and will not result in any significant environnental impact. Having made t"is determination, we have further :encluded that the amendment invcives an action which is insignificant from the standpoint of ervironnental inpact and, ;ursuant to 10 CFR 551.5(d)(4), that an e-vironnental impact sta e ent or negative declaration and environ-nental inpact appraisal ree: not be prepared in conn 2ction with -he issuance of this anencre":.

1752 048

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

(1) because the amendnent does not involve a s'gnificant increase in the probability or consequences of accidents previously considered and does not involve a significant decrease in a safety margin, the anendment does not involve a significant Fazarts censideration, (2) there is reasonable assurance that the healtn and safety of the public will not be endangered by operation in the prc:osec manner, and (3) such activities will be conducted in conpliance with the Conmission's regulations and the issuance of this anendment will not be inimical to the common defense and security or to the health and safety of the public.

Date: December 28, 1979

Attachment:

Appendix A to Safety Evaluation Report Related to Cycle 2 Reload 1752 049

APPEN3IX A

_T.,0 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO A'iEND"ENT NO.16 TO LICENSE NO. NPF-4 VIRGINIA ELECTRIC POWER COMPANY NORTH ANNA POWER STATION UNIT NO. 1 DC".KET NO.53-338 1.0 Introduction By letter dated November 2,1979, as sucolemented November 29, December 17 and December 19,1979 (References 1, 2, 3 and 4 respectively), Virginia Electric Power Company recuested amendment of Apoendix A to Facility 0;:erating License NO. NPF 4 for Nor-h Arna Power Station Unit 1.

Section, summarizes the proposed changes of ta.e arendment to the Technical Specifications.

The VEPCO submittal cf November 2,1979 was presented to support coeration of cycle 2, following cycle 1 operation terninating at an average core burnup of between 14,300 and 15,90C M;lD/MTV. The safety analysis is valid for a cycle 2 burnup less than or equal to 10,400 MWD /MTU.

All anticipated operational occurrences and accidents were reviewed. The Large Break Loss of Coolant Accident, Rod Cluster Control Assembly Eject on Accicent from hot zero power, the Main Steam Line Break Accident, the Excessive Heat Removal due to Feedwater System Malfunction and the Excessive '.oad Increase Anticipated Operational Occurrences were reanalyzed. '(See section 3.0)

The Large Break Loss of Coolant Accident (LOCA), was reanalyzed with 54 steam generator tube plugging using the February 1978 currently approved Westing-house LOCA-ECCS Evaluation Model (Reference 5 ).

Additional analyses (References 2, 6

) were performed to assess the potential impact of recert concerns related to the LOCA-ECCS fuel clad models expressed in draft report NUREG-0630 (Reference 7 ).

(See section 3.1) 2.0 Evaluation of Modifications to Core Desian 2.1 Fuel Systems Desien 52 Region 1 fuel assemblies are to be replaced by 52 Region 4 fuel assemblies.

The Region 4 fuel assemblies are mechanically identical to the Region 3 fuel assemblies which were loaded in cycle 1.

Hence, the reload fuel mechanical design was not reviewed again.

No fuel assembly grid or control rodlet an Plies Clad flattening is not predicted to occur during cycl:e 2 have been detected.

(Reference 1 ).

Since fres. and once burnt fuel asse-blies will :e used i-cycle 2, the maximum fuel ex:osure at the end of cycle 2 will be considera:ly less (alr.ost a factor of 2' than the fuel residence time at which fuel clac uel rod bow penalties have ceen collapse would be predic:ec to occur.

r revisec as discussed in section 2.1.2.

The fuel rod internal pressure design basis limits the internal pressure of the lead fuel rod to a value below t.at which would cause 1) the diametrical gap to increase cue to outward cladding and 2) the occurrence of extensive DNB propagation. These criteria and the methodology to assure confomance with these criteria have been previously approved (References 8,9 ).

1752 050

. 2.1.1 Themal-Hydraulic Design Core hydraulic parameters are unaffected by the reload. A reduction of the core inlet temperature associated with steam generator tube plugging is accomnodated within existing (and previously approved) themal limits. These limits were found to provide adequate protection for cycle 2 and have not been recalculated.

Similarly, since the fuel design has not been changed, protection to the fuel centerline temperature limit of 4700*F is assured by continued compliance with a peak linear heat rate for ever power transients of 21.1 kw/ft. Since over-power transients for cycle 2 are predicted to be bounded by results reported in the plant FSAR, compliance with the peak linear heat rate for overpower transients of 21.1 kw/ft is predicted and, in turn, the 4700*F limit will be met.

The minimum fuel temperature predicted for cycle 2 is lower than that assumed in the FSAR analyses. The Excess Load Increase and Excessive Heat Removal due to Feedwater System Malfunction anticipated operational occurrences are affected and hence were reanalyzed (see section 3.3 ). The change of the predicted fuel temperature is attributable to:

(1) adoption of Westinghouse generic 17x17 fuel dimensions and associated manufacturing tolerances (Reference 10) and (2) use of the latest approved fuel performance code (Reference 11).

2.1.2 Fuel Rod Bowing The licensee has requested relief from currently in force fuel rod bowing penalties which were derived assuming fuel rods bowed to contact. This issue has been addressed generically and reduction of the fuel rod bow penalty has been approved by the staff. The generic resolution is applicable to North Anna.

Briefly, Westinghouse has determined that irradiation of a region of fuel up to 33000 MWD /MTU would result in channel closure less than 85% (References 12,

13, 14 ).

The DNBR reductions associated with 85% channel closure are 11.4% for full flow and 14 for N-1 loop operation or for the Loss of Flow u.iticipated operational occurrence (Reference 15).

N-1 loep operation is not permitted by the North Anna Operating License. The staff has concluded that these penalties can be offset by existing thennal margins of 9.1% DNBR (Reference 16), a revised rod bow penalty (see section 5) of 2.3% DNBR units at 33000 MWD /MTU region burnup, and existing margin in the Loss of Flow analysis.

2.2 Nuclear Desian Figure 1 of Reference 1 indicates the core loading arrangement for cycle 2.

The initial enrichments and region average burnup are given in Table 1 of Reference 1.

A conventional 3 fuel region, in-out fuel management scheme has been employed. 304 depleted burnable poison rods originally used in cycle 1 will be inserted in selected Region 3 and 4 fuel assemblies in cycle 2.

These assemblies are predicted to exhibit the maximum assembly average and 1752 051

. fuel pin power densities. The poison rods have been used to suppress local fuel pin power peaking.

(See section 2.2.2) 2.2.1 Kinetics Parareters and Shutdown Marcin V,inetics parameters (i.e., moderator temperature coefficient, doppl temperature coefficient, doppler only) power coefficient, delayed neutron fraction, and prompt neutron lifetime are predicted by the licensee to be within the bounds of limiting values used in the safety analyses. These values were calculated using the methodology described in Reference 17. Values of the kinetics parameters change from cycle to cycle due primarily to changes in average core enrichment, average core burnup, and flux importance weighting of the fuel regions. These values have not changed significantly relat've to cycle 1, and hence values of kinetics parameters for cycle 2 are within the bounds of the 1imiting values used in previous safety analyses.

Shutdown requirerents and margins are shown in Table 2 of Reference 1.

The requirements have been overestimated (conservative direction) and available rod worth underestir.ated (conservative direction).

Shutdown margin (available minus requirements) is in excess of that assumed in the worst cooldown accident, the steam line break at end of cycle.

2.2.2 Peakina Factors Core peaking factors associated with nomal operation are discussed in this section, peaking factors associated with abnormal conditions are discussed in section 3.

The value of the peak enthalpy rise, F g, assumed in the safety analyses and 3

limited by the plant Technical Specifications has not been altered for cycle 2.

The core wide pin peak to core average linear heat generation rate, Fq, is reduced to a value of 2.10 at cated power. This value has been assumed as input to the current LOCA-ECCS evaluation (section 3) and is incorporated in changes to the plant Technical Specifications (section 5). Predicted values of Fxy (z) have increased relative to cycle 1.

Predicted values of Fxy (z) are one of several constraints on the core design. Other constraints include desired fuel enrichment requirements, fuel region utilization,and cycle length.

of Fxy (gner has, for cycle 2, chosen to accept the penalty of higher values The desiz) in order to achieve the desired cycle length. Revised values of Fxy (z) are incorporated in the plant Technical Specifications (section 5) and have been used as assumed input to the Constant Axial Offset Control, CAOC, analyses.

In turn, CAOC analyses have been performed to attempt to show that for the assumed input values of Fxy (z)

( assu :ing operator control tc within 15',' axial shape index units) the predicted value of Fq times normalized power (i.e., the peak linear heat generation rate, during steady state and lead follow operations)will nct exceed the value of the peak linear heat generation rate assured in the LOCA-ECCS analysis. CAOC analyses for cycle 2

(:.eference 3 ) show that, in fact, Fq times normaitzed power may, during load follow operations, exceed the value assumed in the LOCA-ECCS analysis.

1752 052

4 Hence, the cycle 2 CAOC analysea show that operation at full power with control on ex-core instrumen ation alone may not be permitted. Surveillance with the in-core Axial Power Distribution Monitoring System, APDMS, will be required throughout the cycle.

In-core measurements of Fq times normalized power will be obtained, using the APD.'iS, at frequent intervals speci find in the existing plant Technical Specifications. These measurements will ce performed to assure compliance with the asstStions of' the LOCA-ECCS analysis.

3.0 Safety Analyses Each anticipated operational occurrence and accident originally reported in the plant FSAR has been reviewed for cycle 2 by the licensee. The FSAR analyses ? e intended to be a bounding set of analyses for first and subsequent fuel cycl es.

In general this has proven true. Only those accidents affected by the reload core, or by modeling changes in calculational methodology sub-sequent to acceptance of the FSAR, have required reanalysis. An exception to this statement is the large break Loss of Coolant Accident which was reanalyzed to incorporate 5% steam generator tube plugging. Approximately 35 of the steam generator tubes were plugged during the refueling shutdown.

3.1 LOCA-ECCS Analysis The analysis (References 2, 4 ) was performed with the current approved (Reference 5 ) February 1978 version of the Westinghouse LOCA-ECCS evaluation model which is in compliance with Appendix K to 10CFR50.

Results of the analysis are in compliance with the requirements of 10CFR50.46, A. eptance Criteria for Emergency Core Cooling Systems for Light Water Reactors.

Previous analyses for a spectrum of breaks were performed using the October 1975 Westinghouse model. These analyses showed that the double-ended cold leg guillotine, DECLG, pipe break with a discharge coefficient, CD=0.4, was lim' ing. The plant was predicted tc be steam cooling limited exhibiting a peak clad temperature, PCT, of 2198'F for an assumed Fq of 2.21.

Current analyses of the DECLG break were performed with discharge coefficients of CD=0.4 and 0.6.

Based on these analyses the plant is predicted to remain steam cooling limited; an assumed CD of 0.4 continues to be limiting. A PCT of 2088'F for an assumed Fq of 2.10 is predicted.

All assumptions and initial operating conditions used in the reanalysis are stated by the licensae to be the same as those used in previous analyses with the following exceptions:

(1 ) Fq was reduced from 2.21 to 2.10 (2) Core power was reduced to 102% of current power rating of 2775 MW.

t (3) Reactor coolant system cold leg temperature of 550*F was assumed versus 555'F.

(4) Credit has been taken for as-buil plant containment heat sink dimensions. A 35 Jncertain:y hb been added to all surface areas.

(5) Credit has been taken for paint on carbon steel surfa:es.

(5) Generic 17x17 fuel parameters have been used.

(7) 5% steam generator tube plugging has been assumed.

(8) The February 1978 version of the Westinghouse LOCA-ECCS Evaluation Model was used.

1752 053

. Additinnal analyses have been performed to assess the potential impact rif recent concerns related to the LOCA-ECCS fuel clad models included in draft report NUREG-0630 (Reference 7 ).

The Westinghouse Large Break ECCS model uses data for fuel clad burst conditions associated with a clad heatup rate of 25'F/second. Adoption of Westinghouse data for fuel clad burst conditions associated with an 11 F/second heat up rate, the current value predicted for North Anna, will result in a predicted PCT (during steam cooling of the non-burst peak mode) of 2195'F for an assumed Fq of 2.10 (Reference 2 ).

Total adoption of NRC fuel clad burst data would:

(1) in-crease the burst node clad temperature, however, the plant would remain steam cooling limited, (2) increase the non-burst node PCT by 78'F due to an assumed increased channel blockage from 32.5% to 75'; (the maximum value for the NRC data), (3) increase the peak non-burst node temperature at the peak non-burst evaluation of 7.5 ft by an additional 61*F due to an increase in the burst node temperature at the 6 ft. elevation. These changes would result in a net increase of the predicted PCT by 139'F from the 2195'F value. This change would be accommodated by a decrease in Fq of 0.13.

The permissi ble maximum Fq at rated power cited in the plant Technical Specifications would be reduced from 2.10 to 1.97.

Westinghouse has sabmitted modifications to thair standard ECCS evaluation model on two reload applications. These changes involve ?e slip and break flow models and have been approved for UHI plant application after extensive review. It is estimated that the total benefit of use of these models would be an increase of 0.38 units in Fq.

If credit for horizontal slip is dis-missed and an added uncertainty is assessed for translation of a -hemomenon at blowdown to an effect during reflood, and for the extrapolation of results of sensitivity studies on 4 loop plants to a 3 loop plant (North Anna), it is our current best technical judgement that application of these model changes to North Anna analyses would result in an increase of the permissible Fq of 0.15 (Refarence 18).

Based on these considerations, we conclude that the value of Fq at rated power of 2.10 be incorporated in the North Anna Technical Specifications.

3.2 Rod Droo VEPC0 has formally committed (Reference 19 ) to operating restrictions on the insertion of control bank D while operating in the Automatic Rod Control mode. Such action will preclude inadvertent reactivity insertion in the event of a control rod drop and potential concommittant pwer overshoot.

3.3 Excessive Heat Removal Oue to Feedwater System Malfunction and Excessive Heat Removal These anticipated operational occurr2nces, A00's, were reenalyzed using a reduced initial pellet temperature (see section 2). The effect of the reduction of pellet temperature and corresponding changes in gap conductivity is a delay in the transfer of stored energy from the pellet to the moderator.

System parameters for these A00's are shown in Reference 3 The change of fuel temperature from the FSAR to cycle 2 analyses resulted in negligble pre-dicted change of the plant response.

1752 054

. 3.4 Trio Reactivity and Loss of Flow The normalized reactivity worth as a function of rod position has been revised to incorporate post FSAR methodology. As shown in Figure 15.1-3 of Reference 3, the change is small. An evaluation of the effect of the change on the Loss of Flow transient, i.e., the transient most sensitive to the trip reactivity curve, shows negligible impact. The change is due to the calculation of trip reactivity from full power rather than zero power and hence shows the conservative effect of use of a flux importance shape which is more bottom core peaked at full power than at zero power.

3.5 Rod Cluster Control Assembly Accident As a result of the cycle 2 fuel management,the predicted ejected rod worth at BOL, het zero power, and the predicted post ejection three dimensional power peak at BOL and EOL were in excess of the values used in the FSAR anal yses. Calculations were performed using the standard approved methodology.

In order to meet design limits on the maximum clad temperature, the feedback reactivity weighting function was increased. The change in the weighting function is based on the approved methodology described in Reference 20.

3.6 Steam Line Break Accident Analyses As a result of the cycle 2 fuel management scheme,the peak enthalpy rise during plant cooldown with all rods except the highest worth rod cluster control assembly,is predicted to be in excess of the value used in the FSAR analyses.

It is noted that if all control rods scram,DNBR limits are not challenged.

If one control rod fails to insert,as is assumed in this design basis analysis,then DNBR limits may be challenged in the vicinity of the stuck rod. The licensee has taken credit for a reduction of the predicted return to power from 13.7% of power in the FSAR analysis to 6.92".

of rated power for cycle 2 in the DNBR calculations for this accident.

The reduction of the predicted return to power is attributed to revision of the calculated power coefficient. The power coefficient used in the FSAR Steam Line Break analysis was calculated at full flow and used throughout the transient which assumes loss of off site power and hence loss of flow.

The cycle 2 power defect was calculated as a function of coastdown flow.

Based on the large margin of safety inherent in the analysis, which is asserted by the licensee to meet condition II criteria (no DNBR), and the regulatory criteria of 10 CFR 100 (limited fuel damage permitted), the steam line break accident analysis is acceptable for cycle 2.

1752 055

7~

mm m

9 9

Wd o

.a 4.0 Startup Tests Procram Startup tests are described in References 1, 21, 22. These tests are consistent with the star:up tests perfomed in association with other recent The tests ' ave been reviewed in terns of their intended VEPCO reloads.

r purpose. A startup repo-t will be provided (Reference 3 ).

-.d Technical Specification Chan;es Proposed modifications tc t5c plant Technical Specifications are described bel ow.

These proposed c"ar ges ar'e acceptable.

1.

Technical Specificatior 4.2.2.2.e

.Fxy at rated thermal pcwe-has been increased to conform to the assumptions of the Constant Axia' C" set Control analyses. This change is necessary to preserve the margin O' safety.

2.

Technical Speci ficatf or 4.2.2.2.f.4 Reference to part le g:5 control rods has been deleted. These rods are

" locked out" of the core. This change is editcrial.

3.

Technical Specificatf or. Figure 3.2-3 The rod bow penalty fraction versus region average burnup has been sig-nificantly reduced. Based on experiments, analyes and review (see section 2.1.2) this enange reflects the current technical assessment of rod bow penalties ard 1ence does not decrease the margin of safety.

4.

Technical Specificatior 3.2.2, 3.2.6, 3/4 2.1 and Figure 3.2-2 Values of Fq at rated power have been reduced from a value of 2.21 to 2.10 and values of K(z), the nomalized Fq (z) as a function of core height, have been revised to be consistent with the current LOCA-ECCS analysis.

These changes are necessary to preserve the rnargin of safety.

6.0 Summary of Environmental and Safety Considerations We have determined that Cycle 2 operation, the procosed action, would not involve a change in ef31uent types or total amounts nor an increase in power level and will no; result in any significent environmental impact. Having made this determination, we have further concluded that this action is insignifi:ar: from the standpoint of environmental impact and, pursuant to 10 CFR I5:.f(d)(4), that an environmental impact state-ment or negative declara-i:

and env ronmental 1 cact appraisal need not be prepared in connectic-S-this tction.

1752 056

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

(1) because Cycle 2 operation, the proposed action, would not involve a significant increase in the probability or consequences of accidents previously considered and will 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 Commission's regulations and this action will not be inimical to the common defense and security or to the health and safety of the public.

1752 057

s

References:

l (1) Letter from C. M. Stallings (VEPCO) to H. R. Denton (NRC), Serial No. 867, November 2,1979, Request for Amendment to Coerating License, Proposed Technical Specification Change No. 24, North Anna Power Station, Unit No.1.

i (2) Letter from C. M. Stallings (VEPCO) to H. R. Denton (NRC), Serial No. 986, November 29, 1979, Request for Amendment to 0::erating License, Propond Technical Specification Change No. 27, North Anna Power Station, Units 1 and 2.

(3) Letter from C. M. Stallings (VEPCO) to H. R. Denton (NRC), Serial No.1136, December 17, 1979, Supplemental Information to Request for Amendment to Operating License, Proposed Technical Specification Change No. 24, North Anna Power Station, Lni.t 1.

I (4) Letter from C. M. Stallings (VEPCO) to H. R. Centon (NRC), Serial No. 986B, December 19, 1979, Supplemental Information tc Request for Amendment to Operating License, Proposed Change No. 27, ' orth Anna Power Station, Units 1 and 2.

i (5) Letter from J. F. Stolz (NRC) to T. M. Anderson (Westinghouse),

August 29, 1978, i

t (6) Letter from T. M. Anderson (Westinghouse) to D. G. Eisenhut (NRC),

I Serial No. NS-TMA-2174, December 7,1379.

t 1

(7) Powers, Meyers, " Cladding Swelling & Rupture Models for LOC / Analysis,"

Draft Report, NUREG-0630, November 1979.

(8) Risher, D. H. et. al., " Safety Analysis for the Revised Fuel Rod Internal Pressure Desiga Basis," WCAP-8964, June 1977.

(9) Miller, J. V. (ed) " Improved Analytical Models Used in Westinghouse Fuel Rod Design Computations," WCAP-8720 (Proprietary) and WCAP-8795 (Non-Proprietary), October 1976.

1 (10) Table 4.4-1, Revision 33, February 7,1975 to the North Anna Power Station, i

Units 1 and 2, Final Safety Analysis Report, Docket Nos. 50-338 and 50-339, i

dated January 3,1973.

(11 )

J. V. Miller, et. al. " Improved Analytical Models Used in W Fuel Rod Design Computations," November 1376, WCAP-8720.

(12 )

J. R. Reavis, et. al., " Fuel Rod Bowing," W:AP-8692, December 1975, Westinghouse Electric Corporation.

(13) " Rod Bow Effects in Westinghouse Fuel," Westinghouse (E. Eiche1dinger) to NRC (D. F. Ross) letter, NS-E-1530, dated October 24, 1977, 1752 058

a (14) " Fuel Rod Bowing," Westinghouse (T. M. Anderson) to NRC (D. F. Ross, Jr.)

letter, NS-TMA-1760, da.ted May 25, 1978.

(15) " Staff Review of WCAP-8691," NRC (J. F. Stol:) to Westinghouse (T. M. Anderson) letter dated April 5,1979.

(16) " Interim Safety Evaluation Report on Effects of Fuel Rod Bowing on Thermal Margin Lalculations for Light Water Reactor (Revision 1),"

U. S. Nuclear Regulatory Commission, February 16, 1977.

(17)

F. M. Bordelon, et. al.," Westinghouse Reload Safety Evaluation Methodology," WCAP-9272, March 1978.

(18)

G. N. Lauben (NRC) to R. P..Denise (NRC), " Review Status of Considered Revisions to Vendor ECCS Evaluation Models," memorandum, December 21, 1979.

(19) Letter from C. M. Stallings (VEPCO) to H. R. Denton (NRC),

Serial Number 973, December 17,1979, " Procedural Changes Required to Address Control Rod Drop Analysis Changes."

(20) Risher, D.

H., "An Evaluation of the Rod Ejection Accident in Westinghouse Pressurized Water Reactors Using Spatial Kinetics Methods," WCAP-7588, Revision 1-A, January 1975.

(21) Letter from C. M. Stallings (VEPCO) to E. G. Case (NRC),

Serial Number 272, May 11,1978, transmitting Supplemental Information to Amendment to the Operating License, Technical Specifications Change No. 65, Surry Power Station, Units 1 and 2.

(22) Letter from W. N. Thomas (VEPCO) to H. R. Denten (NRC),

Serial Number 581, October 13,1978, (VEP-FRJ-30, "Surry Unit 1, Cycle 5 Startup Physics Test Report, Virginia Electric and Power Company").

1752 u59