Text

Amends 117 & 99 to Licenses DPR-53 & DPR-69,respectively, Changing Tech Spec to Revise Basis for Containment Isolation Signal/Safety Injection Actuation Signal Setpoint
	ML20141G277
Person / Time
Site:	Calvert Cliffs
Issue date:	04/14/1986
From:	Thadani A; Office of Nuclear Reactor Regulation
To:	; Baltimore Gas & Electric Co (BGE)
Shared Package
ML20141G283	List: ML20141G277; ML20141G295;
References
	DPR-53-A-117, DPR-69-A-099 NUDOCS 8604230344
	Download: ML20141G277 (59)
	v • d • e

._

'o UNITED STATES

=

NUCLEAR REGULATORY COMMISSION o

h WASHINGTON, D. C. 20555

%,...../

BALTIM0RE GAS AND ELECTRIC COMPANY DOCKET N0. 50-317 CALVERT CLIFFS NUCLEAR POWER PLANT UNIT N0. 1 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No.117 License No. DPR-53 l

1.

The Nuclear Regulatory Commission (the Commission) has found that:

A.

The applications for amendments by Baltimore Gas & Electric Company (the licensee) dated February 22, 1985 and October 25, 1985, comply with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Comission's rules and regulations set forth in 10 CFR Chapter I; B.

The facility will operate in conformity with the applications, the provisions of the Act, and the rules and regulations of the Comission; l

C.

There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Comission's regulations; D.

The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E.

The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

8604230344 860414 I

PDR ADOCK 05000317

0 e 2.

Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 2.C.(2) of Facility Operating License No. DPR-53 is hereby amended to read as follows:

(2) Technical Specificaticns The Technical Specifications contained in Appendix A, as revised e

through Amendment No.117, are hereby incorporated in the license.

The licensee shall cperate the facility in accordance with the Technical Specifications.

3.

This license amendment is effective as of the date of its issuance.

FORTH/NUCLEARREGULATORYCOMMISSION

$ hbF M^

~

AshofC.Thadani, Director PWR Project Directorate #8 Division of PWR Licensing-B

Attachment:

Changes to the Technical Specifications Date of Issuance: April 14, 1986

\\

s ATTACHMENT TO LICENSE AMENDMENT NO.117

~

FACILTIY OPERATING LICENSE N0. DPR-53 DOCKET NO. 50-317 Replace the following pages of the Appendix "A" Technical Specifications with the enclosed pages.

The revised pages are identified by amendment number and contain vertical lines indicating the areas of change.

The corresponding overleaf pages are provided to maintain document completeness.

Remove Pages Insert Pages B 2-5 B 2-5 3/4 1-6 3/4 1-6 3/4 1-11 3/4 1-11 3/4 3-40 3/4 3-40 3/4 3-41 3/4 3-41 3/4 3-41a 3/4 3-42 (no change) 3/4 4-5 3/4 4-5 3/4 5-5 3/4 5-5 3/4 5-Sa 3/4 5-Sa 3/4 6-1 3/4 6-1 3/4 6-26 3/4 6-26 3/4 7-61a 3/4 7-61a B 3/4 3-2 B 3/4 3-2 B 3/4 5-2 B 3/4 5-2 B 3/4 7-1 B 3/4 7-1 6-18a 6-18a J

LI'MITING SAFETY SYSTEM SETTINGS BASES X~

g operation of the reactor at reduced power if one or two reactor scolant pumps are taken out of service. The low-flow trip setpoints and Allowable Values for the various reactor coolant pump combinations have been derived in consider & tion of instrument errors and response times of equipment involved to maintain the DNBR above 1.23 under normal operation and expacted transients.

For reactor operation with only two or three reactor coolant pumps operating, the Reactor Coolant Flow-Low trip setpoints, the Power Level-High trip set-points, and the Thermal Margin / Low Pressure trip setpoints are automatically changed when the pump condition selector switch is manually set to the desired two-or three-pump position. Changing these trip setpoints during two and three pump operation prevents the minimum value of DNBR from going below 1.23 during normal operational transients and anticipated transients when only two or three reactor coolant pumps are operating.

Pressurizer Pressure-High The Pressurizer Pressure-High trip, backed up by the pressurizer code safety valves and main steam line safety valves, provides reactor coolant system protection against overpressurization in the event of loss of load without reactor trip. This trip's setpoint is 100 psi below the nominal lift setting (2500 psia) of the pressurizer code safety valves and its concurrent operation with the power-operated relief valves avoids the unde trable opera-tion of the pressurizer code safety valves.

Containment Pressure-High The Containment Pressure-High trip provides assurance that a reactor trip is initiated prior to, or at least concurrently with, a safety injection.

Steam Generator Pressure-Low The Steam Generator Pressure-Low trip provides protection against an excessive rate of heat extraction from the steam generators and subsequent cooldown of the reactor coolant. The setting of 685 psia is sufficiently below the full-load operating point of 850 psia so as not to interfere with normal operation, but still high enough to provide the required protec-tion in the event of excessively high steam flow. This setting was used with an uncertainty factor of + 85 psi which was based on the main steam line break event inside containment 7 CALVERT CLIFFS - UNIT 1 B 2-5 Amendment No. 33,f $,7J,$$,117

.]

LIMITING SAFETY SYSTEM SETTINGS BASES Steam Generator Water Level The Steam Generator Water Level-Low trip provides core protection by preventing operation with the steam generator water level below the minimum volume required for adequate heat removal capacity and assures that the pressure of the reactor coolant system will not exceed its Safety Limit. The specified setpoint in combination with the auxiliary feedwater actuation system ensures that sufficient water inventory exists in both steam generators to remove decay heat following a loss of main feedwater flow event.

1 Axial Flux Offset The axial flux offset trip is provided to ensure that excessive axial peaking will not cause fuel damage. The axial flux offset is determined from the axially split excore detectors. The trip setpoints ensure that neither a DNBR of less than 1.23 nor a peak linear heat rate which corresponds to the temperature for fuel centerline melting will exist as a consequence of axial power maldistributions. These trip set-points were derived from an analysis of many axial power shapes with allowances for instrumentation inaccuracies and the uncertainty associated with the excore to incore axial flux offset relationship.

Thermal Margin / Low Pressure The Thermal Margin / Low Pressure trip is provided to prevent operation when the DNBR is less than 1.23.

The trip is initiated whenever the reactor coolant system pressure signal drops below either 1875 psia or a computed value as described below, whichever is higher. The computed value is a function of the higher of AT power or neutron power, reactor inlet temperature, and the number of reactor coolant pumps operating. The minimum value of reactor coolant flow rate, the maximum AZIMUTHAL POWER TILT and the maximum CEA deviation permitted for continuous operation are as:;umed in the genera-tion of this trip, function.

In addition, CEA group sequencing in accor-dance with Specifications 3.1.3.5 and 3.1.3.6 is assumed.

Finally, the maximum insertion of CEA banks which can occur during any anticipated operational occurrence prior to a Power Level-High trip is assumed.

CALVERT CLIFFS - UNIT 1 B 2-6 Amendment No. 33, W,AB, 7//, g g s

REACTIVITY CONTROL SYSTEMS MODERATOR TEMPERATURE COEFFICIENT LIMITING CONDITION FOR OPERATION 3.1.1.4 The moderator temperature coefficient (MTC) shall be:

Less positive than 0.7 x 10-4 ak/k/ F whenever THERMAL POWER 0

a.

is < 70% of RATED THERMAL POWER.

b.

Less positive than 0.2 x 10-4 Ak/k/ F whenever THERMAL POWER is > 70% of RATED THERMAL POWER, and Less negative than -2.7 x 10-4 Ak/k/ F at RATED THERMAL POWER.

0 c.

APPLICABILITY: MODES 1 and 2*#

ACTION:

With the moderator temperature coefficient outsife any one of the above limits, be in at least HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS 4.1.1.4.1 The MTC shall be determined to be within its limits by confirmatory measurements. MTC measured values shall be extrapolated and/or compensated to permit direct comparison with the above limits.

With Kef f " 1.0.

See Special Test Exception 3.10.2.

CALVERT CLIFFS - UNIT 1 3/4 1-5 Amendment No. AS, SS,104

REACTIVITY CONTROL SYSTEMS SURVEILLAllCE REQUIREMENTS (Continued) 4.1.1.4.2 The MTC shall be determined at the following frequencies and THERf1AL POWER conditions during each fuel cycle:

a.

Prior to initial operation above 5% of RATED THERMAL POWER, after each fuel loading.

b.

At any THERMAL POWER above 20% of RATED THERMAL POWER, within 7 EFPD after initially reaching an equilibrium condition at or above 90% of RATED THERMAL POWER.

c.

At any THERMAL POWER, within 7 EFPD of reaching a RATED THERMAL l

POWER equilibrium boron concentration of 300 ppm.

I O

i o

1 CALVERT CLIFFS - UNIT 1 3/4 1-6 Amendment No. S/F,117

~,

o REACTIVITY CONTROL SYSTEMS CHARGING PUMPS - OPERATING LIMITING CCNDITION FOR OPERATION l

3.1.2.4 At least two charging pumps shall be OPERABLE.*

APPLICABILITY: MODES 1, 2, 3 and 4.

ACTION:

With only one charging pump OPERABLE, restore at least two charging pumps to OPERABLEstatuswithin72hoursorbeinatleastHOTSfANDBYandboratedto a SHUTDOWN MARGIN equivalent to at least 3% ak/k at 200 F within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ; restore at least two charging pumps to OPERABLE status within the next 7 days or be in COLD SHUTDOWN within the next 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SURVEILLANCE REQUIREMENTS 4.1.2.4 At least two charging pumps shall be demonstrated OPERABLE:

a.

At least once per 18 months by verifying that each charging pump starts automatically upon receipt of a Safety Injection Activation Test Signal.

b.

No additional Surveillance Requirements other than those required by Specification 4.0.5.

Above 80% RATED THERMAL POWER the two OPERABLE charging pumps shall have independent power supplies.

CALVERT CLIFFS - UNIT 1 3/4 1-11 Amendment No. 4, A04,117

=

REACTIVITY CONTROL SYSTEMS BORIC ACID PUMPS - SHUTDOWN 2

LIMITING CONDITION FOR OPERATION 3.1.2.5 At least one boric acid pump shall be OPERABLE and capable of being powered from an OPERABLE emergency bus if only the flow path through the boric acid pump in Specification 3.1.2.la above, is OPERABLE.

APPLICABILITY: MODES 5 and 6.

ACTION:

With no boric acid pump OPERABLE as required to complete the flow path of Specification 3.1.2.la, suspend all operations involving CORE ALTERA-TIONS or positive reactivity changes until at least one boric acid pump is restored to OPERABLE status.

SURVEILLANCE REQUIREMENTS 4.1.2.5 No additional Surveillance Requirements other than those required by Specification 4.0.5.

f i

j CALVERT CLIFFS - UNIT 1 3/4 1-12 l

l

. - ~.

f 4

TABLE 4.3-6 9

REMOTE SHUTDOWN MONITORING INSTRUMENTATION SURVEILLANCC REQUIREMENTS r-si 5;

CHANNEL CHANNEL e,

CHECK CALIBRATION i

[

INSTRUMEt!T A

M N.A.

1.

Wide Range Neutron Flux 9

EE 2.

Reactor Trip Breaker Indication M

N.A.

Z 3.

Reactor Coolant Cold leg Temperature M

R M

R 4.

Pressurizer Pressure M

R 5.

Pressurizer Level 6.

Steam Generator Level (Wide Range)

M R

R M

R 7.

Steam Generator Pressure i

ts E

=

i e

30 l

n CD

INSTRUMENTATION POST-ACCIDENT INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.3.6 The post-accident monitoring instrumentation channels shown in Table 3.3.10 shall be OPERABLE.

t i

APPLICABILITY:

MODES 1, 2 and 3.

ACTION:

a.

As shown in Table 3.3-10.

b.

The provisions of Specification 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.3.3.6 Each post-accident monitoring instrumentation channel shall be demonstrated OPERABLE by norformance of the CHANNEL CHECK and CHANNEL 4

CALIBRATION operations frequencies shown in Table 4.3-10.

a i

CALVERT CLIFFS - UNIT 1 3/4 3-40 Amendment No. 117

TABLE 3.3-10

)

g; POST-ACCIDENT MONITORING INSTRUMENTATION

"<m MINIMUM E

CHANNELS l

p2 INSTRUMENT OPERABLE ACTION 1.

Deleted 2.

Containment Pressure 2

31 z

El 3.

Wide Range Logarithmic Neutron Flux Monitor 2

31 j

a 4.

Reactor Coolant Outlet Temperature 2

31 5.

Deleted 4

kg 6.

Pressurizer Pressure 2

31 j

4-y 7.

Pressurizer Level 2

31 t-

~~

8.

Steam Generator Pressure 2/ steam generator 31 9.

Steam Generator Level (Wide Range) 2/ steam generator 31 i

EIg 10.

Feedwater Flow 2

31

&g 11.

Auxiliary Feedwater Flow Rate 2/ steam generator 31 e,

1 jf 12.

RCS Subcooled Margin Monitor 1

31 1

13.

PORV/ Safety Valve Acoustic Flow Monitoring 1/ valve 31 hE 14.

PORV Solenoid Power Indication 1/ valve 31 8'

i E

g, 15.

Containment Water Level (Wide Range) 2 32, 33

'i

?*

k$P bO E

a TABLE 3.3-10 (Centinued)

ACTION STATEMENTS ACTION 31 - With the number of OPERABLE post-accident monitoring channels less than required by Table 3.3-10, either restcre the inoperable channel to OPERABLE status within 30 days or be in H0T SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

ACTION 32 - With the number of OPERABLE post-accident monitoring channels one less than the minimum channel operable requirement in Table 3.3-10, operation may proceed provided the inoperable channel is restored to OPERABLE status at the next outage of sufficient duration.

ACTION 33 - With the number of OPERABLE post-accident monitoring channels two less than required by Table 3.3-10, either restore one inoperable channel to OPERABLE status within 30 days or be in HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

I l

CALVERT CLIFFS - UNIT 1 3/4 3-41a Amendment No. 117

TABLE 4.3-10 POST-ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS _

n.

.~

2,-

r k

CHANNEL CHANNEL CHECK QLIBRATION INSTRl! MENT n

C

?,

1.

tieleted v

M R

2.

Containment Pressure E

Wide Range Logarithmic Neutron Flux Monitor M

N.A.

g 3.

4.

Reactor Coolant Outlet Temperature M

R 5.

Deleted R

6.

Pressurizer Pressure M

R Y

7.

Pressurizer Level M

R O

8.

Steam Generator Pressure M

R 9.

Steam Generator Level (Wide Range)

M R

10. Feedwater Flow M

R M

R

11. Auxiliary Feedwater Flow Rate k

12. RCS Subcooled Margin Monitor M

R a

13.

PORV/ Safety Valve Acoustic Monitor N.A.

R A

14.

PORV Solenoid Power Indication N.A.

N.A.

z

15. Containment Water Level (Wide Range)

M R

l U"

9 "k

at

i REACTOR COOLANT SYSTEM PRESSURIZER a

LIMITING CONDITION FOR OPERATION 3.4.4.

The pressurizer shall be OPERABLE with a steam bubble and with at least 150 kw of pressurizer heater capacity capable of being supplied by emergency power. The pressurizer level shall be maintained within an operating band between 133 and 225 inches except when three charging pumps are operating and letdown flow is less than 25 GP!1.

If three charging pumps are operating and letdown flow is less than 25 GPM pressurizer l

level shall be limited to between 133 and 210 inches.

APPLICABILITY: MODES 1 and 2.

ACTION:

With the pressurizer inoperable due to an inoperable emergency power a.

supply to the pressurizer heaters either restore the inoperable emergency power supply within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in at least. HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in HOT SHUTDOWN within the following 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b.

With the pressurizer otherwise inoperable, be in at least HOT STANDBY with the reactor trip breakers open within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE RE0VIREt1ENTS 4.4.4 The pressurizer water level shall be determined to be within the above band at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

CALVERT CLIFFS - UNIT 1 3/4 4-5 Amendment No. 33, 70, 117

REACTOR COOLANT SYSTEM STEAM GENERATORS LIMITING CONDITION FOR OPERATION 3.4.5 Each steam generator shall be OPERABLE.

APPLICABILITY: MODES 1, 2, 3 and 4.

ACTION:

With cne or more steam generators inoperable, restore the inoperable generator (s) to OPERABLE status prior to increasing T,yg above 200 F.

SURVEILLANCE REQUIREMENTS 4.4.5.0 Each steam generator shall be demonstrated OPERABLE by performance of the following augmented inservice inspection program and the require-ments of Specification 4.0.5.

4.4.5.1 Steam Generator Sample Selection and Inspection - Each steam generator shall be determined OPERABLE during shutdown by selecting and inspecting at least the minimum number of steam generators specified in Table 4.4-1.

4.4.5.2 Steam Generator Tube Sample Selection and Inspection - The steam generator tube minimum sample size, inspection result classification, and the corresponding action required shall be as specified in Table 4.4-2.

The inservice inspection of steam generator tubes shall be performed at the frequencies specified in Specification 4.4.5.3 and the inspected tubes shall be ve rified 6cceptable per the acceptance criteria of Speci-fication 4.4.5.4.

The tubes selected for each inservice inspection shall include at least 3% of the total number of tubes in all steam generators; the tubes selected for these inspections shall be selected on a random basis except:

Where experience in similar plants with similar water chemistry a.

indicates critical areas to be inspected, then at least 50% of the tubes inspected shall be from these critical areas.

b.

The first inservice inspection (subsequent to the preservice inspection) of each steam generator shall include:

I 1.

All nonplugged tubes that previously had detecta.ie wall penetrations (>20%), and CALVERT CLIFFS - UNIT 1 3/44-6 i

i i

k

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE' REQUIREMENTS (Continued) e.

At least once per 18 months by:

1.

Verifying automatic isolation and interlock action of the shutdown cooling system from the Reactor Coolant System when the Reactor Coolant System pressure is above 300 psia.

i 2.

A visual inspection of the containment sump and verify-ing that the subsystem suction inlets are not restricted by debris and that the sump components (trash racks, screens, etc.) show no evidence of structural distress or corrosion.

3.

Verifying that a minimum total of 100 cub'c feet of l

solid granular trisodium phosphate dodecahvdrate (TSP) is contained within the TSP storage baskets.

l 4.

Verifying that when a representative sample of 4.0 + 0.1 grams of TSP from a TSP storage basket is submerged,_

without agitation, in 3.5 + 0.1 liters of 77 + 10 F boratedwaterfromtheRWTTthepHofthemixedsolution is raised to > 6 within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

f.

At least once per 18 months, during shutdown, by:

1.

Verifying that each automatic valve in the flow path actuates to its correct position on a Safety Injection Actuation test signal.

2.

Verifying that each of the following pumps start auto-matically upon receipt of a Safety Injection Actuation Test Signal:

a.

High-Pressure Safety Injection pump.

b.

Low-Pressure Safety Injection pump.

CALVERT CLIFFS - UNIT 1 3/4 5-5 Amendment No. 34,48, 117

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) e g.

By performing a flow balance test during shutdown following i

completion of HPSI system modifications that alter system flow characteristics and verifying the following flow rates for a single HPS! pump system *:

1.

The sum of the three lowest flow legs shall be greater than 470** gpm.

h.

By verifying that the HPSI pumps develop a total head of i

2900 ft. on recirculation flow to the refueling water tank when tested pursuant to Specification 4.0.5.

A HPSI pump system is a HPSI pump and one of two safety injection headers.

- These limits contain allowances for instrument error, drift or fluctuation.

CALVERT CLIFFS - UNIT 1 3/4 5-Sa Amendment No. 3f,75,70f, 117

1 3/4.6 CONTAINMENT SYSTEMS 3/4. 6.1 PRIttARY CONTAINMENT CONTAINMENT INTEGRITY

_LfMITING CONDITION FOR OPERATION l

3.6.1.1 Primary CONTAIN!!ENT INTEGRITY shall be maintained.

APPLICABILITY: MODES 1, 2, 3 and 4.

ACTION:

Without primary CONTAINMENT INTEGRITY, restore CONTAINMENT INTEGRITY within one hour or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SURVEILLANCE REQUIREMENTS 4.6.1.1 Primary CONTAINMENT INTEGRITY shall be demonstrated:

a.

At least once per 31 days by verifying that all penetrations

not capable of being closed by OPERABLE containment automatic isolation valves and required to be closed during accident conditions are closed by valves, blind flanges, or deactivated automatic valves secured in their positions, except as provided in Table 3.6-1 of Specification 3.6.4.1.

b.

By verifying that each containment air lock is OPERABLE per Specification 3.6.1.3.

c.

By verifying that the equipment hatch is closed and sealed, prior to entering 11 ode 4 following a shutdown where the equipment hatch was opened, by conducting a Type B test per Appendix J to 10 CFR Part 50.

i i

Except valves, blind flanges, and deactivated automatic valves which are located inside the containment and are locked, sealed, or otherwise secured in the closed position.

These penetrations shall be verified closed during each COLD SHUTDOWN except that such verification need not be performed more often thar. once per 92 days.

CALVERT CLIFFS - UNIT 1 3/4 6-1 Amendment No. 7/y,117

CONTAINMENT SYSTEMS CONTAINMENT LEAKAGE a

LI!!ITING CONDITION FOR OPERATION 3.6.1.2 Containment leakage rates shdl be limited to:

a.

An overall integrated leakage rate of:

1 L,pe(346,000 SCCM), 0.20 percent by weight of the containment 1.

air r 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months at P, 50 psig, or 3

2.

Ilt (61,600.% Cit), 0.058 percent by weight of the containment air per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months at a reduced pressure of P 25 psig.

t b.

A combined leakage rate of 1 0.60 L (207,600 SCCM), for all penetra-tions and valves subject to Type B $nd C tests when pressurized to P

a APPLICABILITY: MODES 1, 2, 3 and 4.

ACTION:

With either (a) the measured overall integrated containment leakage rate exceeding 0.75 L SCCM) or 0.75 L (46,200 SCCM), as applicable, or (b) with the Mea (259.500sured combined leakage fate for all penatrations and valves subject to Types B and C tests exceeding 0.60 L, restore t'1e leakage rate (s) to within the limit (s) prior to increasing the Reactor Covio.?. System temperature above 200*F.

SURVEILLANCE REQUIREMENTS 4.6.1.2 The containment leakage rates shall be demonstrated at the follow-ing test schedule and shall be determined in conformance with the criteria specified in Appendix J of 10 CFR Part 50 using the methods and provisions l

of ANSI N45.4 - 1972:

a.

Three Type A tests (overall Integrated Containment Leakage Rate) shall be conducted at 40 + 10 month intervals during shutdown at either Pa (50 psig) or at Pt (25 psig) during each 10-year service period.

I CALVERT CLIFFS - UNIT 1 3/4 6-2 Amendment No. 75, fM,112

l TABLE 3.6-1 (Continued) h!

CONTAINMENT ISOLATION VALVES

5 E

PENETRATION ISOLATION ISOLATION VALVE ISOLATION l2 NO.

CHANNEL IDENTIFICATION NO.

FUNCTION TIME (SECONDS)

G Di 61 NA SFP-176 Refueling Pool Outlet NA NA SFP-174 NA NA SFP-172 NA c-55 NA SFP-189 NA w

62 SIAS A PH-6579-MOV Containment Heating Outlet

< 13 4

64 NA PH-376 Containment Heating Inlet NA I

Ad.

s i

?'

i D?

(1) Manual or remote manual valve which is closed during plant operation.

1 l

(2) May be opened below 300 F to establish shutdown cooling flow.

(3) Containment purge valves will be shut in MODES 1, 2, 3, and 4 per TS 3/4 6.1.7.

l R

g

May be open en ar intermittent basis under administrative control.

a i

2

- Containment purge isolation valves isolation times will only apply in MODE 6 when the valves are 1

5 required to be OPERABLE and they are open.

Isolation time for containment purge isolation valves g

is NA for MODES 1, 2, 3 and 4 per TS 3/4 6.1.7, during which time these valves must remain closed.

(4) Containmen.t vent isolation valves shall be opened for containment pressure control, airborngC in l

'[

radioactivity control, and surveillance testing purposes only.

e u,

l

CONTAINMENT SYSTEMS 3/4.6.5 COMBUSTIBLE GAS CONTROL 3

HYDR 0 GEN ANALYZERS LIMITING CONDITION FOR OPERATION 3.6.5.1 Two independent containment hydrogen analyzers shall be OPERABLE.

APPLICABILITY: MODES 1 and 2.

ACTION:

a.

With one hydrogen analyzer inoperable, restore the inoperable analyzer to OPERABLE status within 30 days or:

l 1.

Verify containment atmosphere grab sampling capability and prepare and submit a special report to the Commission pursuant to Specification 6.9.2 within the following 30 days, outlining the ACTION taken, the cause for the inoperability, and the plans and schedule for restoring the system to OPERABLE status, or 2.

Be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , b.

With both hydrogen analyzers inoperable, restore at least one inoperable analyzer to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS 4.6.5.1 Each hydrogen analyzer shall be demonstrated OPERABLE at least bi-weekly on a STAGGERED TEST BASIS by drawing a sample from the waste gas system through the hydrogen analyzer.

4.6.5.2 Each hydrogen analyzer shall be demonstrated OPERABLE at least once per 92 days on a STAGGERED TEST BASIS by performing a CHANNEL CALIBRA-TION using sample gases in accordance with manufacturers' recommendations.

CALVERT r'.' FFS - UNIT 1 3/4 6-26 Amendment No. 60,74,$3,703,709,117

1 l}

TABLE 3.7-4 SAFETY RELATEU HYDRAULIC SNUBBERS

P 4;

SNUBBER SYSTEM SNUBBER INSTALLED ACCESSIBLE OR HIGH RADIATION ESPECIALLY DIFFICULT v? NO. ON, LOCATION AND ELEVATION INACCESSIBLE z0NE** TO REMGVE l j-lA or I) (Yes or No) (Yes or No) -4 I-83-55 MAIN STEAM LINE ENCAPSULATION 27' A No No 1 l-83-56 MAIN STEAM LINE ENCAPSULATION 27' A No No 1-83-57 MAIN STEAM LINE ENCAPSULATION 27' A No No j l-83-58 MAIN STEAM LINE ENCAPSULATION 27' A No No R = J S 1-83-67 MAIN STEAM FROM S.G. #12 61' I Yes Ne 1-83-69 MAIN STEAM FROM S.G. #12 61' I Yes No i l-83-70 MAIN STEAM FRai S.G. #12 61' I Yes No l-83-Il MAIN STEAM FROM S.G. #12 61' I Yes No l-83-13 MSIV #11 HYDRAULIC SUPPLY 38' A No No... l-83-74 MSIV #11 HYDRAULIC SUPPLY 38' A No No E$ 1

.uy' TABLE 3.7-4 h SAFETY RELATED HYDRAULIC SNUBBERS

N E

SNUBBER SYSTEM SNUBBER INSTALLED ACCESSIBLE OR HIGH RADIATION ESPECIALLY DIFFICULT NO. ON, LOCATION AND ELEVATION INACCESSIBLE ZONE ** TO REMOVE nC (A or I) (Yes or No) (Yes or No) 'm 1-83-75 AUXILIARY STEAM ISOLATION V/.LVE BYPASS 32' A No No E R 1-83-76 AUXILIARY FEED PUMP STEAM SUPPLY FROM S.G. #12 40' A No No 1-G3-76A AUXILIARY FEED FUHF 5TEi+i SUPPLY FRG1 S.G. #12 40' A No No l-83-77 AUXILIARY FEED PUMP STEAM SUPPLY FROM S.G. #12 40' A No No y 9

Snubbers may be added to safey related systems without prior License Amendment to Table 3.7-4 provided that a revision to Table 3.7-4 is included with the next License Amendment request. Snubbers may be removed from safety related systems for the purpose of replacement by sway struts in accordance with the NRC's Safety y

Evaluation dated April 19, 1984, provided that a revision to Table 3.7-4 is included with the next License Amendment request. a

- Modification to this table due to changes in high radiation areas shall be submitted to the NRC as part of the next License Amendment request.

D b = e

3/4.3 INSTRUMENATION BASES 3/4.3.1 and 3/4.3.2 PROTECTIVE AND ENGINEERED SAFETY FEATURES (ESF) INSTRUMENTATION The OPERABILITY of the protective and ESF instrumentation systems and bypasses ensure that 1) the associated ESF action and/or reactor trip will be initiated when the parameter monitored by each channel or combi-nation therof exceeds its setpoint, 2) the specified coincidence logic is maintained, 3) sufficient redundancy is maintained to permit a channel to be out of service for testing or maintenance, and 4) sufficient system functional capability is available for protective and ESF purposes from diverse parameters. The OPERABILITY of these systems is required to provide the overall reliability, redundance and diversity assumed available in the facility design for the protection and mitigation of accident and transient con-ditions. The integrated operation of each of these systems is consistent with the assumptions used in the accident analyses. The surveillance requirements specified for these systems ensure that the overall system functional capability is maintained comparable to the original design standards. The periodic surveillance tests per-formed at the minimum frequencies are sufficient to demonstrate this capability. The measurement of response time at the specified frequencies pro-vides assurance that the protective and ESF action function associated with each channel is completed within the time limit assumed in the accident analyses. No credit was taken in the analyses for those channels with response times indicated as not applicable. Response time may be demonstrated by any series of sequential, over-lapping or total channel test measurements provided that such tests demonstrate the total channel response time as defined. Sensor response time verification may be demonstrated by either 1) in place, onsite or offsite test measurements or 2) utilizing replacement sensors with certified response times, i 3/4.3.3 MONITORING INSTRUMENTATION 3/4. 3. 3.1 RADIATION MONITORING INSTRUMENTATION I The OPERABILITY of the radiation monitoring channels ensures that

1) the radiation levels are continually measured in the areas served CALVERT CLIFFS - UNIT 1 B 3/4 3-1

)

INSTRUMENTATION BASES W by the individual channels and 2) the alarm or automatic action is initiated when the radiation level trip setpoint is exceeded. The Iodine ar.d Particulate samplers were installed to meet the require-ments of F.UREG-0737 Item II.F.1. The samplers' operation was not assumed in any accident analysis. i 3/4.3.3.2 INCORE DETECTORS The OPERABILITY of the incore detectors with th. specified minimum complement of equipment ensures that the measurements obtained from use of this system accurately represent the spatial neutron flux distribution of the reactor core. 3/4.3.3.3. SEISMIC INSTRUMENTATION The OPERABILITY of the seismic instrumentation ensures that sufficient capability is available to promptly determine the magnitude of a seismic event and evaluate the response of those features important to safety. This capability is required to permit comparison of the measured response to that used in the design basis for the facility and is consistent with the recommendations of Regulatory Guide 1.12 " Instrumentation for Earthquakes," April 1974. 3/4.3.3.4 METE 010 LOGICAL INSTRUMENTATION The OPERABILITY of the meteorological instrumentation ensures that sufficient meteorological data is available for estimating potential radiation doses to the public as a result of routine or accidental release of radioactive materials to the atmosphere. This capability is required to evalucte the qeed for initiating protective measures to protect the health and safety of the public and is consistent with the recommendations of Regulatory Gufde 1.23 "Onsite Meteorological Programs," February 1972, as supplemented by Supplement 1 to NUREG-0737. l 3/4.3.3.5 REMOTE SHUTDOWN INSTRUMENTATION The OPERABILITY of the remote shutdown instrumentation ensures that sufficient capability is available to permit shutdown and maintenance of HOT STANDBY of the facility from locations outside of the control room. This capability is required in the event control rcom habitability is lost and is consistent with General Design Criteria 19 of 10 CFR 50. CALVERT CLIFFS - UNIT 1 B 3/4 3-2 Amendment No. J03, )97, 117

3/4.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) BASES a 3/4.5.1 SAFETY INJECTION TANKS The OPERABILITY of each of the RCS safety injection tanks ensures that a sufficient volume of borated water will be immediately forced into the reactor core through each of the cold legs in the event the RCS pressure falls below the pressure of the safety injection tanks. This initial surge of water into j the core provides the initial cooling mechanism during large RCS pipe ruptures. The limits on safety injection tank volume, boron cor. centration and pressure ensure that the assumptions used for safety injection tank injection in the accident analysis are met. The safety injection tank power operated isolation valves are considered to be " operating bypasses" in the context of IEEE Std. 279-1971, which requires that bypasses of a protective function be removed automatically whenever permissive conditions are not met. In addition, as these safety injection tank isolation valves fail to meet single failure criteria, removal of power to the valves is required. The limits for operation with a safety injection tank inoperable for any reason except an isolation valve closed minimizes the time exposure of the plant to a LOCA event occurring concurrent with failure of an additional safety injection tank which may result in unacceptable peak cladding terperatures. If a closed isolation valve cannot be immediately opened, the full capability I of one safety injection tank is not available and prompt action it required to place the reactor in a mode where this capability is not required. 3/4.5.2 and 3/4.5.3 ECCS SUBSYSTEMS The OPERABILITY of two separate ECCS subsystems ensures that sufficient emergency core cooling capability will be available in the event of a LOCA assuming the loss of one subsystem through any single failure consideration. Either subsystem operating in conjunction with the safety injection tanks is capab;e of supplying sufficient core cooling to limit the peak cladding temperatures within acceptable limits for all postulated break sizes ranging from the double ended break of the largest RCS cold leg pipe downward. In addition, each ECCS subsystem provides long term core cooling capability in the recirculation mode during the accident recovery period. Portions of the low pressure safety injection (LPSI) system flowpath are comon to both subsystems. This includes the low pressure safety injection flow control valve, CV-306, the flow orifice downstream of CV-306, and the four low pressure safety injection loop isolation valves. Although the portions of the flowpath are common, the system design is adequate to ensure l reliable ECCS operatiun due to the short period of LPSI system operation following a design basis Loss of Coolant Incident prior to recirculation. The LPSI system design is consistent with the assumptions in the safety analysis. CALVERT CLIFFS - UNIT 1 B 3/4 5-1 Amendment No.103

EMERGENCY CORE COOLING SYSTEMS BASES = The trisodium phosphate dodecahydrate (TSP) stored in dissolving baskets located in the containment basement is provided to minimize the possibility of corrosion cracking of certain metal components during operation of the ECCS following a LOCA. The TSP provides this protection by dissolving in the sump water and causing its final pH to be raised to > 7.0. The requirement to dissolve a representative sample of TSP in a sample of RWT water provides assurance that the stored TSP will dissolve in borated water at the postulated post LOCA temperatures. The Surveillance Requirements provided to ensure OPERABILITY,of each component ensure that at a minimum, t1e assumptions used in the safety analyses are met and that subsystem OPERASILIT( is maintained. The surveillance require-ment for flow balance testing provides assurance that proper ECCS flows will be l maintained in the event of a LOCA. Maintenance of proper flow resistance and pressure drop in the piping system to each injection point is necessary to: (1) prevent total pump flow from exceeding runout conditions when the system is in its minimum resistance configuration, (2) provide the proper flow split between injection points in accordance with the assumptions used in the ECCS-LOCA analyses, and (3) provide an acceptable level of total ECCS flow to all injection points equal to or above tLat assumed in the ECCS-LOCA analyses. Minimum HPSI flow requirements are based upon small break LOCA calculations which credit charging pump flow following an SIAS. Surveillance testing includes allowances for instrumentation and system leakage uncertainties. The 470 gpm requirement for minimum HPSI flow from the three lowest flow legs includes instrument uncertainties but not system check valve leakage. The OPERABILITY of the charging pumps and the associated flow paths is assured by the Boration System Specification 3/4.1.2. Specification of safety injection pump total developed head ensures pump performance is consistent with safetyJanalysis assumptions. 3/4.5.4 REFUELING WATER TANK (RWT) The OPERABILITY of the RWT as part of the ECCS ensures that a sufficient supply of borated water is availablE for injection by the ECCS in the event of a LOCA. The limits on RWT minimtm volume and boron concentration ensure that 1) sufficient water is available within containment to permit recircula-tion cooling flow to the core, and 2) the reactor will remain subtritical in the cold condition following mixing of the RWT and the RCS water volumes with all control rods inserted except for the most reactive control assembly. These assumptions are consistent with the LOCA analyses. The contained water volume limit includes an allowance for water not usable because of tank discharge line location or other physical cnaractor-1stics. l l 1 l CALVERT CLIFFS - UNIT 1 B 3/4 5-2 Amcadment No. 34,4fM/,117

1 3/4.7 PLANT SYSTEMS BASES 3/4.7.1 TURBINE CYCLE 3/4.7.1.1 SAFETY VALVES The OPERABILITY of the main steam line code safety valves ensures that the secondary system pressure will t'e limited to within 110% of its design pressure of 1000 psig during the most severe anticipated system operational transient. The total relieving capacity for all valves on all of the steam lines is 12.18 x 106 lbs/hr at 100% RATED THERMAL POWER. The maximum relieving capacity is associated with a turbine trip from 100% RATED THERMAL POWER coincident with an assumed loss of condenser heat sink (i.e., no steam bypass to the condenser). The main steam line code safety valves are tested and maintained in accordance with the requirements of Section XI of the ASME Boiler and Pressure Vessel Code. The as-left lift settings will be no less than 985 psig to ensure that the lift setpoints will remain within specification during the cycle. In MODE 3, two main steam safety valves are required OPERABLE per steam generator. These valves will provide adequate relieving capacity for removal of both decay heat and reactor coolant pump heat from the reactor coolant system l via either of the two steam generators. This requirement is provided to facilitate the post-overhaul setting and OPERABILITY testing of the safety l i valves which can only be conducted when the RCS is at or above 5000F. It allows entry into MODE 3 with a minimum number of main steam safety valves OPERABLE so that the set pressure for the remaining valves can be adjusted in the plant. This is the most accurate means for adjusting safety valve set pressures since 'he valves will be in thermal equilibrium with the operating environment. STARTUP and/or POWER OPERATION is allowable with safety valves inoperable within the limitations of the ACTION requirements on the basis of the reduction in secondary system steam flow and THERMAL POWER required by the reduced reactor trip settings of the Power Level-High channels. The reactor trip setpoint reductions are derived on the following bases: For two loop operation SP = ( } XI }I ) x 106.5 For single loop operation (two reactor coolant pumps operating in the same loop) 3p, (X) - (Y)(U) x 46.8 where: SP reduced reactor trip setpoint in percent of RATED THERPAL = POWER V maximum number of inoperable safety valves per steam line = CALVERT CLIFFS - UNIT 1 B 3/4 7-1 Amendment No. (dt,117

PLANT SYSTEMS l BASES maximum number of inoperable safety valves per U = operating steam line 106.5 = Power Level - High Trip Setpoint for two loop operation 46.8 = Power Level - High Trip Setpoint for single loop operation with two reactor coolant pumps operating in the same loop Total relieving capacity of all safety valves per X = steam line in lbs/ hour Y Maximum relieving capacity of any one safety valve = in lbs/ hour 3/4.7.1.2 AUXILIARY FEEDWATER SYSTEM The OPERABILITY of the auxiliary feedwater system ensures that the Reactor Coolant System can be cooled down to less than 300*F from normal operating conditions in the event of a total loss of offsite power. A capacity of 400 gpm is sufficient to ensure that adequate feedwater flow is available to remove decay heat and reduce the Reactor Coolant System tempera-ture to less than 300*F when the shutdown cooling system may be placed into l operation. Flow control valves, installed in each leg supplying the steam generators, are set to maintain a nominal flow setpoint of 200 gpm plus or minus 10 gpm for operator setting band. The nominal flow setpoint of 200 gpm incorpurates a total instrument loop error band of plus 25 gpm and minus 26 gpm for the motor-driven pump train. The corresponding values for the steam-driven pump l train are plus 37 gpm and minus 40 gpm. The operator setting band, when combined with the instrument loop error, results in a total flow band of 164 gpm (minimum) and 235 gpm (maximum) for the motor-driven pump train. The corresponding values for the steam-driven pump train are 150 gpm (minimum) and 247 gpm (maximum). Safety analyses show that more flow during an over-cooling transient and less flow during an undercooling transient could be tolerated; i.e., flow fluctuations outside this flow band but within the assumptions used in the analyses listed below, are allowable. In the spectrum of events analyzed in which automatic initiation of auxiliary feedwater occurs, tl.e following flow conditions are allowed with an operator action time of 10 minutes. CALVERT CLIFFS - UNIT 1 B 3/4 7-2 Amendment No. Eh 67, 78,8 g

ADMINISTRATIVE CONTROLS a. ECCS Actuation, Specifications 3.5.2 and 3.5.3. b. Inoperable Seismic Monitoring Instrumentation, Specification 3.3.3.3. c. Inoperable Meteorological Monitoring Instrumentation, Specification 3.3.3.4 d. Seismic event analysis, Specification 4.3.3.3.2. e. Core Barrel Movement, Specification 3.4.11. f. Fire Detection Instrumentation, Specification 3.3.3.7 g. Fire Suppression Systems, Specifications 3.7.11.1, 3.7.11.2, 3.7.11.3, 3.7.11.4, and 3.7.11.5. h. Penetration Fire Barriers, Specification 1.7.12. 1. Steam Generator Tube Inspection Results, Specification 4.4.5.5.a and c. J. Specific Activity of Primary. Coolant, Specification 3.4.8. J k. Containment Structural Integrity, Specification 4.6.1.6. 1. Radioactive Effluents - Csiculated Dose and Total Dose, Specifica-tions 3.11.1.2, 3.11.2.2, 3.11.2.3, and 3.11.4. r m. Radioactive Effluents - Liquid Radwaste, Gaseous Radwaste and Ventilation Exhaust Treatment Systems Discharges, Specifications 3.11.1.3 and 3.11.2.4. l n. Radiological Environmental Monitoring Program, Specification 3.12.1. o. Radiation Monitoring Instrumentation, Specification 3.3.3.1 (Table 3.3-6). p. Overpressure Protection Systems, Specification 3.4.9.3. l q. Hydrogen Analyzers, Specification 3.6.5.1. l l CALVERT CLIFFS - UNIT 1 6-18a Amendment No., 29,94,705, 117 ) J

[ UNITED STATES o,, 8. NUCLEAR REGULATORY COMMISSION o ,I WASHINGTON D. C. 20555 ,/ v BALTIM0RE GAS AND ELECTRIC COMPANY DOCKET NO. 50-318 CALVERT CLIFFS NUCLEAR POWER PLANT UNIT N0. 2 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 99 License No. DPR-69 1. The Nuclear Regulatory Comission (the Comission) has found that: A. The applications for amendments by Baltimore Gas & Electric Company (the licensee) dated February 22, 1985 and October 25, 1985 comply with the standards and requirements of the Atomic Enm, Act of 1954, as amended (the Act), and the Comission's rules and regulations set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the applications, the provisions of the Act, and the rules and regulations of the Comission; C. There is reasonable assurance (1) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Cccaission's regulations; D. The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Comission's regulations and all applicable requirements have been satisfied.

2. Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendaient, and paragraph 2.C.2 of Facility Operating License No. DPR-69 is hereby amended to read as follows: 2. Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 99, are hereby incorporated in the license. The licensee shall operate the facility in accordance with the Technical Specifications. ~ 3. This license amendment is effective as of the date of its issuance. FOR THE NUCLEAR REGULATORY COMMISSION M.Ad Ash k C. Thadani, Director PWRProjectDirectorate#8 Division of PWR Licensing-B

Attachment:

Changes to the Technical Specifications Date of Issuance: April 14, 1986 i l 4 -r ...r.-

ATTACHMENT TO LICENSE AMENDMENT NO. 99 FACILTIY OPERATING LICENSE NO. DPR-69 DOCKET NO. 50-318 Replace the following pages of the Appendix "A" Technical Specifications with the enclosed pages. The revised pages are identified by amendment number and contain vertical lines indicating the areas of change. The corresponding overleaf pages are provided to maintain document completeness. Remove Pages Insert Pages B 2-5 B 2-5 3/4 1-6 3/4 1-6 3/4 3-40 3/4 3-40 3/4 3-41 3/4 3-41 3/4 3-41a 3/4 3-42 (no change) 3/4 4-5 3/4 4-5 3/4 5-5 3/4 5-5 3/4 5-Sa 3/4 5-Sa 3/4 6-1 3/4 6-1 3/4 6-26 3/4 6-26 B 3/4 3-2 B 3/4 3-2 B 3/4 5-2 B 3/4 5-2 B 3/4 7-1 B 3/4 7-1 6-18a 6-18a f a 1 ---w-- ~. - - w w- -p r e.

LIMITING SAFETY SYSTEM SETTINGS BASES operation of the reactor at reduced power if one or two reactor coolant pumps are taken out of service. The low-flow trip setpoints and Allowable Values for the various reactor coolant pump combinations have been derived in consideration of instrument errors and response. times of equipment involved to maintain the DNBR above 1.21 under normal operation and expected transients. For reactor operation with only two or three reactor coolant pumps operating, the Reactor Coolant Flow-Low trip set-points, the Power Level-High trip setpoints, and the Thermal Margin / Low Pressure trip setpoints are automatically changed when the pump condition selector switch is manually set to the desired two-or three-pump position. Changing these trip setpoints during two and three pump operation prevents the minimum value of DNBR from going below 1.21 during normal operational transients and anticipated transients when only two or three reactor coolant pumps are operating. Pressurizer Pressure-High The Pressurizer Pressure-High trip, backed up by the pressurizer code safety valves and main steam line safety valves, provides reactor coolant system protection against overpressurization in the event of loss of load without reactor trip. This trip's setpoint is 100 psi celow the nominal lift setting (2500 psia) of the pressurizer code safety valves and its concurrent operation with the power-operated relief valves avoids the undesirable operation of the pressurizer code safety valves. Containment Pressure-High The Containment Pressure-High trip provides assurance that a reactor i trip is initiated prior to, or at least concurrently with, a safety I injection. Steam Generator Pressure-Low The Steam Generator Pressure-Low trip provides protection against an excessive rate of heat extraction from the steam generators and subsequent cooldown of the reactor coolant. The setting of 685 psia is sufficiently below the full-load operating point of 850 psia so as not to interfere with normal operation, but still high enough to provide the required protection in the event of excessively high steam flow. This setting was used with an uncertainty factor of + 85 psi in the accident analyses.which was based on the Main Steam Tine Break event. CALVERT CLIFFS - UNIT 2 B 2-5 Amendment No.17,31, gggty, 99

LIMITING SAFETY SYSTEM SETTINGS ~ ~ BASES Steam Generator Water Level The Steam Generator Water Level-Low trip provides core protection by preventing operation with the steam generator water level below the minimum volume required for adequate heat removal capacity and assures that the pressure of the reactor coolant system will not exceed its Safety Limit. The specified setpoint in combination with the auxiliary feedwater actuation system ensures.that sufficient water inventory exists in both steam generators to remove decay heat following a loss of main feedwater flow event. Axial Flux Offset The axial flux offset trip is provided to ensure that excessive axial peaking will not cause fuel damage. The axial flux offset is determined from the axially split excore detectors. The trip setpoints ensure that neither a DNBR of less than 1.21 nor a peak linear heat rate l which corresponds to the temperature for fuel centerline melting will exist as a consequence of axial power maldistributions. These trip set-points were derived from an analysis of many axial power shapes with allowances for instrumentation inaccuracies and the uncertainty associated with the excore to incore axial flux offset relationship. Thermal Margin / Low Pressure The Thermal Margin / Low Pressure trip is provided to prevent operation when the DNBR is less than 1.21. I The trip is initiated whenever the reactor coolant system pressure signal drops below either 1875 psia or a computed value as described below, whichever is higher. The computed value is a function of the higher of AT power or neutron power, reactor inlet temperature, and the number of reactor coolant pumps operating. The minimum value of reactor coolant flow rate, the maximum AZIMUTHAL POWER TILT and the maximum CEA deviation permitted for continuous operation are assumed in the genera-tion of this trip function. In addition, CEA group sequencing in accor-dance with Specifications 3.1.3.5 and 3.1.3.6 is assumed. Finally, the maximum insertion of CEA banks which can occur during any anticipated operational occurrence prior to a Power Level-High trip is assumed. CALVERT CLIFFS - UNIT 2 B 2-6 AmendmentNo.Jg,if,J'J'90

REACTIVITY CONTROL SYSTEMS MODERATOR TEMPERATURE COEFFICIENT LIMITING CONDITION FOR OPERATION 3.1.1.4 The moderator temperature coefficient (MTC) shall be: Less positive than 0.7 x 10-4 Ak/k/*F whenever THERMAL l a. POWER is < 70% of RATED THERMAL POWER, d b. Less positive than 0.2 x 10-4 Ak/k/*F whenever THERMAL POWER is > 70% of RATED THERMAL POWER, and Less negative than -2.7 x 10-' ak/k/*F at RATED THERMAL l c. POWER. APPLICABILITY: MODES 1 and 2*# ACTION: With the moderator temperature coefficient outside any one of the above limits, be in at least HOT STANDBY within 6 hours. SURVEILLANCE REQUIREMENTS 4.1.1.4.1 The MTC shall be determined to be within its limits by confirmatory measurements. MTC measured values shall be extrapolated and/or compensated to permit direct comparison with the above limits.

With K,ff > 1.0.

See Special Test Exception 3.10.2.

CALVERT CLIFFS - UNIT 2 3/4 1-5 Amendment No. 78,II )),90

REACTIVITY CONTROL SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) 4.1.1.4.2 The MTC shall be determined at the following frequencies and THERMAL POWER conditions during each fuel cycle: Prior to initial operation above 5% of RATED THERMAL POWER, a. after each fuel loading. b. At any THERMAL POWER: above 90% of RATED THERMAL POWER, within 7 EFPD after initially reaching an equilibrium condition at or above 90% of RATED THERMAL POWER after each fuel loading. I At any THERMAL Power,'w thin 7 EFPD of reaching a RATED c. THERMAL POWER equilibrium boron concentration of 300 ppm. CALVERT CLIFFS-UNIT 2 3/4 1-6 Amendment No.g/], 99

9 r-jj TABLE 4.3-6 a REMOTE SHUTDOWN MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS ,1 CHANNEL CHANNEL 7' INSTRUMENT CHECK CALIBRATION E 1. Wide Range Neutron Flux M N.A. n2 2. Reactor Trip Breaker Indication M N.A. 3. Reactor Coolant Cold Leg Temperature M R 4. Pressurizer Pressure M R 5. Pressurizer Level M R 2 6. Steam Generator Level M R E! 7. Steam Generator Pressure M R 34-

INSTRUMENTATION POST-ACCIDENT INSTRUMENTATION ~ LIMITING CONDITION FOR OPERATION 3.3.3.6 The post-accident monitoring instrumentation channels shown in Table 3.3-10 shall be OPERABLE. APPLICABILITY: MODES 1, 2 and 3. ACTION: a. As shown in Table 3.3-10. b. The provisions of Specification 3.0.4 are not applicable. SURVEILLANCE REQUIREMENTS 4.3.3.6 Each post-accident monitoring instrumentation channel shall be demonstrated OPERABLE by performance of the CHANNEL CHECK and CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3-10. CALVERT CLIFFS - UNIT 2 3/4 3-40 Amendment No. 99

1 TABLE 3.3-10 POST-ACCIDENT MONITORING INSTRUMENTATION 9; 9 MINIMUM CHANNELS P INSTRUMENT OPERABLE ACTION m? 1. Containment Pressure 2 31 h 2. Wide Range Logarithmic Neutron Flux Monitor 2 31 3. Reactor Coolant Outlet Temperature 2 31 4. Pressurizer Pressure 2 31 5. Pressurizer Level 2 31 { 6. Steam Generator Pressure 2/ steam generator 31 7. Steam Genrator Level (Wide Range) 2/ steam generator 31 8. Auxiliary Feedwater Flow Rate 2/ steam generator 31 9. RCS Subcooled Margin Monitor 1 31 10. PORV/ Safety Valve Acoustic Flow Monitoring 1/ valve 31 R E 11. PORV Solenoid Power Indication 1/ valve 31 8 5 12. Feedwater Flow 2 31 13. Containment Water Level (Wide Range) 2 32, 33 g e-h= b s

TABLE 3.3-10 (Continued) ACTION STATEMENTS \\ i ACTION 31 - With the number of OPERABLE post-accident monitoring channels less than required by Table 3.3-10, either restore the inoperable channel to OPERABLE status within 30 days or be in j H0T SHUTDOWN within the next 12 hours. ACTION 32 - With the number of OPERABLE post-accident monitoring channels l one less than the minimum channel operable requirement in l Table 3.3-10, operation may proceed provided the inoperable l channel is restored to OPERABLE status at the next outage of j sufficient duration. ACTION 33 - With the number of OPERABLE post-accident monitoring channels two less than required by Table 3.3-10, either restore one inoperable channel to OPERABLE status within 30 days or be in HOT SHUTDOWN within the next 12 hours. I l CALVERT CLIFFS - UNIT 2 3/4 3-41a Amendment No. 99

TABLE 4.3-10 POST-ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS 9 ~ r-M CHANNEL CHANNEL INSTRUMENT CHECK CALIBRATION 1. Containment Pressure M R 7 2. Wide Range Logarithmic Neutron Flux Monitor M N.A. E 3. Reactor Coolant Outlet Temperature M R m 4. Pressurizer Pressure M R 5. Pressurizer Level M R 6. Steam Generator Pressure M R 7. Steam Generator Level (Wide Range) M R 8. Auxiliary Feedwater Flow Rate M R 0 9. RCS Subcooled Margin Monitor M R 10. PORV/ Safety Valve Acoustic Monitor N.A. R 11. PORV Solenoid Power Indication N.A. N.A. 12. Feedwater Flow M R $ 13. Containment Water Level (Wide Range) M 'R l 5 E

REACTOR COOLANT SYSTEM PRESSURIZER s LIMITING CONDITION FOR OPERATION 0 3.4.4. The pressurizer shall be OPERABLE with a steam bubble and with at least 150 kw of pressurizer heater capacity capable of being supplied by emergency power. The pressurizer level shall be maintained within an operating band between 133 and 225 inches except when three charging pumps are operating and letdown flow is less than 25 GPil. If three charging pumps are operating and letdown flow is less than 25 GPM pressurizer level shall be limited to between 133 and 210 inches. APPLICABILITY: MODES 1 and 2. ACTION: a. With the pressurizer inoperable due to an inoperable emergency power supply to the pressurizer heaters either restore the inoperable emergency power supply within 72 hours or be in at least HOT STANDBY within the next 6 hours and in HOT SHUTDOWN within the following 12 hours. b. With the pressurizer otherwise inoperable, be in at least HOT STANDBY with the reactor trip breakers open within 6 hours and in HOT SHUTDOWN within the following 6 hours. SURVEILLANCE REQUIREMENTS 4.4.4 The pressurizer water level shall be determined to be within the above band at least once per 12 hours. 1 CALVERT CLIFFS - UNIT 2 3/4 4-5 Amendment No. 36,63, 99 --+r. r .--e,n----,. ,n-- w - ---m,-- ,,------.n.,,,g.,--,-,,-_,,_,,.

REACTOR COOLANT SYSTEM STEAM GENERATORS E 4 LIMITING CONDITION FOR OPERATION 3.4.5 Each steam generator.shall be OPERABLE. APPLICABILITY: MODES 1, 2, 3 and 4. ACTION: With one or more steam generators inoperable, restore the inoperable I 9enerator(s) to OPERABLE status prior to increasing T,yg above 200*F. SURVEILLANCE REQUIREMENTS i 4.4.5.0 Each steam generator shall be demonstrated OPERABLE by performance of the following augmented inservice inspection program and the require-ments of Specification 4.0.5. 4.4.5.1 Steam Generator Sample Selection and Inspection - Each steam generator shall be determined OPERABLE during shutdown by selecting and inspecting at least the minimum number of steam generators specified in Table 4.4-1. 4.4.5.2 Steam Generator Tube Sample Selection and Inspection - The steam i generator tube minimum sample size, inspection result classification, and the corresponding action required shall be as specified in Table 4.4-2. The inservice inspection of steam generator tubes shall be performed at the frequencies specified in Specification 4.4.5.3 and the inspected tubes shall be verified acceptable per the acceptance criteria of Speci-fication 4.4.5.4. The tubes selected for each inservice inspection shall include at least 3% of the total number of tubes in all steam generators; the tubes selected for these inspections shall be selected on a random basis except: a. Where experience in similar plants with similar water chemistry indicates critical areas to be inspected, then at least 50% of the tubes inspected shall be from these critical areas, b. The first inservice inspection (subsequent to the preservice inspection) of each steam generator shall include: I 1. All nonplugged tubes that previously had detectable wall penetrations (>20%),and i 3/4 4-6 CALVERT CLIFFS - UNIT 2

o EMERGENCY CORE COOLING SYSTEMS 't SURVEILLANCE REQUIREMENTS (Continued) e. At least once per 18 months by: 1. Verifying automatic isolation and interlock action of the shutdown cooling system from the Reactor Coolant System when the Reactor Coolant System pressure is above 300 psia. 2. A visual inspection of the containment sump and verifying' that the subsystem suction inlets are not restricted by debris and that the sump components (trash racks, screens, etc.) show no evidence of structural distress or corrosion. 3. Verifying that a minimum total of 100 cubic feet of solid granular trisodium phosphate dodecahydrate (TSP) is contained within the TSP storage baskets. 4. Verifying that when a representative sample of 4.0 + 0.1 grams of TSP from a TSP storage basket is submerged 7 without agitation, in 3.5 t 0.1 liters of 77 10 F borated water from the RWT, the pH of the mixed solution is raised to > 6 within 4 hours. f. At least once per 18 months, during shutdown, by: 1. Verifying that each automatic valve in the flow path actuates to its correct position on a Safety Injection Actuation test signal. 2. Verifying that each of the following pumps start auto-matically upon receipt of a Safety Injection Actuation Test Signal: a. High-Pressure Safety Injection pump. b. Low-Pressure Safety Injection pump. C ALVERT CLIFFS - UNIT 2 3/4 5-5 Amendment No.16, /), 99 4

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) l g. By performing a flow balance test during shutdown following compietion of HPSI system modifications that alter system flow characteristics and verifying the following flow rates for a single HPSI pump system *: 1. The sum of the three lowest flow legs shall be greater than 470** gpm. h. By verifying that the HPSI pumps develop a total head of 2900 ft i on recirculation flow to the refueling water tank when tested pursuant to Specification 4.0.5. t f " A MPSi pump system is a ' IPSI pump and one of two safety injection headers.

- These limits contain allcaances for instrument error, drift or fluctuation.

CALVERT CLIFFS - UNIT 2 3/4 5-5a Amendment No. J$,E$,$9, 99 .q +7-w c.- 4 w 7-. m,

3/4.6 CONTAINMENT SYSTEMS 3/ 4. 6.1 PRIMARY CONTAINMENT CONTAINMENT INTEGRITY LIMITING CONDITION FOR OPERATION 3.6.1.1 Primary CONTAIN!iENT INTEGRITY shall be maintained. APPLICABILITY: h03E 1, 2, 3 and 4. ACTION: Without primary CONTAINMENT INTEGRITY, restore CONTAINMENT INTEGRITY within one hour or be in at least HOT STANDBY within the next 6 hours and in COLD SHUTDOWN within the following 30 hours. SURVEILLANCE RE0UIREMENTS 4.6.1.1 Primary CONTAINMENT INTEGRITY shall be demonstrated: a. At least once per 31 days by verifying that all penetrations

not capable of being closed by OPERABLE containment automatic isolation valves and required to be closed during accident conditions are closed by valves, blind flanges, or deactivated automatic valves secured in their positions, except as provided in Table 3.6-1 of Specification 3.6.4.1.

b. By verifying that each containment air 1cck is OPERABLE per Specification 3.6.1.3. c. By verifying that the equipment he.tch is closed and sealed, prior to entering !! ode 4 following a shutdown where the equipment hatch was opened, by conducting a Type B test per Appendix J to 10 CFR Part 50.

Except valves, blind flanges, and deactivated automatic valves which are located inside the containment and are locked, s6aled, or otherwise secured in the closed position. These penetrations shall be verified closed during each COLD SHUTDOWN except that such verification need not be performed more often than once per 92 days.

CALVERT CLIFFS - UNIT 2 3/4 6-1 AmendmentNa.'$,6@,99. ./ + ,e -,,-+, 4

CONTAINMENT SYSTEMS CONTAINMENT LEAKAGE ~ LIMITING CONDITION FOR OPERATION 3.6.1.2 Containment leakage rates shall be limited to: a. An overall integrated leakage rate of: a (346,000 SCCM), 0.20 percent by weight of'the containment 1. <L air per 24 hours at P, 50 psig, or 3 t (44,600 SCCM), 0.042 percent by weight of the containment 2. <L air per 24 hours at a reduced pressure of P, 25 psig. t b. A combined leakage rate of < 0.60 L (207,600 SCCM) for all penetra-tions and valves subject to Type B $nd C tests when pressurized to P

a APPLICABILITY: MODES 1, 2, 3 and 4.

ACTION: With either (a) the measured overall integrated containment leakage rate exceeding 0.75 L SCCM), or 0.75 L (33,400 SCCM), as applicable, or (b) with the Mea (259,500suredcombinedleakagerkteforallpenetrationsand restore the leakage valves subject to Types B and C tests exceeding 0.60 L, Reactor Coolant System rate (s) to within the limit (s) prior to increasing the temperature above 200*F. SURVEILLANCE REQUIREMENTS 4.6.1.2 The containment leakage rates shall be demonstrated at the follow-ing test schedule and shall be determined in conformance with the criteria specified in Appendix J of 10 CFR 50 using the methods and provisions of l ANSI N45.4 - 1972: Three Type A tests (Overall Integrated Containment Leakage Rate) a. shall be conducted at 40 + 10 rronth intervals during shutdown at either Pa (50 psig) or at Pt (25 psig) during each 10-year service period. CALVERT CLIFFS - UNIT 2 3/4 6-2 Amendment No. E6, /). 9'3

P f 4 TABLE 3.6-1 (Continued)' 9 CONTAINMENT ISOLATION VALVES G 9 PENETRATION ISOLATION ISOLATION VALVE ISOLATION NO. CHANNEL IDENTIFICATION NO. FUNCTION TIME (SECONDS) PG 61 NA SFP-184 Refueling Pool Outlet 3 NA SFP-182 NA NA NA SFP-180 NA e NA SFP-186 NA .5 -e 62 SIAS A PH-6579-MOV Contalment Heating 0>:tlet <13 64 NA PH-387 Containment Hiating Inlet NA t g (1) Manual or remote manual valve which is closed during p1' ant operation. j (2) May be opene.1 below 300'F to establish shutdown cooling flow., m + ~ (3) Containment purge valves will be shut in MODES 1, 2, 3 and 4 per TS 3/4 6.1.7. l l

May be open on an intermittent basis under administrative control.

I

- Containment purge isolation valves isolation times will only, apply in MODE 6 when the valves are required to be OPERABLE and they are open.

Isolation time for containment purge isolation valves is NA for MODES 1, 2, 3 and 4 per TS 3/4 6.1.7, during which timo these valves must remain closed. ( (4) Containment vent isolation valves shall be opened 'for containment pressure control, airborne g radioactivity control, and surveillance testing purposes only. l . e+ 44- = 1 4 ? 5 i n E'

CONTAINMENT SYSTEMS 3/4.6.5 COMBUSTIBLE GAS CONTROL HYDROGEN ANALYZERS LIMITING CONDITION FOR OPERATION 3.6.5.1 Two independent containment hydrogen analyzers shall be OPERABLE. APPLICABILITY: MODES 1 and 2. ACTION: a. With one hydrogen analyzer inoperable, ret. tore the inoperable analyzer to OPERABLE status within 30 days or: l 1. Verify containment atmosphere grab sampling capability and prepare and submit a special report to the Commission pursuant to Specification '.9.2 within the following 30 days, outlining the ACTION taken,. e cause for the inoperability, and the plans and schedule for restoring the system to OPERABLE status, or 2. Be in at least HOT STANDBY within the next 6 hours, b. With both hydrogen analyzers inoperable, restore at least d ie inoperable analyzertoOPERABLEstatuswithin)*.hoursorbeinatleastHOTSTANDBY within the next 6 hours. SURVEILLANCE REQUIREMENTS 4.6.5.1 Each hydrogen analyzer shall be demonstrated OPERABLE at least biweekly on a STAGGERED TEST BASIS by drawing a sample from the Waste Gas System through the hydrcgen analyzer indicator. 4.6.5.2 Each hydrogen analyzer shall be demonstrated OPERABLE at least once per 92 days on a STAGGERED TEST BASIS by performing a CHANNEL CALIBRA-TION using sample gases in accordance with manufacturers' recomendations. CALVERT CLIFFS - UNIT 2 3/4 6-26 Amendment No. f 7,EE,H,97, 99

3/4.3 INSTRUMENTATION I 1 BASES 3/4.3.1 and 3/4.3.2 PROTECTIVE AND ENGINEERED SAFETY FEATURES (ESF) INSTRUMENTATION and bypasses ensure that 1) protective and ESF instrumentation syst The OPERABILITY of the j the associated ESF action and/or reactor trip t will be initiated when the parameter monitored by each channel or combi-nation therof exceeds its setpoint, 2) the specified coincidence logic is maintained, 3) sufficient redundancy is maintained to permit a channel to be out of service for testing or maintenance, and 4) sufficient system functional capability is available for protective and ESF purposes from diverse paraneters. 1 1 The OPERABILITY of these systems is required to provide the overall reliability, redundance and diversity assumed available in the facility design for the protection and mitigation of accident and transient con-ditions. The integrated operation of each of these systems is consistent with the assumptions used in the accident analyses. The surveillance requirements specified for these systems ensure that the overall system functional capability is maintained comparable to the original design standards. The periodic surveillance tests per-formed at the minimum f requencies are sufficient to demonstrate this capability. The measurement of response time at the specified frequencies pro-vides assurance that the protective and ESF action function associated with each channel is completed within the time limit assumed in the accident analyses. No credit was taken in the analyses for those channels with response times indicated as not applicable. i Response time may be demonstrated by any series of sequential, over-lapping or total channel test measurements provided that such tests demonstrate the total channel response time as defined. Sensor response time verification may be demonstrated by either 1) in place, onsite or offsite test measurements or 2) utilizing replacement sensors with certified response times. 3/4.3.3 MONITORING INSTRUMENTATION 3/4.3.3.1 RADIATION MONITORING INSTRUMENTATION The OPERABILITY of the radiation monitoring channels ensures that i i

1) the radiation levels are continually measured in the areas served l. CALVERT CLIFFS - UNIT 2 B 3/4 3-1 j

e -r. . ~.,.., - .,-.---,.,....~----.,,.,,.,,..--,,-w. .,,,,,.,--., - n.- n --n- --.-n,,--, m- ,--g

INSTRUMENTATION BASES by the individual channels and 2) the alarm or automatic action is initiated when the radiation level trip setpoint is exceeded. The iodine and particulate samplers were installed to meet the require-ments of NUREG-0737 Item II.F.1. The samplers' operation was not assumed in any accident analysis. 3/4.3.3.2 INCORE DETECTORS The OPERABILITY of the incore detectors with the specified minimum complement of equipment ensures that the measurements obtained from use of this system accurately represent the spatial neutron flux distribution of the reactor core. 3/4.3.3.3 SEISMIC INSTRUMENTATION The OPERABILITY of the seismic instrumentation ensures that sufficient capability is available to promptly determine the magnitude of a seismic event and evaluate the response of those features important to safety. This capability is required to permit comparison of the measured response to that used in the design basis for the facility and is consistent with the recommendations of Regulatory Guide 1.12, " Instrumentation for Earthquakes," April 1974. 3/4.3.3.4 METEOROLOGICAL INSTRUMENTATION The OPERABILITY of the meteorological instrumentation ensures that sufficient meteorological data is available for estimating potential radia-tion doses to the public as a result of routine or accidental release of radioactive materials to the atmosphere. This capability is required to evaluate the need for initiating protective measures to protect the health and safety of the public and is consistent with the recommendations of Regulatory Guide 1.23 "Onsite Meteorological Programs". February 1972, i as supplemented by Supplement 1 to NUREG-0737. I 3/4.3.3.5 REMOTE SHUTDOWN INSTRUMENTATION The OPERABILITY of the remote shutdown instrumentation ensures that sufficient capability is available to permit shutdown and maintenance of HOT STANDBY of the facility from locations outside of tha control room. This capability is required in the event control room habitability is lost and is consistent with General Design Criteria 19 of 10 CFR 50. CALVERT CLIFFS - UNIT 2 B 3/4 3-2 Amendment No.85, Sg, 99

3/4.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) BASES 3/4. 5.1 SAFETY INJECTION TANKS The OPERABILITY of each of the RCS safety injection tanks ensures that a sufficient volume of borated water will be immediately forced into the reactor core through each of the cold legs in the event the RCS pressure falls below V the pressure of the safety injection tanks. This initial surge of water into the core provides the initial cooling mechanism during large RCS pipe ruptures. The limits on safety injection tank volume, boron concentration and pressure ensure that the assumptions used for safety injection tank injection in the accident analysis are met. The safety injection tenk power operated isolation valves are considered to be " operating bypasses" in the context of IEEE Std. 279-1971, which requires that bypasses of a protection function be removed automatically whenever permissive conditions are not met. In addition, as these safety injection tank isolation valves fail to meet single failure criteria, removal of power to the valves is required. The limits for operation with a safety injection tank inoperable for any reason except an isolation valve closed minimizes the time exposure of the plant to a LOCA event occurring concurrent with failure of an additional safety injection tank which may result in unacceptable peak cladding temper-atures. If a closed isolation valve cannot be imediately opened, the full capability of one safety injection tank is not available and prompt action is required to place the reactor in a mode where this capability is not required. 3/4.5.2 and 3/4.5.3 ECCS SUBSYSTEMS The OPERABILITY of two separate ECCS subsystems ensures that sufficient emergency core cooling capability will be availatle in the event of a LOCA assuming the loss of one subsystem through ary sirgle failure consideration. Either subsystem operating in conjunction with the safety injection tanks is capable of supplying sufficient core cooling to lir.iit tne peak cladding temperatures within acceptable limits for all postulated break sizes ranging from the double ended break of the largest RCS cold leg pipe downward. In addition, each ECCS subsystem rrovides long term core cooling capability in the recirculation mode during the accident recovery period. Portions of the low pressure safety injection (LPSI) system flowpath are common to both subsystems. This includes the low pressure safety injection flow control valve, CV-306, the flow orifice downstream of CV-306, and the four low pressure safety injection loop isolation valves. Although the pcrtions of the flowpath are common, the system design is adequate to ensure reliable ECCS operation due to the short period of LPSI system operation following a design basis Loss of Coolant Incident prior to recirculation. The LPSI system design is consistent with the assumptions in the safety analysis. CALVERT CLIFFS - UNIT 2 B 3/4 5-1 Amendment No. 85

s EMERGENCY CORE COOLING SYSTEMS A BASES The trisodium phosphate dodecchydrate (TSP) stored in dissolving baskets located in the containment basement is provided to minimize the possibil:2y of corrosion cracking of certain metal components during operation of the ECCS following a LOCA. The TSP provides this protection by dissolving in the sump water and causing its final pH to be raised to > 7.0. The requirement to dissolve a representative sample of TSP in a sample of RWT water provides assurance that the stored TSP will dissolve in borated water at the postulated post LOCA temperatures. The Surveillance Requirements provided to ensure OPERABILITY of each component ensure that at a minimum, the assumptions used in the safety analyses are met and that subsystem OPERABILITY is maintained. The surveillance requirement for flow balance testing provides assurance that proper ECCS flows will be maintained in the event of a LOCA. Maintenance of proper flow resistance and pressure drop in the piping system to each injection point is necessary to: (1) prevent total pump flow from exceeding i runout conditions when the systhm is in its minimum resistance configura-tion, (2) provide the proper f10w split between injection points in accordance with the assumptions used in the ECCS-LOCA analyses, and (3) provide an acceptable level of total ECCS flow to all injection points equal to or l. above that assumed in the ECCS-LOCA analyses. Minimum HPSI flow requirements are based upon Small Break LOCA calculations which credit charging pump flow following a SIAS. Surveillance testing includes allowances for instrumentation and system leakage uncertainties. The 470 gpm requirement for minimum HPSI flow from the three lowest flow legs includes instrument uncertainties but not system check valve leakage. The OPERABILITY of the charging pumps and the associated flowpaths is assured by the Boration System Specifications 3/4.1.2. Specification of safety injection pump total developed head ensures pump performance consistent with safety analysis assumptions. 3/4.5.4 REFUELING WATER TANK (RWT) The OPERABILITY of the RWT as part of the ECCS ensures that a sufficient supply of borated water is available for injection by the ECCS in the event of a LOCA. The limits on RWT minimum volume and boron concentration ensure that 1) sufficient water is available within containment to permit recircula-tion cooling flow to the core, and 2) the reactor will remain subtritical in the cold condition following mixing of the RWT and the RCS water volumes with all control rods inserted except for the most reactive control assembly. These assumptions are consistent with the LOCA analyses. The contained water volume limit includes an allowance for water not usable because of tank discharge line location or other p5ysical characteristics. CALVERT CLIFFS - UNIT 2 B 3/4 5-2 Amendment No. J6,pp, 99 m

I3/4.7 PLANT SYSTEMS BASES 3/4.7.1 TURBINE CYCLE 3/4.7.1.1 SAFETY VALVES The OPERABILITY of the main steam line code safety valves ensures that the secondary system pressure will be limited to within 110% of its design pressure of 1000 psig during the most severe anticipated system operational transient. The total. relieving capacity for all valves on all of the steam lines is 12.18 x 106 lbs/hr at 100% RATED THERMAL POWER. The maximum relieving capacity is associated with a turbine trip from 100% RATED THERMAL POWER coincident with an assumed loss of condenser heat sink (i.e., no steam bypass to the condenser). The main steam line code safety valves are tested and maintained in accordance with the requirements of Section XI of the ASME Boiler and Pressure Code. The as-left lift settings will be no less than 985 psig to ensure that the lift setpoints will remain within specification during the cycle. In MODE 3, two main steam safety valves are required OPERABLE per steam generator. These valves will provide adequate relieving capacity for removal I of both decay heat and reactor coolant pump heat from the reactor coolant system via either of the two steam generators. This requirement is provided to facilitate the post-overhaul setting and operability testing of the safety valves which can only be conducted when the RCS is at or above 500 F. It allows entry into MODE 3 with a minimum number of main steam safety valves OPEPABLE so that the set pressure for the remaining valves can be adjusted in the plant. This is the most accurate means for adjusting safety valve set pressures since the valves will be in thermal equilibrium with the operating environment. STARTUP anc'/or POWER OPERATION is allowable with safety valves inoperable within the limitations of the ACTION requirements on the basis of the reduction in secondary system steam flow and THERMAL POWER required by the reduced reactor trip settings of the Power Level-High channels. The reactor trip setpoint reductions are derived on the following bases: For two loop operation SP = ( } XI IIY) x 106.5 For single loop operation (two reactor coolant pumps operating in the same loop) SP = (X) - (Y)(U) x 46.8 where: SP = reduced reactor trip setpoint in percent of RATED THERMAL POWEP V = maximum number of inoperable safety valves per steam line CALVERT CLIFF 5 - UNIT 2 B 3/4 7-1 Amendment No.N/. 99

PLANT SYSTEMS BASES maximum number of inoperable safety valves per operating U = steam line 106.5 Power Level-High Trip Setpoint for two loop operation = 46.8 Power Level-High Trip Setpoint for single loop operation = with two reactor coolant pumps operating in the same loop Total relieving capacity of all safety valves per steam X = line in lbs/ hour Maximum relieving capacity of any one safety valve in Y = lbs/ hour 3/4.7.1.2 AUXILIARY FEEDWATER SYSTEM The OPERABILITY of the auxiliary feedwater system ensures that the Reactor Coolant System can be cooled down to less than 3000F from nomal operating conditions in the event of a total loss of cffsite power. A capacity of 400 gpm is sufficient to ensure that adequate feedwater flow is available to remove decay heat and reduce the Reactor Coolant System temperature to less than 3000F when the shutdown cooling system may be placed into operation. Flow control valves, installed in each leg supplying the steam generators, are set to maintain a nominal flow setpoint of 200 gpm plus or minus 10 gpm for operator setting band. The nominal flow setpoint of 200 gpm incorporates a total instrument loop error band of plus 25 gpm and minus 26 gpm for the motor-driven pump train. The corresponding values for the steam-driven pump train are plus 37 gpm and minus 40 gpm. The operator setting band, when combined with the instrument loop error, results in a total flow band of 164 gpm (minimum) and 235 gpm (maximum) for the motor-driven pump train. The corresponding values for the steam-driven pump train are 150 gpm (minimum) and 247 gpm (maximum). Safety analyses show that more flow during an overcooling transient and less flow during an undercooling transient could be tolerated; i.e., flow fluctuations outside this flow band but within the assumptions used in the analyses listed below, are allowable. In the spectrum of events analyzed in which automatic initiation of auxiliary feedwater occurs, the following flow conditions are allowed with an operator action time of 10 minutes. (1) Loss of Feedwater 0 gpm Auxiliary Feedwater Flow (2) Feedline Break 0 gpm Auxiliary Feedwater Flow CALVERT CLIFFS - UNIT 2 B 3/4 7-2 Amendment No. A.7, 49, M, 78 l

ADMINISTRATIVE CONTROLS a. ECCS Actuation, Specifications 3.5.2 and 3.5.3. a b. Inoperable Seismic Monitoring Instrumentation, Specification 3.3.3.3. c. Inoperable Meteorological Monitoring Instrumentation, Specification 3.3.3.4. d. Seismic event analysis, Specification 4.3.3.3.2. e. Core Barrel Movement, Specification 3.4.11. f. Fire Detection Instrumentation, Specification 3.3.3.7. g. Fire Suppression Systems, Specifications 3.7.11.1, 3.7.11.2, 3.7.11.3, 3.7.11.4, and 3.7.11.5. h. Penetration Fire Barriers, Specification 3.7.12. 1. Steam Generator Tube Inspection Results, Specification 4.4.5.5.a and c. l j. Specific Activity of Primary Coolant, Specification 3.4.9. k. Containment Structural Integrity, Specification 4.6.1.6. 1. Radioactive Effluents - Calculated Dose and Total Dose, Specifica-tions 3.11.1.2, 3.11.2.2, 3.11.2.3, and 3.11.4. m. Radioactive Effluents -- Liquid Radwaste, Gaseous Radwaste and Ventilation Exhaust Treatment Systems Discharges, Specifications 3.11.1.3 and 3.11.2.4. l n. Radiological Environmental Monitoring Program, Specification 3.12.1. o. Radiation Monitoring In.:+rumentation, Specification 3.3.3.1 (Table 3.3-6). p. Overpressure Protection Systems, Specification 3.4.9.3. q. Hydrogen Analyzers, Specification 3.6.5.1. i l i CALVERT CLIFFS - UNIT 2 6-18a Amendment No. 74,75,56,99 _x____________.}}

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