ML20137H494

Proposed Tech Specs Incorporating Addl Restrictions on Operation of MSSVs

ML20137H494
Person / Time
Site:	Fort Calhoun
Issue date:	03/26/1997
From:	OMAHA PUBLIC POWER DISTRICT
To:
Shared Package
ML20137H493	List: LIC-97-0049, Application for Amend to License DPR-40,incorporating Addl Restrictions on Operation of MSSVs ML20137H494
References
NUDOCS 9704020261
Download: ML20137H494 (14)

Text

. _ _ _

.. 2.0

. LIMITING CONDITIONS FOR OPERATION 2.1 Reactor Coolant System (continued) 2.1.6 Pressurizer and Main Steam Safety Valves Anolicability Applies to the status of the pressurizer and main steam safety valves.

Obiective To specify minimum requirements pertaining to the pressurizer and main steam safety valves. )

! Specifications i 1

To provide adequate overpressure protection for the reactor coolant system and steam system, the following safety valve requirements shall be met:

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J (1) The torshall ot be made critical unless the two pre rizer safety valve e operable

i their lift ettin s adjusted to ensure valve opening 2500 psia 2485jsig +1% and 2545 p;ia 2530)sig 1 %.m (2) Whenever there is fuel in the reactor, and the reactor vessel head is installed, a minimum of one operable safety valve shall be installed on the pressurizer. However, when in at least the cold shutdown condition, safety valve nozzles may be open to containment

atmosphere during performance of safety valve tests or maintenance to satisfy this I specification.

y' (3) Whenever me reae:cr is in povver operation, eight of me ten nmin ::can: =fety valves sha!! be Operable vi1 Seir lif: :::ing: adju::ed ic en=re valves on each header opening a: 1000 psia ! 3/ 2%,1015 psia l 3/ 2%,1025 psia 3/ 2%,1040 psia l 3/ 2%, and

. 1050 psia i 3/ 2%.*

Ar isist G^oPbf?thsifiVE Msid Stsia Safet9WilVesT(MSSVs)

• :ssi6cisted ?widf Eaclisteini eneratoEshEllibeiOPNRABLs?in MDDESysnd!2Ndft settings lNdllRat'985 g%3/-2 %[1000lpsigN3/n1010 Mig ?+3/-2 QO25lpsig $3/-2$as p;siG3/j 2$0!

Te[ (WitIilesithirffdtir~bf'ths'fiseLMSSVs assobiaisdlwitlicaelisisam generaf6f OPERABLE, be!in at least HDT STANDBYiwithin 6' hours aixl! HOT

^

SHUTDOWN lwithin an; additional 6(hburs!

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(4) Two power-operated relieiNalvEsTPORVs) shall be operable during heatups and cooldowns when the RCS temperature is less than 515 F, and in Modes 4 and 5 whenever the head is on the reactor vessel and the RCS is not vented through a 0.94 square inch or larger vent, to prevent violation of the pressure-temperature limits designated by Figures 2-1 A and 2-1B.

a. With one PORV inoperable during heatups and cooldowns when the RCS temperature is less than 515*F, restore the inoperable PORV to operable within 7 4

days or be in cold shutdown within the next 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> and depressurize and vent the RCS through at least a 0.94 square inch or larger vent within the following 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

9704020261 970326 PDR ADOCK 050002G5 p PDR

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b. With both PORVs inoperable during heatups and cooldowns when the RCS l' temperature is less than 515*F, be in cold shutdown within the next 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> and

,f',.

depressurize and vent the RCS through at least a 0.94 square inch or larger vent within the following 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

c. , With one PORV inoperable in Modes 4 or 5, within one hour ensure the pressurizer steam space is greater than 53% volume (50.6% or less actual level) and restore the inoperable PORV to operable within 7 days. If adequate steam space cannot be established within one hour, then restore the inoperable PORV to operable within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. If the PORV cannot be restored in the required time, depressurize and vent the RCS through at least a 0.94 square inch or larger vent within the next 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

2-15 Amendment No. 39,17,54,146,161

2.0 LIMITING CONDITIONS FOR OPERATION

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2.1 . Reactor Coolant System (continued)

' / .~1.6 2 Pressurizer and Main Steam Safety Valves (continued)

d. With both PORVs inoperable in Modes 4 or 5 depressurize and vent the RCS through at least a 0.94 square inch or larger vent within the next 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

(5) Two power-operated relief valves (PORVs) and their associated block valves shall be operable in Modes 1,2, and 3.

a. With one or both PORV(s) inoperable because of excessive seat leakage, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> either restore the PORV(s) to operable status or close the associated block valve (s) with power maintained to the block valve (s); otherwise, be in at least HOT SHUTDOWN 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 COLD SHUTDOWN within the following 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

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b. With one PORV inoperable due to causes other the excessive seat leakage, within 1 l hour either restore PORV to operable status or close its associated block valve and remove power from the block valve; restore the PORV to operable status within the following 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in HOT SHUTDOWN 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 COLD SHUTDOWN with the following 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

c. With both PORVs inoperable due to causes other than excessive seat leakage, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> either restore at least one PORV to operable status or close both block valves, j remove power from the block valves, and be in HOT SHUTDOWN 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 COLD SHUTDOWN within the following 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

d. With one or both block valve (s) inoperable, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> restore the block valve (s) to l operable status or place the associated PORV(s) in the closed position. Restore at least {

one block valve to operable status within the next hour if both block valves are  !

inoperable; restore the remaining inoperable block valve to operable within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

Otherwise, be in at least HOT SHUTDOWN 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 COLD SHUTDOWN within the following 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

l Basis The highest reactor coolant system pressure reached in any of the accidents analyzed resulted from a complete loss of turbine generator load without simultaneous reactor trip while operating at 1500 MWt.m This pressure was less than the 2750 psia safety limit and the ASME Section III upset pressure limit of 10% greater than the design pressure.* The reactor is assumed to trip on a "High Pressurizer Pressure" trip signal.

The pressurizer safety valves are required to be calibrated to within 1% of the specified setpoint value using ASME Section XI test methods. ASME Section XI requires that valves in steam service use steam as the test medium for establishing the setpoint. With the presence of a water-filled loop seal, establishing the valve setpoint with steam may result in in-situ valve actuation at pressures outside the 1% tolerance specined. Under transient conditions, it ctedjatahemlveTITwi actuate l arIY5Tess tham 4el e h specified se pomt, which is within th tolerance assumed in the safety nalysis. These analjs6slare based'oh~ahinimtim~of anf;fouf of the fivs? main sisam?ssfetfjalVuiida each main' steam header being OPERABLE?

Thhwenoper5Ied rehehalves4PORVs)~5FeriiTNrelieve RCFrprMthe setting of the pressurizer code safety valves. These relief valves have remotely operated block valves to provide a positive shutoff capability should a relief valve become inoperable. The electrical power for both the relief valves and the block valves is capable of being supplied from an emergency power source to ensure the ability to seal this possible RCS leakage path.

2-15a Amendment No. 54,145,157,161

2.0 LIMITING CONDITIONS FOR OPERATION 2.1 ; Rsactor Coolant System (continued)

/2.1.6 Pressurizer and Main Steam Safety Valves (continued)

Action statements (5)b. and c. include the removal of power from a closed block valve to preclude any inadvertent opening of the block valve at a time the PORV may not be closed due to maintenance.

However, the applicability requirements of the LCO to operate with the block valve (s) closed with power maintained to the block valve (s) are only intended to permit operation of the plant for a limited period of time not to exceed the next refueling shutdown (Mode 5), so that maintenance can be performed on the PORV(s) to eliminate the seat leakage condition.

To deterrnine the maximum steam flow, the only other pressure relieving system assumed operational is the main steam safety valves. Conservative values for all systems parameters, delay times and core moderator coefficients are assumed. Overpressure protection is provided to portions of the reactor coolant system which are at the highest pressure considering pump head, flow pressure drops and elevation heads.

If no residual heat were removed by any of the means available, the amount of steam which could be generated at safety valve lift pressure would be less than half of the capacity of one safety valve. This specification, therefore, provides adequate defense against overpressurization when the reactor is suberitical.

Performance of certain calibration and maintenance procedures on safety valves requires removal from the pressurizer. Should a safety valve be removed, either operability of the other safety valve or maintenance of at least one nozzle open to atmosphere will assure that sufficient relief capacity is available. Use of plastic or other similar material to prevent the entry of foreign material into the open nozzle will not be construed to violate the "open to atmosphere" provision, since the presence of this material would not significantly restrict the discharge of reactor Ian The total relief capacity of the ten main steam safety valv s is 6-54 6.606 x 106 lb/hr. f, following testing, the as found setpoints are outside +/-1% of nominal ' _ geplatvalues, the lves are set to within the +/-1% tolerance. The main steam safety valves were analyzed I6Fa t tal loss of main feedwater flow while operating at 1500 MWtm to ensure that the peak secondary pressure was less than 1100 psia, the ASME Section III upset pressure limit of 10% greater than the design pressure. At the power of 1500 MWt, sufficient relief valve capacity is available to prevent overpressurization of the steam system on loss-of-load conditions.*

The power-operated relief valve low setpoint will be adjusted to provide sufficient margin, when used in conjunction with Technical Specification Sections 2.1.1 and 2.3, to prevent the design basis pressure transients from causing an overpressurization incident. Limitation of this requirement to scheduled cooldown ensures that, should emergency conditions dictate rapid cooldown of the reactor coolant system, inoperability of the low temperature overpressure protection system would not prove to be an inhibiting factor. The effective full flow area of an open PORV is 0.94 in2 ,

Removal of the reactor vessel head provides sufficient expansion volume to limit any of the design basis pressure transients. Thus, no additional relief capacity is required. ,

I References ]

(1) Article 9 of the 1968 ASME Boiler and Pressure Vessel Code,Section III  !

(2) USAR, Section 14.9 (3) USAR, Section 14.10 l (4) USAR, Sections 4.3.4, 4.3.9.5 2-16 Amendment No. 39,17,51,146,161

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U.S. Nuclear Regulatory Comission l LIC-97-0049 ATTACHMENT B 1

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DISCUSSION, JUSTIFICATION AND NO SIGNIFICANT HAZARDS CONSIDERATION DISCUSSION AND JUSTIFICATION l i

The Omaha Public Power District (0 PPD) proposes to revise the Fort Calhoun Station (FCS) Unit No.1 Technical Specifications (TS) 2.1.6, " Pressurizer and '

Main Steam Safety Valves," to incorporate additional restrictions on the Main Steam Safety Valves (MSSVs). These additional restrictions are a result of l recent engineering analyses.  !

BACKGROUND l i

FCS has two Steam Generators (SG), each with one 2 -inch MSSV and four 6 -

inch MSSVs.

lhe purpose of the MSSVs is to limit the secondary system  !

pressure to'less than or equal to 110% of the design pressure of 1000 psia

• when passing 100% of design steam flow.

On January 15, 1997, an internal Condition Report was initiated indicating i that piping pressure losses between the SG and MSSV inlets were not fully  ;

evaluated with respect to MSSV performance or not fully addressed within plant safety analyses which involve MSSV actuation. On January 17, 1997, FCS received a 10 CFR Part 21 report from Asea Brown Boveri - Combustion Engineering (ABB-CE) addressing this as a potential generic issue for plants )

utilizing the CESEC Code. This report recommended that licensees conduct a i review to ensure that the unrecoverable piping pressure losses between the SG  ;

and the MSSV inlets have been fully addressed in applicable safety analyses and to review and adjust MSSV blowdown settings if necessary to assure stable valve operation.

An engineering analysis, independently verified by ABB-CE, was completed by 0 PPD. As a result of considering inlet pressure drop, additional restrictions must be incorporated in TS 2.1.6(3) on MSSVs. Currently TS 2.1.6(3) requires that eight (8) of the ten (10) MSSVs be operable during power operation (defined as reactor critical with power above 2%). The engineering analysis has shown that this requirement must be restricted to one (1) inoperable MSSV per SG.

ANALYSES Calculation of Pressure Losses l

A review of isometric drawings shows that the system is made up of two headers i each having approximately 100 feet of 26 inch ID piping having 1 SG outlet nozzle,1-50% flow limiting venturi, and 5-90= elbows. The pressure drops in '

the main steam lines were then calculated and compared to values used in the plant safety analyses. The resulting identification that these pressure drop considerations had not been addressed in the plant safety analyses led to initiation of the internal Condition Report.

1

, DISCUSSION AND JUSTIFICATION (Continued):

The pressure loss calculation assumed maximum design steam flow through the  !

MSSVs coincident with Main Steam Isolation Valve (MSIV) closure without a reactor trip. The calculated pressure losses due to this configuration are 9.5 psid for main steam header piping losses. This value was confirmed to be  !

conservative by measurements at 100% power conducted under a maintenance work  !

order. Additional pressure drops due to steam flow through the branch inlets <

to the safety valves were calculated at 21.0 psid for the 2 inch MSSV and  !

24.0 psid for the 6 inch MSSVs. (

A review of existing calculations for line losses in the primary system was  ;

conducted and was determined to be 39 psid for the inlets to the primary i safety valves.

Comparison of Valve Blowdown to Calculated Pressure Losses The total losses (line losses and valve losses) of 30.5 psid (2 inch valves) and 33.5 psid (6 inch valves) were compared to the valve blowdown which is checked each refueling outage as part of the required surveillance test. The pressure losses are less than the 39 psid and 40 psid blowdown for the 2 inch and 6. inch valve with the lowest setpoint (respectively). Therefore, the recommendation from the Part 21 to review blowdown settings versus pressure drops to preclude valve chatter was conducted and no changes are required at FCS.

CESEC-III CODE All analyses were performed using the NRC-approved CESEC-III transient I analysis methodology and computer code. The CESEC-III code employs a single- l node model for the SG. As a result, spatial pressure variations within the SG {

cannot be computed by the code. The maximum and minimum secondary side SG )

pressures calculated by the code occur at the top of the tube sheet and at the  !

steam outlet ' nozzle, respectively. '

The CESEC-III model does not allow modeling of individual valves, rather it models sets of valves, one on each SG. Additionally, CESEC-III does not model the 2 inch valves and therefore credit for opening of MS-291 and MS-292 was made by adjusting the valve area. The valve accumulation was increased from 3% to adjust for increased line losses as flow increases during the valve's fl ow. The CESEC-III model allows input of valve accumulation and blowdown for individual valves to address the lift setpoint of the valve at which the valve passes 70% flow and pressure at which the valve passes 100% flow. The MSSV l

characteristics are shown in Figure A.

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DISCUSSION AND JUSTIFICATION (Cont..ned):

Transient Analyses The scope of the-transient analyses was limited to evaluating the pressure drops in the piping run for both the primary and MSSVs to determine the impact on the peak primary and secondary system pressures, and to reflect recent changes. Recent changes include updating the SG parameters to account for -

15.5% effective tube plugging, caused by additional tubes plugged during the 1996 refueling outage, and the presence of the SG orifice plate. Additional cases were also run to investigate the effect of 0% and 20% tube plugging. ,

The applicable transient for peak primary system pressure is the Loss of Load, l and for maximum secondary system pressure is Loss of Feedwater. l The assumptions were that the plant is operating at 1535.6 MW,, (100% power +

2% uncertainty + reactor coolant pump heat), the MSSVs lifted at +3% of their nominal setpoints, the primary safety valve setpoints were adjusted to account for line losses and lifted at +1% of their setpoints, and the pressure losses in the main steam line to the SG wtre added to obtain the maximum secondary system pressure within the SG. Additional cases were evaluated with a +6%

primary safety valve drift since this possibility is described in the Bases to TS 2.1.6.

The modeled CESEC-III MSSV valve areas of 0.4497 2ft were modified to account for piping pressure losses between the SG and MSSVs. Credit for opening of MS-291 and MS-292 was made by adjusting the initial valve area (prior to changing ratio for the pressures losses) to the total with MS-291 and MS-292.

The modeled original valve design's accumulation was modified from the value of 3% to account for piping pressure losses between the SG and the MSSVs and the differential pressure (Ap) developed as a result of flow through the valves.

The modeled valve actuation setpoints were modified to account for the pipe i run Ap that would exist prior to the valve's opening. This value is calculated in a conservative manner which assumes full flow to the lower setpoint MSSVs prior to a higher setpoint MSSV opening.

Results The results are summarized in Table 1. The results confirm that the effective increase in MSSV set pressure caused by the piping pressure losses leading to the primary safeties and MSSVs is acceptable. This is predicated on the fact that only one (1) MSSV may be inoperable per SG. In order to generate acceptable results for the peak secondary pressure case, it was necessary to credit the Low Steam Generator Level Trip (LSGLT) for the Loss of Feedwater s

case. This is consistent with ABB-CE methodology.

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DISCUSSION AND JUSTIFICATION (Continued):

Another methodology change was performed for the peak RCS pressure case for ,

both the Loss of Load and Loss of Feedwater cases, where the All Rods Out scram worths / curves were used instead of the Power Dependent Insertion Limits  ;

(PDIL) curves. The AR0 curves have the smallest initial scram worth as ,

dictated by ABB-CE, and therefore are conservative. An additional assumption  !

made for calculating the peak secondary pressure was that the Pressurizer Pressure Control System was in automatic to maximize primary to secondary heat transfer. I PROPOSED TS CHANGES P

In order to conform to the analyses' conclusions, it is proposed that TS $

2.1.6(3) be revised to require four (4) of five (5) MSSVs associated with each ',

SG be operable. Currently TS 2.1.6(3) states that the MSSVs be operable l during power operation. This is being revised to state Modes 1 and 2 which j are defined as power operation above 2% power, and reactor critical below 2% l power, respectively. The additional -requirements to maintain operable MSSVs l during Mode 2 ensures that over pressure protection is provided when the  !

reactor is critical.

Additionally, TS 2.1.6(3) does not contain any required actions if the LC0 is not met, therefore TS 2.0.1 would be required to be entered. It is proposed that this be revised to require the plant be placed in bot standby within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (Mode 2) and hot shutdown (Mode 3), within an additional 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. This ensures that the plant is placed in a condition where the MSSVs do not perform any safety related function and the Limiting Condition for Operations is not applicable. A total of twelve hours to be subcritical is consistent with other FCS TS and with ABB-CE Improved Standard TS. The setpoints for both the primary safety valves and MSSVs are being revised from pounds absolute to pounds gauge to be consistent with the nameplate values of the valves.

The basis of TS 2.1.6 is being revised to reflect the revised calculated total relief capacity of the ten MSSVs from 6.54 x 10' lb/hr to 6.606 x 10' lb/hr.

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TABLE 1 RESULTS OF LOSS OF LOAD (LOL)

AND LOSS OF FEEDWATER (LOFW) EVENTS Case Number Peak Primary Time Peak Time Pressure (secs) Secondary (secs)

(psia)_ Pressure (psia) l RESULTS OF LIMITING LOSS OF LOAD (LOL) EVENTS Case 1 - Limiting Secondary 2631.6 13.565 1097.42 19.455 Pressure 2 Case 2 - Limiting Primary Pressure 2649.0 11.587 1080.42 16.095 i

Case 3 - Limiting Primary Pressure 2 2742.8 12.400 1088.71 15.002 with +6% primary safety valve drift RESULTS OF LIMITING LOSS OF FEEDWATER (LOFW) EVENTS Case 4 - Limiting Primary Pressure 2 2561.6 46.527 1089.28 49.040 Case 5 - Limiting Secondary 2256.4 36.754 1094.88 42.254 2

Pressure Notes )

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1. These limiting secondary pressure cases assume one MSSV inoperable per SG and the actual effective tube plugging of 15.5% of the SG tubes,

2. These limiting primary pressure cases assume 20% SG tube plugging.

3. This limiting primary pressure case assumes the actual effective tube plugging of 15.5% of the SG tubes. Tube plugging did not have a significant effect on the LOFW results.

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1 FIGURE A l l

1 SECONDARY SAFETY VALVE CHARACTERISTICS j L

1 d

l FRACTIONAL VALVE FLOW AREA FRACTIONAL VALVE FLOW AREA WHEN INLET PRESSURE REACHES WHEN INLET PRESSURE DOES NOT

, GREATER THAN OR EQUAL TO 3% REACH 3% ABOVE THE VALVE SET 1 AB0VE THE SET PRESSURE DURING PRESSURE DURING A TRANSIENT.

A TRANSIENT.

l 2

1.0 1.0 3 '- .

E E

g 0.7 d

2 c'/'

I 1

5 8

a 2

0.7 _ _ _ _ _ _

1 l

1 l

o I o I  :

c:

p: I I o I b i N  ! N

• l

• I 1

I i 0.0 1 I 0.0 1

-21@ fR SSURE 3% -21@ RESSURE VALVE INLET PRESSURE VALVE INLET PRESSURE OPENING CLOSING 6

d ,

BASIS FOR NO SIGNIFICANT HAZARDS CONSIDERATION:

The proposed changes do not involve significant hazards consideration because operation of Fort Calhoun Station (FCS) Unit No. 1 in accordance with these changes would not:

(1) Involve a significant increase in the probability or consequences of an accident previously evaluated.

The Omaha Public Power District (0 PPD) proposes to revise the Fort Calhoun Station (FCS) Unit No.1 Technical Specifications (TS) 2.1.6, " Pressurizer and Main Steam Safety Valves," to incorporate additional restrictions on the Main Steam Safety Valves (MSSVs) as a result of recent engineering analyses.

FCS has two Steam Generators (SG), each with one 2 -inch MSSV and four 6 -

inch MSSVs. The purpose of the MSSVs is to limit the secondary system pressure to less than or equal to 110% of the design pressure of 1000 lbs. per sau. ire inch absolute (psia) when passing 100% of design steam ficw.

The pressure drcps in the main steam lines were calculated. The total losses (line losses and valve losses) of 30.5 psid (2 inch valves) and 33.5 psid (6 inch valves) were compared to the valve blowdown which is adjusted / checked each refueling outage as part of the required surveillance test. The pressure losses are less than the 39 psid and 40 psid blowdown for the 2 inch and 6 inch valve with the lowest setpoint (respectively). Therefore, the recommendation from the Part 21 to review blowdown settings to preclude valve chatter was conducted and there is no concern at FCS. A review of existing calculations for line losses in the primary system was conducted and was j determined to be 39 psid for the inlets to the primary safety valves. l Analyses were then conducted to determine the impact of the total line losses ,

on previously analyzed accidents documented in the Updated Safety Analysis I Report (USAR). The scope of the analyses was to evaluate the pressure drops l in the piping run for both the primary and MSSVs to determine the impact on the peak primary and secondary system pressures. The applicable transient for peak primary system pressure is the Loss of Load, and for maximum secondary system pressure is the Loss of Feedwater. All analyses _ were performed using the NRC-approved CESEC-III transient analysis methodology and computer code.

The assumptions of the analyses were that the plant is operating at 1535.6 MW,, (100% power + 2% uncertainty + reactor coolant pump heat), the MSSVs lifted at +3% of their nominal setpoints, the primary safety valve setpoints were adjusted to account for line losses and lifting at +1% of their setpoints, and the pressure losses in the main steam line to the SG were added l to obtain the maximum secondary system pressure w thin the SG. Additional cases were evaluated with a +6% primary safety valve drift since this possibility is described in the Bases to TS 2.1.6.

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BASIS FOR N0'SIGNIFICANT HAZARDS CONSIDERATION (Continued):

The results from these analyses confirm that the effective increase in MSSV set pressure caused by the piping pressure losses leading to the primary safeties and MSSVs is below the 1100 psia design limit for.the secondary system, and below the 2750 psia design limit for the primary system. This is predicated on the fact that only one (1) MSSV may be inoperable per SG.

Failure of a MSSV is not an initiator of any previously analyzed accident, and therefore the proposed changes do not increase-the probability of an accident previously analyzed. The proposed change to revise TS 2.1.6 to allow only one MSSV per SG to.be inoperable has been shown, utilizing NRC approved methodology, to li. nit the design pressure to values below the design limits.

An administrative change to revise the TS setpoint value for both the primary safety valves and MSSVs from pounds absolute to pounds gauge is proposed to be consistent with the nameplate values of the valves and has no effect on any analyses. Therefore the proposed changes do not involve a significant increase in the probability or consequences of an accident previously evaluated.

(2) Create the possibility of a new or different kind of accident from any accident previously evaluated.

There will be no physical alterations to the plant configuration, changes in operating modes, setpoints, or testing methods. The additional restrictions being incorporated into the TS on MSSV operation will ensure that the design basis limits of 110% of design pressure will be met for the primary and secondary systems for analyzed accidents when considering inlet pipe pressure drops. The possibility of valve chatter being caused by the additional pressure losses identified in the Main Steam lines and MSSVs was reviewed and is not a concern. This is due to the valve blowdown (the difference between a valve's opening pressure and closing pressure) being greater than the pressure losses. Therefore, the proposed changes do not create the possibility of a new or different kind of accident from any previously evaluated.

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BASIS FOR NO SIGNIFICANT HAZARDS CONSIDERATION (Continued):  ;

I (3) Involve a significant reduction in a margin of safety. ]

The proposed change results in a peak primary pressure of 2649 psia (with 1%

primary safety valve drift as allowed by TS 2.1.6) and peak secondary pressure of 1081 psia for the loss of load event compared to 2632 psia and 1075 psia '

documented in USAR Section 14.9. The proposed change results in a peak ,

primary pressure of 2562 psia and peak secondary pressure of 1090 psia for the )

loss of feedwater event compared to 2487 psia and 1052 psia documented in USAR j Section 14.10. The analyses confirm that the primary and secondary systems  ;

will continue to be below their respective design limits of 2750 psia and 1100 =

psia. Therefore, the proposed changes do not involve a significant reduction in a margin of safety.

Therefore based on the above considerations, it is OPPD's position that this proposed amendment does not involve significant hazards considerations as defined by 10 CFR 50.92 and the proposed changes will not result in a condition which significantly alters the impact of the Station on the environment. Thus, the proposed changes meet the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9) and pursuant to 10 CFR 51.22(b), no environmental assessment need be prepared.

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