ML20203M502
| ML20203M502 | |
| Person / Time | |
|---|---|
| Site: | Duane Arnold  |
| Issue date: | 02/26/1998 |
| From: | IES UTILITIES INC., (FORMERLY IOWA ELECTRIC LIGHT |
| To: | |
| Shared Package | |
| ML20203M500 | List: |
| References | |
| NUDOCS 9803060430 | |
| Download: ML20203M502 (221) | |
Text
{{#Wiki_filter:. . _ . . _ . Enclosure 1 to NG-98-0342 4
-Revision E to the DAEC-Improved Technical Specifications D A O hh331 P PDR 1
Definitions 1,1 1,0 USE AND APPLICATION 1.1 Definitions
.................................... NOTE-------------------------------------
The defined terms of this section ap ear in capitalized type and are applicable.throughout these Technica Specifications and Bases. IEm Definition ACTIONS ACTIONS shall be that part of'a Specification that prescribes Required Actions to be taken under designated Conditions within specified Completion Times. AVERAGE PLANAR LINEAR The APLHGR shall be applicable to a specific HEAT GENERATION RATE alanar height and is equal-to the sum of the (APLHGR) leat generation rate per unit length of fuel rod
-for all the fuel rods in the s ecified bundle at the specified height divided b the number of fuel rods in the fuel bundle at th height.
CHANNEL CALIBRATION A CHANNEL CALIBRATION shall be the adjustment.-as necessary, of the channel output such that it ressonds within the necessary range and accuracy to (nown values of the parameter that the channel-monitors. The-CHANNEL CALIBPATION shall encompass fle.ea k d mone th -
- neWi & rep:,d(/ c:c c7cncnt;.
displayV, sch :: sensort. and trip functions, rcgired tcalarm ;crfern %, W 'fh3 h cd bkNN[Fb AL TEST, Calibration of instrument channels with Resistance Temperature D6tector (RTD) or thermocouple sensors may consist of an inplace qualitative assessment of sensor behavior and normal calibration of the remaining adjustable devices in the channel. The CHANNEL CALIBRATION i may be performed by means of any series of sequential, overlapping. or total channel steps so that the entire channel is calibrated. (continued) DAEC 1.1-1 Revision A
Definitions l.1 1.1 Definitions (continued) CHANNEL CHECK A CHANNEL CHECK shall be the qualitative. assessment, by observation, of channel behavior during operation. This determination shall include, where possible, comparison of the channel indication and status to other indications or status derived from independent instrument channels measuring the same parameter. CHANNEL FUNCTIONAL TEST A CHANNEL FUNCTIONAL TEST shall be the injection of a simulated or actual signal into the channel as close to the sensor as practicable to verif ' OPERABILITY. including 11 com caea n in the 9"' ch = cl :uch::alarmh. inter $ocki,displayi,and 7 and dan %l - crip tunctions? required t: :crform th: ; W fied l NbJ hfrlps afety functionW. The CHA4NEL FUNCTIONAL TEST may be performed by means of any series of sequential, overlapping, or total channel steps so that the entire channel is tested.
~
CORE ALTERATION CORE ALTERATION shall be the movement of any fuel, sources, or reactivity control components. -) within the reactor vessel with the vessel head removed and fuel in the vessel. The following exceptions are not considered to be CORE ALTERATIONS:
- a. Movement of source range monitors, local power range monitors, intermediate range monitors, traversing incore probes, or special movable detectors (including undervessel replacement);
and
- b. Control rod movement, provided there are no fuel assemblies in the associated core cell.
Suspension of CORE ALTEPATIONS shall not preclude completion of movement of a component to a safe position. (continued) DAEC 1.1-2 Revision A
Definitions 1.1 4 1.' 1 Definitions (continued) LEAKAGE LEAKAGE shall be:
- a. Identified LEAKAGE
- 1. LEAKAGE into the drywell. such as that from pump seals or valve packing. that is captured and conducted to a sump or collecting tank: or
- 2. LEAK /SE into the drywell atmosphere from sources that are both specifically located and known not to interfere with the operation of leakage detection systems;
- b. Unidentified LEAKAGE All LEAKAGE into the drywell that is not identified LEAKAGE:
. c. Total LEAKAGE Sum of the identified and unidentified
) LEAKAGE.
LOGIC SYSTEM FUNCTIONAL A LOGIC SYSTEM FUNCTIONAL TEST shall be a test TEST sTETof all Gqp;r5;! logic components y.; . re '1b Trom ,as [cl,!'e fhmose to th; sen,h, up to. 5 'f !~ okhir
, ,6 fRAsnf T sor as practicable but not including. the actuated device. to verify
,M-r c%I6' ' -
OPERABILITY. The LOGIC SYSTEM FUNCTIONAL TEST may be performed by means of any series of sequential.
,- overlapping. or total system steps so that tha_ Ib entire logic system is tested. ge,,ca clos,s of
_43/3] MINIMUM CRITICAL POWER The MCPR shall be the smallest critica' ower bel RATIO (MCPR) ratio (CPR) that exists in the coreChe CPR is that power in the assembly that is calculated by application of the ap3ropriate correlation (s) to _ cause some noint in t1e assembly to experience 9315 oilingftransition) divided by the actual assembly
% operating power. Transition boiling means the Yq boiling reaime between nuclerte and film boiling.
Boiling /Eransitionl is the r egime in which both nucleate and film boiling occur intermittently with neither type being completely stable. (continued) DAEC 1.1-4 Revision A
RPS Instrumentation 3.3.1.1 3.3 INSTRUMENTATION
-3.3.1.1 Reactor Protection System (RPS) Instrumentation LC0 3.3.1.1 The RPS instrumentation for each Function in Table 3.3.1.1-1 shall be OPERABLE.
APPLICABILITY: According to Table 3.3.1.1-1. ACTIONS i-
. . . . . . . - NOTE 2I------ ;9 9 / 8]
K Separate Condition entry is allowed for each channel. D%T [ Ihen anneL-iiplace[in an'fnoperaIle stefus ly M th intcyassoci he/ per c of SR h6.1.3.J'(EFCVfTestingK en d i ditio and Required Xctions/may begelay for t urs, p vided the ass ciatedfunction maintains trig cap lity./gf to 2
...........................'..................................................y / .
CONDITION REQUIRED ACTION COMPLETION TIME
} -
A. One or more required A.1 Place channel in 12 hours channels inoperable. trip. DE A.2 Place associated trip 12 hours system in trip. B. One or more Functions B.1 Place channel in one 6 hours with one or more trip system in trip. required channels inoperable in both QR trip systems. B.2 Place one trip system 6 hours in trip. (continued) DAEC 3.3-1 Revision A
ECCS Instrumentation 3.3.5.1 3.3 INSTRUMENTATION 3.3.5.1 Emergency Core Cooling System (ECCS) Instrumentation
-??"LICA0!LnY: ' EPFAL POWCIs c 30% RTP. 40 6l7,
_ ~ LCO 3.3.5.1 The ECCS instrumentation for each Function in Table 3.3.5.1-1 shall be OPERABLE. APPLICABILITY: According to Table 3.3.5.1-1. ACTIONS hlb.................................. NOTE-------------------------------------
\ , Separate Condition entry is allowed for each channel, y,yg,f. 7
)[ Wh6n a is pl ed inAff ingpe'able, r status soMT) for the p of SR .6.1.3// (EFCr Testing), entryinto asr6ciated C it s and quired 4ctiorpf may be/ delayed as follpw's: (a) or u hopr's for t HPCI S9 stem and RCI stem Resctor V p High Functi s and.(#) for pp to 2 ours for/other )f$e'ssel strume sWa er ed prov Leve -
the associ ed Function maintairs rip capability./
. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more channels- A.1 Enter the Condition Immediately inoperable. referenced in Table 3.3.5.1-1 for.the channel.
(continued) DAEC 3.3-33 Revision A
7.. .. Primary Containment Isolation Instrumentation
, 3.3.6.1 ON
. ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME As required by h1 Initiate action to Immediately OJ. Recuired Action C.1 restore channel to anc referenced in OPERABLE status. Table 3.3.6.1-1. E h2 Initiate action to Immediately isolate the Residual Heat Removal (RHR) Shutdown Cooling System. hAsrequiredby -...--- NOTE--- - Recuired Action C.1 h1 Only ap licabit anc referenced in inopera le channel is Table 3.3.6.1-1. not in trip. I Immediately Declare associated SupkressionPool go]( Coo ing subsystem (s)
-> inoperable.
M h2 ......--NOTE--------- Only ap)licable if inoperaale channel is in trip. Declare Primary Immediately Containment inoperable. (continued) ^ DAEC 3.3-54 Revision A
~
Primary Containment Isolation Instrumentation 3.3.6.1 febte 3.3.6.1 1 (page 2 of 5) Primary Contelnment isolation Instrumentation APPLICASLE CouctTIONS MtBEs OR REQU1 RED REFERENCED OTNER CHANNELt FRtm SPECIFIED PER TRIP REGUIRED SUEVEILLANCE ALLOWASLE FUNCTION CONDITIONS STSTEM ACTION C.1 REQUIREMENTS VALUE
- 2. Primary Contetruent Isolation
- e. Reector vesset Water 1,2,3 2 M st 3.3.6.1.1 a 165.6 inches Level - Low SR 3.3.6.1.4 st 3.3.6.1.8 SR 3.3.6.1.9
- b. Dryuelt Pressure
- High 1,2,3 2 h SR 3.3.6.1.4 at 3.3.6.1.8 st 3.3.6.1.9 s 2.2 pels
- c. Offges vent Stock - e 1 L st 3.3.6.1.2 (b)
High Radletion SR 3.3.6.1.4 s k jlf-)> fC)J(C) SR 3.3.6.1.8 st 3.3.6.1.9
- d. Reactor Building - 1,2,3 1 sa 3.3.6.1.2 s 12.8 ea/hr Exhaust Shaft - SR 3.3.6.1.4 Nigh Radletion SR 3.3.6.1.8 SR 3.3.6.1.9
- e. Refusting Floor 1,2,3 1 'E st 3.3.6.1.2. s 10.6 ea/hr Enhauet Duct - SR 3.3.6.1.4 Nigh Redletion SR 3.3.6.1.8 st 3.3.6.1.9
- 3. High Pressure Cootent Injection (MPCI) System teoletion
- e. HPCI steen Line Flow - 1,2,3 1 F SR 3.3.6.1.4 s 409 inches Nigh SR 3.3.6.1.8 (inboard) st 3.3.i. 1.9 s110 inches (outboard)
(continued) (b) Allar. cole vetue is ceterminee in accordance with the G)AM. (c) During venting or purging of primary conteirment.0.;.. r. -
- r wua-n o mw r, f : ---J d .
04 1 9922 L DAEC 3.3-59 Revision A
Primary Containment Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 5 of 5) Primary Contairunent Isolation instrunentation APPLICABLE CONDITIONS M(BES OR REgUIRED REFERENCED OTHER CHANNELS FRGE SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION C.1 REQUIREMENTS VALUE i
- 5. Reactor idater Cleans (RWtal) System isolation
- a. Differential Flow
- 1,2,3 1 F SR 3.3.6.1.2 s 59 spm Migh SR 3.3.6.1.4 SR 3.3.6.1.8 SR 3.3.6.1.9
- b. Area Teaperature High 1,2,3 , - F SR 3.3.6.1.2 s 133.3*F goy y I ,.
SR 3.3.6.1.4 SR 3.3.6.1.8 SR 3.3.6.1.9
- c. Ares ventitation 1,2,3 F SR 3.3.6.1.2 Differential SR 3.3.6.1.4 Temperature a High SR 3.3.6.1.8 SR 3.3.6.1.9 RWCU Puup Room RWCU Pulp A Room
. s 22.5'F 4
t s 23.5'F RWCU Puip B Room s 34.5'F RWCU Heat Exch Room l - . , s 51.5'F
- d. SLC System initiation 1,2 I SR 3.3.6.1.9 NA
, c. Reactor vessel Water 1,2,3 2 F SR 3.3.6.1.1 a 112.65
- Level Low Low SR 3.3.6.1.4 inches SR 3.3.6.1.7 SR 3.3.6.1.9
- f. Area Near T!P Room 1,2,3 1 F SR 3.3.6.1.2 s 115.7'F Ambient Temperature - SR 3.3.6.1.4 High SR 3.3.6.1.8 SR 3.3.6.1.9
- 6. Shutdown Cooling System Isolation
- a. Reector Steam Dome 1,2,3 1 F SR 3.3.6.1.4 s 152.7 psis Pressure - High qM11 U 3.3.6.1.5 gg3] SR SR 3.3.6.1.9
- b. Reector vessel Water 3,4,5 2() J SR 3.3.6.1.1 a 165.6 inches tevet - Low SR 3.3.6.1.4 SR 3.3.6.1.8 SR 3.3.6.1.9
- c. Drywell Pressure - 1,2,3 2 F SR 3.3.6.1.4 s 2.2 psis High SR 3.3.6.1.8 SR 3.3.6.1.9
- 7. Conteirvuont Cooling System j lactation
- a. Contairvnent Pressure - 1,2,3 3.3.6.1.3 a 1.25 psig J High 4 K) SR S SR 3.3.6.1.8
< SR 3.3.6.1.9 h := = = = m ; ; m , ., m _a2 w e n 5.m . .a w ear m ,:. ...m.
) SLC System initiation only inputa into one of the two trip systems.
k Onty on. trip system requireo in mooES 4 and 5 on.n Rua Sauteown Cooting System integrity meintained. DAEC 3.3-62 Revision A
4 RPS Electric Power Monitoring l 3.3.8.2 I
? 7, INSTRUMENTATION I 3.3.8.2 Reactor Protection System (RPS) Electric Power Monitoring LCO 3.3.8.2 Two RPS Electrical Protection Assemblies-(EPAs) shall be OPERABLE for each inservice RPS motor generator set or i=
alternate power supply. APPLICABILITY: MODES 1 and 2. MODE,5 with any control rod withdrawn from a core cell p 3,q gpcontaining one or more fuel assemblies. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME
~
! A. One or both inservice A.1 Remove associated 72 hours power supplies with inservice i one EPA inoperable. supply (s) power from
, service.
) .
B. One or both inservice B.1 Remove associated 1 hour power supplies with inservice both EPAs inoperable.- supply (s) power from service 1 C. Required Action and C.1 Be in MODE 3. 12 hours i associated Completion l Time of Condition A or B not met in MODE 1 or 2 . (continued) l
- DAEC 3.3-77 Revision A
- t. -
RPS Electric Power Monitoring 3.3.8.2 ACTIONS (continued) CONDITION REQUIRED ACTION N COMPLETION TIME i D. Required Action and 0.1 Initiate action to Immediately associated Completion fully insert all [g113] Time of Condition A insertable control or B not met in MODE 45 rods in core cells 3,4 or)i with any control rod containing one or p% withdrawn from a core more fuel assemblies. cell containing one or more fuel assemblies. SURVEILLANCE REOUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.8.2.1 ------------------NOTE------------------- igq] Only required to be performed prior to enterina MODE 2.from MODE-B-ee 4. when in - or.3 DE 4 for a 24 hours. Perform , CHANNEL FUNCTIONAL TEST. 184 days SR 3.3.8.2.2 Perform CHANNEL CALIBRATION. The 24 months ' Allowable Values shall be:
- a. Overvoltage s 132 V.
- b. Undervoltage 2 108 V.
- c. Underfrequency z 57 Hz.
SR 3.3.8.2.3 Perform a system functional test. 24 months DAEC 3.3-78 Revision A
RHR Suppression Pool Soray 3.6.2.4 3.6 CONTAINMENT SYSTEMS 3.6.2.4 Residual Hcat Removal (RHR) Suppression Pool Spray D. S. S. I. LCO 3.6.2.4 Two RHR suppression pool spray subsystems shall be OPERABLE. APPLICABILITY: MODES 1. 2. and 3. L4TIONS REQUIRED ACTION COMPLETION TIME O <s.s.S.2) A. One RHR suppression A.1 Restore RHR da pool spray subsystem suppression pool inoperable. saray subsystem to OPERABLE status.
<5, 5. B. 37 B. Two RHR suppression B,1 Restore one RHR 8 hours pool spray subsystems suppression pool inoperable. spray subsystem to OPERABLE status.
43.s.s. Lb C. Required Action and C.1 Be in MODE 3. 12 hours <3#' 8'O associated Completion Time not met. At[Q C.2 Be in MODE 4. 36 hours DACC , bis.cn E SWR /4 STS- 3.6-R" " Rov 1. 04/07/93 ,
RHR Suppression Pool Soray 3.6.2.4 SURVEILLANCE REOUIREMENTS DUKVtALLMNLt ( SR '
. 2.4.1 /
Verif each RHR suppr sion pool spr / ^ y 31 days subs stem manual, p r operated. d au matic valve in he flow path at is - n locked, seale , or otherwis secured n position is i the correct sition or 4 can be aligned o the correct osition. '
)
53.6.2
.2 Verify ea RHR pump de lops a flow rate 2 In
- 00) gpm throu , the heat accordance exchan r while opera ing in the with the suppr sion pool spr y mode. Inservi Testin Progr or 92 ys p ' <4.g.s.o S R 3. 6. 2. 'l . i MQ by a cdc kest %f (oo me,4ks M sappre.5sion. po\ spro.f h e & W no w les e ne.
- LLrt obsh ac,h!.d .
N _ J DAcc BR/4 STS- ab Reva.e x E 3.6-4 h ri. 04/077 E
RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 13.1.1.3 (continued) REQUIREMENTS necessity of using an automatic scram function trip. This functional test can be accomplished by placing the associated RPS Test Switch in the trip position, which will deenergize a pair of the automatic scram contactors and in s turn, trip the associated RPS logic. The RPS Test Switches were not specifically credited in the accident analysis and thus, do not have any OPERABILITY requirements of their own. However, because the Manual Scram pushbuttons at the DAEC are not configured the same as the generic model used in Reference 9. (i .e., they are in a seaarate RPS logic - A3 and B3), the RPS Test Switches have 3een found to be functionally equivalent to the Manual Scram pushbuttons in the generic model for performing the weekly functional test of the automatic scram centactors required by Reference 9. If an RPS Test Switch (e., 's (are) not available for performing this test it ., taissible to take credit for a CHANNEL FUNCTIONAL TEST of an automatic RPS trip function,. if performed within the reauired Frecuency for this SurveillancQN.\1mo Nt O. p4 dy MM b. *35E33IIl ' The Frequency of 7 days is based upon the reliability analysis in Reference 9. - g SR 3 3.1.1 3 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. A n 3u_;A ggjg g As noted. SR 3.3.1.1.4 is not required to be performed when entering MODE 2 from MODE 1. since testing of the MODE 2 required IRM and APRM Functions cannot be performed in MODE 1 without utilizing jumpers, lifted leads, or movable links. This allows entry into MODE 2 if the 7 day Frequency is not met per SR 3.0.2. In this event, the SR must be performed within 12 hours after entering MODE 2 from MODE 1. Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR. A Fres tency of 7 days provides an acceptable level of system average unavailability over the Frequency interval and is based on reliability analysis (Ref. 9), (continued) DAEC B 3.3-28 Revision A
i NEERT A
-- As part of the test of the entire channel, a successful test of the. required eontact(s) of a relay may be performed by the verification of the change ofstate of a single co L ,p%.. . ..I.b. . . .. .
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RPS Instrumentation B 3.3.1.1 EGES SURlEILLANCE REQUIREMENTS SR 3 3_ L.l.ji psecd(rgJ A CHANNEL FUNCTIONAL EST is performed on each required channel to ensure at the entire channel will perform the intended function. A Frequency of 7 days provides an acceptable level of system average availability over the Frequency and is based on the reliability analysis using the-concepts developed in Reference 10.
)
SR 3.3.1 1.6 and SR 3 3.1 1_7 These Surveillances are established to ensure that no gaps in neutron flux indication exist from subcritical to power operation for monitoring core reactivity status. The overlap between SRMs and IRMs is required to be demonstrated to ensure that reactor power will not be increased into a neutron flux region without adequate indication. This is required prior to withdrawing SRMs from the fully inserted Josition since indication is being
, transitioned from t1e SRMs to the IRMs.
The overlap between IRMs and APRMs is of concern when reducing power into the IRM range. On power increases, the system design will prevent further increases (by initiating a rod block) if adequate overlap is not maintained. Overlap between IRMs and APRMs exists when sufficient IRMs and APRMs concurrently have onscale readings such that the transition between MODE 1 and MODE 2 can be made without either APRM downscale rod block, or IRM upscale rod block (i.e., approximately one-half decade of range). Overlap between SMis and IRMs similarly exists when, prior to withdrawing the SRMs from the fully inserted position. IRMs are above mid-scale on range 1 before SRMs lave reached the upscale rod block (i.e. , approximately one-half decade of range). As noted. SR 3.3.1.1.7 is only required to be met dt-ing entry into MODE 2 from MODE 1. That is, after the overlap requirement has been met and indication has transitioned to the IRMs. maintaining overlap is not required (APRMs may be reading downscale once in MODE 2). If overlap for a group of channels is not demonstrated (e.g. . IRM/APRM overlap). the reason for the failure of the Surveillance should be determined and the appropriate channel (s) declared inoperable. 1.y those appropriate (continued) DAEC B 3.3-29 Revision A
-. . e. 4 INSERT A
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RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 131.16 and SR 1 3 1.1 7 (continued) REQUIREMENTS channels that are required in the current MODE cr condition should be declared inoperable. A Frequency of 7 days is reasonable based on engineering judgment and the reliability of the IRMs and APRMs. SR 3.3.1 1.8 LPRM gain settings are determined using analytical methods with input from the axial flux profiles measured by the Traversing Incore Probe (TIP) System. This establishes the relative local flux profile for appropriate representative input to the APRM System. The 1000 MWD /T Frequency is based on operating experience with LPRM sensitivity changes. SR 3 3.1.1 9 and SR 3 3 1.1 13 7;iged l A CHANNEL FUNCTIONAL TEST erformed on each required channel to ensure tha e entire channel will perform the intended function. e 92 day Frequency of SR 3.3.1.1.9 is based on the reliability analysis of Reference 9. The 24 month Frequency is based on the need.to perform this Surveillance under the conditions that apply during a plant outage and the potential for an un)lanned transient if the Surveillanc- re performed with t1e reactor at power. Operating e ence has shown that these components usually pass the Survvillance when performed at the 24 month Frequency. SR 3 3 1.1 10 Calibration of tria units provides a check of the actual-trip setpoints. T1e channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value specified in Table 3.3.1.1-1. If the trip setting is discovered to be less conservative than accounted for in the appropriate set 30 int methodology, but is not beyond the Allowable Value. t1e channel performance is still within the requirements of the plant safety analysis. Under these conditions the setpoint must be readjusted to be equal to or more conservative than accounted for in the appropriate setpoint methodology. (continued) DAEC B 3.3-30 Revision A
INRERT A P M art ofthe test of the entire channel, a successful test of the. required con c annel
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SRM Instrumentation B 3.3.1.2 BASES SURVEILLANCE SR 111 ? E and SR 13.1. ? . 6 - REQUIREMENTS (continued)
$57Y A -991',J Performance of a CHANNEL FUNCTIONAL TEST demonstrates the - associated channel will function properly.4 SR 3.3.1.2.5 is required in MODE 5. and the 7 day Frequency ensures that the channels are OPERABLE while core reactivity changes could be in progress. This Frequency is reasonable, based on o]erating experience and on other Surveillances (such as a CiANNEL CHECK). thbt ensure proper functioning between CHANNEL FUNCTIONAL TESTS.
SR 3.3.1.2.6 is required in MODE 2 with IRMs on Range 2 or , below, and in MODES 3 and 4. Since core reactivity changes do not normally take place in MODES 3 and 4 and core reactivity changes are due solely to control rod movement in MODE 2. the Frequency has been extended from 7 days to 31 days. The 31 day Frequency is based on operating experience and on other Surveillances (such as CHANNEL CHECK) that ensure proper functioning between CHANNEL FUNCTIONAL TESTS. The Note to the Surveillance allows the Surveillance to be delayed until entry into the specified condition of the Applicability (THERMAL POWER decreased to IRM Range 2 or below). The SR must be are on Range 2 or below. performed within 12 hours after IRMs The allowance to enter the Applicability with the 31 day Frequency not met is reasonable, based on the limited time of 12 hours allowed after entering the Applicability and the inability to perform the Surveillance while at higher power levels. Although the Surveillance could be performed while on IRM Range 3. the plant would not be expected to maintain steady state operation at this power level. In this event. the 12 hour Frequency is reasonable, based on the SRMs being otherwise verified to be OPERABLE (i.e., satisfactorily performing the CHANNEL CHECK) and the time required to perform the Surveillances. i SR 3 3.1.2 7 Performance of a CHANNEL CALIBRATION at a Frequency of 24 months verifies the performance of the SRM detectors and associated circuitry. The Frequency considers the plant conditions required to perform the test, the ease of (continued) DAEC B 3.3-43 Revision A
_ e INEERT A m
^8 Part of the test of the entire channel, a successful test of the. required c relay may be performed by the verification of the change ofstate of
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Control Rod Block Instrumentation B 3.3.2.1 BASES ACTIONS E.1 and E 2 - (continued) affect the reactivity of the core and are therefore not required to be inserted. Action must continue until all-insertable control rods in core celis containing one or more fuel assemblies are fully inserted. SURVEILLANCE As noted at the beginning of the SRs. the SRs for each REQUIREMENTS Control Rod Block instrumentation Function are found in the SRs column of Table 3.3.2.1-1. The Surveillances are modified by a second Note to indicate that when an RBM channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Coriditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains control rod block capability. U)on completion of the Surveillance, or expiration of tie 6 hour allowance, the channel must be returned to OPERABLE status or the
'j a)plicable Condition entered and Required Actions taken.
T11s Note is based on the reliability analysis (Ref. 9) assumption of the average time required to Jerform channel Surveillance. That analysis demonstrated tnat the 6 hour testing allowance does not significantly reduce the probability that a control rod block will be initiated when necessary. SR 3.3.2.1.1 I^ Ah A CHANNEL FUNCTIONAL TEST is performed for each RBM channel to ensure that the entire channel will perform the intended g function.v It includes the Reactor Manual Control Multiplexing System input.j The Frequency of 92 days is based on reliability analyses (Ref. 8). hesNn of tie deacter Naml Conhs) 1.kWple~iny Qsk inpd kil *cdde. Inf 1 aF d % xd uleeled,' 'pe.r;pberai md uleckf %d %ie r red relecled w.*0 fuo, d ret, or-Y,} kr L.9RM strinys around;i"(ReE 10). t (continued) DAEC B 3.3-52 Revision A
l NEERT A I As part of the test of the entire channel, a successful test ofe the. req
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relay may be performed by the verification or'the change ofs!
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Control Rod Block Instrumentation B 3.3.2.1 BASES (continued) SURVEILLANCE SR '3.21 ? and (R 1321.3 REQUIREMENTS (cont'.nued) A CHANNEL FUNCTIONAL TEST is performed for the RWM to ensure that the entire system will perform ttle intended function.
$ sui b ^ lThe ~ '
CHANNEL FUNCTIONAL TEST for the RWM is performed by attempting to withdraw a controi rod not in compliance with k c4Cllh g the prescribed sequence and verifying a control rod block occurs and for SR 3.3.2.1 2, and by attempting to select a control rod. in each fully inserted group, not in compliance with the prescribed sequence and verifying a selection error occurs. As noted in the SRs. SR 3.3.2.1.2 is not required to be performed until 1 hour after any control rod is withdrawn at :: 10% RTP in MODE 2. and SR 3.3.2.1.3 is not required to be performed until I hour after THERMAL POWER is s 10% RTP in MODE 1. This allows entry into MODE 2 for SR 3.3.2.1.2. and entry into MODE 1 when THERMAL POWER is s 10% RTP for SR 3.3.2.1.3, to perform the required Surveillance if the 92 day Frequency is not met per SR 3.0.2. The 1 hour allowance is based on operating experience and in consideration of providing a reasonable time in which to complete the SRs. The Frequencies are based on reliability analysis (Ref. 8). SR 3.3.21 A The RBM setpoints are automatically varied as a function of power. Three Allowable Values are specified in Table 3.3.2.1-1. each within a specific power range. The power at which the control rod block Allowable Values. which are verified during the CHANNEL CALIBRATION. automatically change are based on the APRM signal's input to each RBM channel. Below the minimum power setpoint. the RBM is automatically bypassed, lhese power Allowable Values must be verified periodically to be within the specified ranges to ensure that the Analytical Limits for the ranges specified in Table 3.3.2.1-1 are met. If any power range setpoint is nonconservative then the affected RBM channel is considered inoperable. Alternatively, the power range channel can be placed in the conservative condition (i.e., enablina the proper RBM setpoint). If placed in this conditi('.. the SR is met and the RBM channel is not considered inoperable. As noted. neutron detectors are excluded from the Surveillance because they are passive devices, with minimal drift, and because of the difficulty (continued) e DAEC B 3.3-53 Revision A
4 INSERT A_ As part of the test of the = tire channel, a successful test of the. required contac relay may be perforrned by the verification of the change ofstate of a . a H16
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Control Rod Block Instrumentation B 3.3.2.1 BASES (continued) SURVEILLANCE SR 3.3 2.1 4 (continued) REQUIREMENTS of simulating a meaningful signal. Neutron detectors are adequately tested in SR 3.3.1.1.2 and SR 3.3.1.1.7. The 184
" day Frequency is based on the actual trip setpoint methodology utilized for these channels.
SR 31215 - A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel ad lusted to account for instrument drifts between successive ca ibrations consistent with the DAEC Instrument Setpoint Methodology. As noted, neutron detectors are excluded from the CHANNEL CALIBRATION because they are passive devices. with minimal drift. and because of the difficulty of simulating a meaningful signal. Neutron detectors are adequately tested in SR 3.3.1.1.2 and SR 3.3.1.1.7. , The Frequency is based upon the assumtion of a 184 day calibration interval in the determin6 tion of the magnitude of equipment drift in the setpoint analysis. SR 3 3'? 1 6 f.o#
@E A CHANNEL FUNCTIONAL TEST is performed for the Reactor Mode Switch-Shutdown Position Function to ensure that the entire channel will perform the intended function The CHANNEL FUNCTIONAL TEST for the Reactor Mide Switch-Shutdown Position Function is performed by attemating to withdraw any control rod with the reactor mode switc1 in the shutdown position and verifying a control rod block occurs.
As noted in the SR. the Surveillance is not required to be performed until 1 hour after the reactor mode switch is in the shutdown position, since testing of this interlock with the reactor mode switch in any other position cannot be performed without using jumpers, lifted leads, or movable links. This allows entry into MODES 3 and 4 if the 24 month Frequency is not met per SR 3.0,2. The 1 hour allowance is (continued) DAEC B 3.3-54 Revision A
1 4 ...
~
INMERT A As part of the test of the entire channel, a successful test of the. required
- ~~"
relay may be performed by the verification of the change of state 04 i @l6 ..
= _ . _ . . _ - .... ._.-
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4 EOC RPT Instrutr/ ation 4 3.4.1 BASES ACTIONS C 1 and C 2 (continued) With any Required Action and associated Completion Time not met, THERMAL POWER must be reduced to < 30% RTP within 4 hours. Alternately, the associated recirculation pump may be removed from service, since this performs the intended
- function of the instrumentation. The allowed Completion Time of 4 hours is reasonable, based on operating
! experience, to reduce THERMAL POWER to < 30% RTP from full power conditions in an orderly manner and without challenging plant systems. 1 SURVEILLANCE The Surve111ances are modified by a Note to indicate that 4 REQUIREMENTS when a channel is placed in an inoperable status solely for performance of required Surveillances entry into associated Conditions and Required Actions may be delayed for u) to
- 6 hours provided the associated Function maintains EX-RPT trip capability. Upon completion of the Surveillance, or
" expiration of the 6 hour allowance, the channel must be returned to OPERABLE s:atus or the a entered and Required Actions taken. Thispplicable Note is based Condition on the reliability analysis (Ref. 4) assumption' of t' e average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the 4 recirculation pumps will trip when necessary. SR 3 3.4.1.1 A CH/NNEL FUNCTIONAL TEST is performed on ecch re utred channel to ensure that the channel will perform the intended
$nsuk function.pThe RPT breaker is excluded from this testing.
' The Frequency of 92 days is based on reliability analysis of q q l(,
- Reference 4.
SR 3.3.4 1.2 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel (continued) 2 i DAEC B 3.3-84 Revision A 4
, , . _ . . , _ . ,.,_.m _ _ _ _ . _ . . . - . _ . -
l IMMERT A_
. . - As part of the test of the entire channel, a successful test of the. require relay may r-be performed by the verification of the change ofstat ~
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ATWS RPT Instrumentation B 3.3.4.2 BASES SURVEILLANCE SR 13421 - REQUIREMENTS Performance of the CHANNEL CHECK for the Reactor Vessel Water Level Low Low Function once every 12 hours ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure: thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CAllBRATION. Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria it may be an indication that the instrument has drifted outside its limit. The Frequency is based upon operating exxrience that demonstrates channel failure is rare. T1e CHANNEL CHECK supplements less formal but more frequent checks of channels during normal operational use of the dis with the required channels of this LCO. plays associated i SR 1342? A CHANNEL FUNCTIONAL TEST is performed on each required c nel to ensure that the channel will perform the intended marl A unction.4 The RPT breaker itself is excluded from this testing. The Frequency of 12 months is based on the fact that AWS is considered a very low probability event and is outside the normal design basis. Therefore, the surveillance frequency is less stringent than for safety-related instrumentation. i (continued) DAEC B 3.3-93 Revision A
- 0.
- rNmT (
- -- As part of the test of the enthe channel, a successful test of the.requind contac relay may be performed by the veri 5 cation of the change of state of
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ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE SR m11 (continued) REQUIREMENTS The Frequency is based upon operating ex)erience that demonstrates channel failure is rare. T1e CHANNEL CHECK
' supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.
SR 3.3.5.1.2. SR 3.3.5.1.3 and SR 3.3.5.1.5 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function.v- M A
}qfG g The Frequency of 92 days for SR 3.3.5.1.3 is based on the reliability analyses of Reference 5.
The Frequencies of 31 days and 12 months (SR 3.3.5.1.2 and SR 3.3.5.1.5. respectively) are based upon engineering judgment and the reliability of the components. SR 3 3.5.1.4 SR 3 3.5 1.6 SR 3 3 5 1.7. and SR 3.3.5 1.8 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel respondt to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel-adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology. The Frequency of SR 3.3.5.1.4 is based upon the assumptica of a 92 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis. The Frequency of SR 3.3.5.1.6 is based upon the assumption of a 12 month calibration interval in the determination of the magnitude of equipment drift in the tetpoint analysis. The Frequency of SR 3.3.5.1.7 is based u)on the assumption of an 18 montn calibration interval in tie determination of the magnitude of equipment drift in the setpoint analysis. The Frequency of SR 3.3.5.1.8 is tased upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis. (continued) DAEC B 3.3-136 Revision A
INRERT A
- - -- - As part of the test of the entire channel, a successful test of the. required contact relay may be performed by the verincation of the change cfstats of a si
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RCIC System Instrumentation B 3.3.5.2 BASES (continued) N SURVEILLANCE to the need to override the logic to prevent ation i REQUIREMENTS of t , uction Transfer when testing F on 3. a 12 ~ (continued) hour allowance vided to complets sting of both 4 instruments instead o sepacat instrument. These instr s our allowances for each in)uts to both the fN HPCI and RCIC Suct ransfer ogics. ur allowance wi ow time to complete testing for J syste SR 3.3.5.2.1 Performance of the CHANNEL CHECK once every 24 hours ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a parameter on other similar channels. It is 'ased on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of - t excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect ' gross channel failure: thus, it is key to verifying the instrumentation continues to operate properly between each
, CHANNEL CALIBRATION.
l Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties. including indication and readability. If a channel is outside the criteria, it may be an indication that the-
- instrument has drifted outside its limit.
The Frequency is based upon operating ex]erience that demonstrates channel failure is rare. T1e CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO. l SR 3.3.5.2.2 i A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. s p y A { The Frequency of 92 days is based on the reliability analysis of Reference 1. (continued) DAEC B 3.3-147 Revision A
- - . . - - - . __ __- . .- _ - - - . . - - -_. - - - .. . = . .. _. . -- INSERT A
. . -. As part of the test of the entire channel, a successful test of the. required con relay may be perfonned by the verification of the change of state o fb I '
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Primary Containment Isolat1on Instrume station B 3.3.6.1 BASES APPLICABLE 5b (c. and R f Area Ama Near Tin Room Ambient. and SAFETY ANALYSES Aree vent,1at,on 01ffarential Tamnerature-wiah LCO. and APPLICABILITY RWCU area area near TIP Room ambient, and area ventilation (continued) differential temperatures are provided to detect a leak from the RWCU System. The isolation occurs even when very small leaks have occurred and is diverse to the high differential flow instrumentation for the hot portions o' the RWCU System. If the small leak continues without isolation, offsite dose limits may be reached. In addition, the Area Near TIP Room Ambient Temperature - High Function isolates the RWCU System to ensure that the assumed environmental conditions are maintained in the first floor of the Reactor Building for equipment qualification purposes. Credit for these instruments is not taken in any translent or accident
~
i Mb ' analysis in the UFSAR. since bounding analyses are performed for large breaks such as recirculation or MSL breaks. b om Mly a; d Area, area near TIP Room ambient, and area ventilation oI d differential temperature signals are initiated from temperature elements that are located in the area that is y Ofc2 ABILITYj being monitored. Six temperature elements provide i'1put to b the Area Temperature-High Function (four in the RWCU heat gQQg exchanger area and two in the RWCU pump area-). However, only two channels are required to be OPERABLE (one in each
@ trip system) to ensure that no single instrument failure can
._oreciuae the 1 solation function >s#se the Area Differential Temperature High Function ljLraMe to detect breaks in t
/ h. M. #41
,p same areas as the Area Temperature - Hioh Functions,
,. ,\ i bg i
i joraeFto/maintayn coverage in both/ areas, eacn area (1 e., , i emot Ithe heat / excha er area are must tfave e ther
' * *3 \ .b' . ;> ' a OPERABLE Ar a Tempe /and ature - the h cha 1 or ch OP A a Vghtilat on Diff ential T mperatu e - Higf cha nelKin
\ M e ch trip sy emj roun' s ** v 3
Twelve temperature elements provide input to the Area Ventilation Differential Temperature-ligh Function. The output of these temperature elements is used to determine the differential temperature. Each channel consists of a differential temperature instrument that receives inputs from temperature elements that are located in the inlet and outlet of the area cooling system and for a total of six available channels (three in the RWCU heat exchanger area and three in the RWCU pum) area). However, only two channels are-required to se OPERABLE. (one in eacn crip system) to ensure that no single instrument failure can (continued) DAEC B 3.3-169 Revision A
Primary Containment Isolation Instrumentation B 3.3.6.1 h BASES sci-ah omN p g 0 9 7,4 L fg i ~ APPLICABLE 5 b. 5c - and Cf area Area Near Tin Room Ambient. and SAFETY ANALYSES LCO. and Area Ventilation Differeni1a1 Teerature-Hioh (continued) ; APPLICABILITY (.W O m preclude the isolation functionys+neefthe Area Temperature V *> ' - H1gn function 1M to detect breaks in the same area as
< F. '* the Area Ventilation Differential Temperature - High
. Function .f4n oroer to ma tain cover e in both a
' s
$~ eachl W ' area have'/u.e., thiOPERABLE either ap nger area a d th heat exc rea Tempera ure e pump ar a) must High c nnel or hTd}3.6.1l
# an APERABLE Area Ventil tion Differpntial Temper ure_- ha cryennel in pach trip s stem.i
- h904 ~ Four temperature elements provide input to the Area Near TIP l Room Ambient Temperature - High Function. However, only two Q}] channels are required to be OPERABLE (one in each trip system) to ensure that no single instrument failure can preclude the isolation function.
The Area. Area Near TIP Room Ambient, and Area Ventilation Differential Temperature-High Allowable Values are set low enough to detect a leak equivalent to 5 gpm. These Functions isolate the Group 5 valves. 5.d - Sir System initiation The isolation of the RWCU System is required when the SLC System tlas been initiated to prevent dilution and rencval of the boron solution by the RWCU System (Ref. 4). The SLC ' System initiation signal is initiated from the SLC System initiation switch. There is no Allowable Value associated with this Function l since the channels are mechanically actuated based solely on l the position of the SLC System. initiation switch. One channel of the SLC System Initistion Function is available and is required to be OPERABLE only in MODES 1 1 and 2. since these are the only MODES where the reactor can be critical. and these MODES are consistent with the Applicability fr" the SLC System (LC0 3.1.7). (continued) DAEC B 3.3-170 Revision A
Primary Ccntainment : solation Instrumentatien B 3.3.6.1 BASES APPLICA3LE 5.d- etc system initutien (continued) SAFETY ANALYSES, LCO. ana (F)f) B92G 3 As noted (footnote-( Yto Table 3.3.6.1 1), this Function is APPLICABILITY only required to ci se the valves associated with one trip system. since the signal only provides input into one of the two trip systems. This results in isolating two of the three RWCU PCIVs. 5e Peacter Vessel Water level -Lnw Low Low RPV water level indicates that the capability to cool the fuel may be threstened. Should RPV water level decrease too far, fuel damage could result. Therefore: isolation of some interfaces with the reactor vessel occurs to isolate the potential sources of a break. The isolation of the RWCU System on Reactor Vessel Water Level-Low Low supports act1ons to ensure that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. The Reactor Vessel Water Level-Low Low Function associated with RWCU isolation is not directly assumed in the UFSAR safety analyses because the RWCU System line break is bounded by I breaks of larger systems (recirculation and MSL breaks are more limiting). ' Reactor Vessel Water Level-Low Low signals are initiated from four level switches that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (var 1able leg) in the vessel. Four channels of Reactor Vessel Water Level-Low Low Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function. The Reactor vessel Water Level-Low Low Allowable Value was chosen to be the same as the ECCS Reactor Vessel Water Level-Low Low Allowable Value (LCO 3.3.5.1). since the capability to cool the fuel may be threatened. This Function isolates the Group 5 valves. / (continued) DR B 3.3-171 Revision A
Primary Containment Isolat1on Instrumentation B 3.3.6.1 BASES APPLICABLE 6.b. neaciv vessel Water tevel l ow : continued) SAFETY ANALYSES. LCO. and RHR Shutdown Cooling System isolation on Reactor Vessel APPLICABILITY Water Level-Low supports actions to ensure that the RPV water level does not drop below the top of the active fuel during a vessel draindown event caused by a leak (e.g., pipe break or inadvertent valve opening) in the RHR Shutdown Cooling System when the system is in operation (i.e., the shutdown cooling suction valves are automatically isolated, and if both of the RHR shutdown cooling suction valves are not fully closed and reactor steam dome )ressure is less than 135 psig (nominal), then the two in>oard LPCI injection valves are also automatically isolated if a low reactor vcssel water level signal is received). Reactor Vessel Water Level-Low signals are initiated from four level indicating switches that sense the difference between the ressure due to a constant column of water (reference 1 ) and the pressure due to the actual water level (variab e leg) in the vessel. Four channels (two channels per trip system) of the Reactor Vessel Water 1 Level-Low OPERABLE to ensure Function that no singleare available instrument failure cart and 6- are req preclude the isolation function. As noted (footnote (4 to f3 Table 3.3.6.1-1). only two channels of the Reactor Vessel Water Level-Low Function are required to be OPERABLE in MODES 4 and 5 (and must be capable of providing input to initiate the isolation of the same division of isolation valves, i.e. , both the Al and B1 channels or both the A2 and B2 channels are required to be OPERABLE). provided the RHR Shutdown Cooling System integrity is maintained. System integrity is maintained provided the piping is intact and no operations with the potential for draining the reactor vessel through the system are being performed. The Reactor Vessel Water Levei-Low Allowable Value was chosen to be the same as the RPS Reactor Vessel Water Level-Low Allowable Value (LCO 3.3.1.1), since the capability to cool the fuel may be threatened. The Reactor Vessel Water Level-Low Function is only required to be OPERABLE in MODES 3. 4. and 5 to prevent this potential flow 3ath from lowering the reactor vessel level to the top of t1e fuel. In MODFS 1 and 2. another isolation (i.e.. Reactor Steam Dome Pressure-High) and administrative (continued) DAEC B 3.3-173 Revision A
i Primary Containment Isolation Instrumentation , B 3.3.6.1
- BASES (continued)
ACTIONS A.1. and A 2 (continued) single failure, and allow operation to continue with no l further restrictions. Alternately. if it is not desired to
" place the channel in tri) (e.g., as in the case where placing the inoperable clannel in trip would result in an isolation). Condition C must be entered and its Required
- Action taken.
An additional Required Action is provided for Function 7.a. Required Action A.2 requires that within 24 hours the containment sprays be inhibited. If a Function 7.a channel is placed in tri') per Required Action A.1. containment integrity could )e threatened due to exceeding the containment negative design pressure limit. Inhibiting the i containment s) rays from spraying both the drywell and the QQ sup3ression clamber removes this threat. One acceptable metlod of inhibiting containment spray operation is to I verify that either the inboard or outboard containment spray bbD Motor Operated Valve (MOV) on each applicable penetration is
'3. fo.2..qror ,- b closed, and then to o)en the circuit breakers that supply g .
g , electrical power tr. t1ose M0Vs (Note: if the inboard suppression chamber MOVs are closed, suppression pool
*'56 cooling is not affected).4 The 24 hour completion time is
{ % Ie mogenMe. r
- b. M
-Tir.e consistent with the time allowed to place the channel in trip.
, 108. Sqpetish , ,90s\Stt*'b )y ' d sys % W). J Required Action B.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in redundant automatic isolation capability being lost for the associated penetrat1on flow path (s). The MSL 1 solation Functions are considered to be maintaining isolation cacability when sufficient channels are OPERABLE or in trip, such that both trip .evstems will generate a trip signal from the given Function on a valid signal. The other isolation functions are considered to be maintaining isolation capability when sufficient channels are OPERABLE or in trip, such that one trip system will generate a trip signal from the given Function on a valid signal. This ensures that one of the two PCIV; in the associated penetration flow path can receive an isolation signal from the given Function. Note that Condition B can not exist for penetrations that are 4 (continued) l DAEC B 3.3-178 Revision A
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS 11 and I2 (continued) b ~ remain unisolated provided action is immediately initiated to restore the channel to OPERABLE status or to isolate the RHR Shutdown Cooling System (i.e.. provide alternate decay heat removal capabilities so the penetration flow path can be isolated). Actions must continue until the channel is restored to OPEPABLE ctatus or the RHR Shutdown Cooling System is isolated. 1 and If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the containment 7 cooling system permissive logic may not allow the rDJ L Suppression Pool Cooling System to be placed in service ( under post accident conditions (i.e. , with containment pressure greater than 2 psig). Therefore, the affected k5 ew\.'% Suppression Pool Cooling subsystem (s) must hp declared due,;b-Sa.m inoperable immediately per Required ActionUK 1. Refer to
@ hh LCO 3.6.2.3 for the Required Actions and associated ggy4 Completion Times for inoperable RHR Su)pression Pool Cooling subsystem (sLa Alternatively.1f the clannel is placed in Ob EC 4N itrip but the containment sprays are not inhibited.
Woh IQ"i N containment integrity could be threatened due to exceeding
$$ese b\
kopenMe the negative design pressure limit. Therefore, the primary containment must,te declared inoperable immediately per 19 M M 3.6 2.q equiredAction@2. mkN bs eM (b1andltT2 L If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, either the primary containment vent and purge penetrati.;n flow pathQ-must be isolated oi administrativeCcontr6T or tne primary containment vent anc purae valves usMernate) monitoring P3 nstrumentation must ,e estabiisneo. 1nese actions are - required because the a:?ility of the Function 2.c isolation 3060_ signals to limit release; to less than 10 CFR 20 limits (if a LOCA were to occur during orimary containment venting o)erations) is threatened. Wien Function 2.c is inoperable. tie activity for which the isolation was intended must be terminated or administrative controls must be implemented. (continued) DAEC B 3.3-183 Revision A
i Priracry Conta1nment ! solation Instrumentation , B 3.3.6.1 BASES SURVEILLANCE sR ' 3.6.1.1 and SR 3 3.6.1.2 REQUIREMENTS Performance of the CHANNEL CHECK once every 12 hours or once every 24 hours ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assurrption that instrument channels monitoring the same parameter should read a) proximately the same value. Significant deviations between t1e instrument channels could be an indication of excessive instrument drift in one of the
- channels or of something even more serious. A CHANNEL CHECK will detect gross channel failure: thus, it is key to i verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.
Agreement criteria are determined by the plant staff based . on a combination of the channel instrument uncertainties. including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit. The Frequencies are based on operating experierice that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO. SR 7 1 6.1.3 at SR 1 3.6.1.4 M 3 3 4 .1. 3 A CHANNEL FUNCTIONAL TEST is performed on each required channel to enture that the entire channel will perform the intenced function, g g g g jg The 92 day Frequency of SR 3.3.6.1.4 is based on the reliability analyses described in References 6 and 7. The t 31 day Frequency of SR 3.3.6.1.3gis based on engineering judgment and the reliability of the components, anci k e 2.4 mon $ ') hqm & SR 3.3.6.l.lo) (continued) DAEC B 3.3-185 Revision A J
I
- i
( 1 NEMTA
- - - As part of the test of the entire channel, a successful test of the. required con rolsy may be performed by the verification of the change ofstate of ~
b 9% - 4 t 1 1
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1 Secondary Containment Isolation Instrumentation B 3.3.6.2
~
BASES SURVEILLANCE SR 3 3 6 2.1 and SR 3 3.6.2 2 (continued) , RE0VIREMENTS Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties,
- including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.
The Frequencies are based on operating experience that i demonstrates channel failure is rare. The CHANNEL CHECK i supplements less formal, but more frequent, checks of
- channel status during normal operational use of the displays 1
associated with channels required by the LCO.
. .b_ .
A CHANNEL FUNCTIONAL TEST is performed on each required 1 channel to ensure that the entire channel will perform the intended function. N w A g {gq g The Frequency of 92 days is based on the reliability analysis of References 4 and 5. SR 3.3.6.2.4 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel 4 responds to the measured parameter within the necessary : range and accuracy. CHANNEL CALIBRATION leaves the channel ! adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology. The Frequency of SR 3.3.6.2.4 is based on the assumption of a 24 month calibration interval in the determination of the 4 magnitude of equipment drift in the setpoint analysis. SR 3.3.6.2.5 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required isolation logic for a specific channel. The system functional testing performed on SCIV/Ds and the SBGT System in LCO 3.6.4.2 and LC0 3.6.4.3. (continued) DAEC B 3.3-197 Revision A
IN! TERT A
. . . As part of the test of the entire channel, a successful test of the. required relay may be performed by the verification of the change ofstate o ~
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. LLS Instrumentation , B 3.3.6.3 BASES SURVEILLANCE As noted at the beginning of the SRs. the SRs for each LLS REQUIREMENTS ' instrumentation Function are Ic.cated in the SRs column of Table 3.3.6.3-1.
- The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for u) to i 6 hours provided the associated Function maintains L.S initiation capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be
' returned to OPERABLE status or the a entered and Required Actions taken.This pplicable Note isCondition based on the reliability analysis (Ref. 3) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the will initiate when necessary. probability that the LLS valves SR 3.3.6.3.1. and SR 3.3.6.3.2 A CHANNEL FUNCTIONAL TEST is performed on eacn required channel to ensure that the entire channel will perform the intended function. L y g gg g g ' The 92 day Frequency is based on the reliability analysis of Reference 3. j A portion of the SRV tailpipe pressure switch channels is located inside the primary containment and is not available for testing during reactor operation. Therefore. SR 3.3.6.3.1 is only required on that portion of the channel that is outside primary containment. SR 3. 3. 6. 3. 3. SR 3. 3. 6. 3. 4. and SR 3. 3. 6. 3. 5 CHANNEL CALIBRATION is a complete check of the instrument loop and sensor. This test verifies the channel responds to . the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology. (continued) ! DAEC B 3.3-205 Revision A
rMRnT A_ -
. . As part of the test of the entire chancel, a successful test of the. required contac ~ ~"
relay rnay be performed by the verification of the change ofstate of a sin W Q9i& .
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SFU System Instrumentatior, B 3.3.7.1 BASES (continued) SURVEILLANCE SR 1371.1 REQUIREMENTS (continued) Performance of the CHANNEL CHECK once every 24 hours ensures that a gross failura of instrumentation has not occurred. A
' CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure: thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.
Agreement criteria are determined by the plant staff, based on a combination of the channel instrument uncertainties. including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its ' limit. The Frequency is based upon operating ex)erience that demonstrates channel failure is rare. T1e CHANNEL CHECK supplements less formal, but more frequent, checks of channel status during norwl operational use of the displays associated with channels required by the LCU. SR 1171.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. g g A g {gg g The Frequency of 92 days is based on the reliability analyses of References 4 and 5. SR 3.3.7.1.3 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary' range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive (continued) DAEC B 3.3-211 Revision A
\ < INEERT A
~ -- - As part of the test of the entire channel, a sucensful test of the. required con
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LOP Instrumentation B 3.3.8.1
~
BASES
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ACTIONS C_1 (continued) declared inoperable immediately. This requires entry into applicable Conditions and Required Actions of LC0 3.8.1 and LCO 3.8.2. which provide appropriate actions fnr the inoperable DG(s). SURVEILLANCE As noted at the beginning of the SRs. the SRs for each LOP REQUIREMENTS instrumentation Function are located in the SRs column of Table 3.3.8.1-1. The Surveillances are modified by a Note to incicate that when a channel is placed in an inoperable statu; sole'y for performance of required Surveillances, entry into asse;iated Conditions and Required Actions may be delayed for up to 2 hours provided the associated Function maintains DG initiation capability. Upon completion of the Surveillance. or expiration of the 2 hour allowance, the channel must be returned to OPERABLE status or the a entered and Required Actions taken pplicable Condition SR 3 3.8.1.1 and SR ~3.3 8 1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. t- yg 4 g {ggf G The Frequencies of 31 days and 12 months are based on operating experience with regard to channel OPERABILITY and drift, which demonstrates that failure of more than one channel of a given Function in any 31 day interval or 12 month interval (as appropriate) is a rare event. SR 3.3.8.1.3 and SR 3 3.8.1.4 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. lhis test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology. (continued) DAEC B 3.3-220 Revision A t
MsnTA
- - - - As Part of the test of the entire clunnel, a successful test of the. required centact(s) of relay may be performed by the verification of the change of state of a ainsic 14 . %lb __.
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RPS Electric Power Monitoring B 3.3.8.2 BASES LCO nominal trip set)oint. but within its Allowable Value, is (continued) acceptable. A clannel is inoperable if its actual trip setpoint is not within its required Allowable Value. Trip setpoints are those predetermined values of output at which
' an action should take place. The setpoints are compared to the actual process parameter (e.g. , overvoltage). -and when the measured output value of the process parameter exceeds the setpoint. the associated device (e.g.. tri) coil) changes state. The Allowable Values (AV) are Jased on the nominal power supply voltage and frequency requirements for RPS components because there are no Analytic Limits in the safety analysis from which to derive the AVs. The nominal trip setpoints are determined from the AVs. accounting for instrument errors and 3rovide adequate protection. The trip
- setpoints derived in t11s manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift. and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.
The Allowable Values for the instrument settings are based on the RPS providing a B7 Hz.120 V 101. to the RPS bus. The settings are calculated based on the loads on the buses and RPS MG set or alternate power supply being 120 VAC and 60 Hz. APPLICABILITY The oper'ation of the RPS EPAs is essential to disconnect the RPS bus powered components from the MG set or alternate power supply during abnormal voltage or frequency conditions. Since the d@radation of a nonclass 1E source supplying power to the RPS bus can occur as a result of any random single failure the OPERABILITY of the RPS EPAs is required when the PPS bus powcred components are required to be OPERABLE. This results in the RPS Electric Power g} Monitoring System OPERABILITY being required in MODES 1 and 2: ant ip300E55 with any control rod withdrawn from a core cell wntaining one or more fuel assemblies. {,@4 @, (continued) DAEC B 3.3-224 Revision A
-______ I
RPS Electric Power Monitoring B 3.3.8.2 BASES ACTIONS fL1 (continued) acceptable because it minimizes risk while allowing time for restoration of the EPA or removal of the associated power supply from service. Alternately. if it is not desired to remove the power supply (s) from service (e.g., as in the case where removing the power supply (s) from service would result in a scram or isolation), Condition C or D. as applicable, must be entered and its Required Actions taken. Cl If any Required Action and associated Completion Time of Condition A or 8 are not met in MODE 1 or 2. a plant shutdown must be performed. This places the plant in a condition where minimal equipment, powered through the inoperable RPS EPA (s), is required and ensures that the safety function of the RPS (e.g., scram of control rods) is not required. The plant shutdown is accomplished by placing the plant in MODE 3 within 12 hours. The allowed Completion Time is reasonable, based on operating experience, to reach
. the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
[191 0 U 3M cr] If any Required Action and associated CoFpletion Time of Condition A or B are not met in M00E#5 with any control rod withdrawn from a core cell containing one or more fuel assemblies the operator must imediately initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Required Action D.1 results in the least reactive condition for the reactor core and ensures that the safety function of the RPS (e.g., scram of control rods) is not required. (continued)
< DAEC B 3.3-226 Revision A i
RPS Electric Power Monitoring B 3.3.8.2 BASES SURVEILLANCE SR 13821 y REQUIREMENTS A CHANNEL FUNCTIONAL TEST is performed on each overvoltage.
, undervoltage, channel andtheunderfrequency will perform intended function.t_ channel yc A [qo to$ ensure that AsnotedintheSurveillance,theCHANNELFUNCTIONALTESTish only required to be 3erformed while the plant is in a condition in which tie loss of the RPS bus will not jeopardize steady state power operation (the design of the system is such that the power source must be removed from service to conduct the Surveillance). The 24 hours is intended to indicate an outage of sufficient duration to allow for scheduling and proper performance of the Surveillance.
The 184 day Frequency and the Note in the Surveillance are based on guidance provided in Generic Letter 91-09 (Ref. 2). SR - 3 3 8 3 2 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies that the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology. The Frequency is based on the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis. SR 13823 Performance of a system functional test demonstrates that, with a required system actuation (simulated or actual) signal, the system will automatically trip open the associated EPA. Only one signal per EPA is required to be tested. This Surveillance overlaps with the CHANNEL CALIBRATION to provide complete testing of the safety function. The system functional test of the Class 1E i circuit breakers is included as part of this test to 3rovide complete testing of the safety function. If the breaters (continued) DAEC B 3.3-227 Revision A
NSERTA
- --- As part of the test of the entire channel, a successful test of the. required contact (
relay rnay be performed by the verificazion of the change of state of a sin ~ t ._ _._
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RCS Leakage Detection Instrumentation B 3.4.5 BASES ACTIONS C.1 and C.2 (continued) that the plant will not be operated in a degraded cui h uration for a lengthy time period. D.1 and 0.2 M If any Required Action of Condition AA or C cannot be met within the associated Com)letion Time, the plant must be brought to a MODE in whic1 the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to perform the actions in an orderly manner and without challenging plant systems. " SURVEILLANCE SR 3451 REQUIREMENTS . This SR is for the performance of a CHANNEL CHECK of the required Primary Containment Air Sampling System. The check gives reasonable confidence that the channel is operating properly. The Frequency of 12 hours is based on instrument reliability and is reasonable for detecting off normal conditions. SR 3 4 5.2 i8 3 This SR is for the performance of a CHANNEL FUNCTIONAL TEST of the required Primary Containment ir Sampling System instrumentation. eauioment drain sump. flow integrator and InswY b floor crain sump flow integritor? EO testsensurel that the m monitors can perform their function in the desired manner Obl9HS)' and also verifies the Primary Containment Air Sampling System alarm functions properly. The Frequency of 31 days considers instrument reliability, and operating experience has shown it proper for detacting degradation. SR 3453 This SR is for the performance of a CHANNEL FUNCTIONAL TEST of required equipment drain sump flow timer and floor drain sump flow time The functiona'l test verifies the [nsec+ A - h @qlG (continued) DAEC B 3.4-29 Revision A
--- - As part of the test of the entire channel, a successful test of the required contact (s) of a channe relay may be perfonned by the verificarica of the change ofstate of a single contact ~~
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I RHR Suopression Pool Spray B 3.6.2.4 B 3.6 CONTAINMENT SYSTEMS B 3.6.2.4 Residual Heat Removal (:HR) Suppression Pool Spray BASES
'[99 2.O]
/ / / ~
BACKGROUND Foll g a Dprign Basis. Accident (DBA), the Rk Suppres on ' Pool pray ystem remgves heat frem the suppr ssion cha er air pace. e supppe'ssion pooJMs designed o absorb he t hh b] s den put of at from thyprimary sy' m from a api epressu ' ation of tne reactor p ssure ve el (RPV) or a
- NW)M thr gh saf reliefva.Wes. The he additio ppressio pool results in increas steam in he o the suppress n chamber /which increa s primary ontainme pressup . Steam.olowdown from BA can a o bypass le suppression pool and end up i he suppr sion cna er ajrspace. Sofne means must btf provided o remove eat fr j Xhe sup 'slon enamber g that the essure a temp aturej insid imary containment remin thin ana ~ zed d cn J t Jim / This> function is provided by two reduncant RHF, CSYo,t'I suppression pool saray subsystems. The aurcose of this LCO is-to ensure that aoth subsystems are OPERABLE-in applicable ,
MODES. Each of the two RHR suppression pool spray subsystems ' 2 contains twoapumos and one heat exchanger, which are manually initiated and independently controlled. The two subsystems perform the suppression pool spray function by circulating water from the suppression pool through the RHR heat exchangers and returning it to-thetsuooression cool - spraysparger/. The spargers only accommooate(small DN"> portion of tne total RHR pu'ab flow; the remalnoer of the fics returns to the suppression pool througn the suppression s ft pool cooling return line. Thus, both suppression pool cooling and suppression pool spray functions are performed when the Suppression Pool Spray System is initiated. RHR service water circulating through the tube side of the heat exchangsrs, exchanges heat with the suppression pool water and discharges this heat to the external heat sink. Either RHR suppression pool spray subsystem is sufficient to condense the steam from small bypass leaks from the drywell to the suppression chamber airspace during the postulated DBA. (continued) TS - B 3.6-B Y.$/7/95
, ITS BASES 3.6.2.4 g L_ t h, %q.
INSERT FOR BACKGROUND The suppression pool is designed to absorb the sudden input oi heat from the pruna. r system from a Design Basis Accident (DBA) or a rapid depressurization of the reactor pressure vessel (RPV) through the Safety Relief Valves. The prunary means provided to remove heat from the suppression chamber is the RHR Suppression Pool Cooling System. Steam blowdown from a DBA can bypass de suppression pool and end up in the suppression chamber airspace as a result of the allowable leakage between the Drywell and Suppression Chamber. Although not required by the accident analysis to ensure that the suppression chsnber remains within the analyzed design pressure and temperature limits, condensing the steam in the suppression chamber airspace reduces the long-term pressure response in the primary containment. e 4 __b
RHR Suppression Pool Soray B 3.6.2.4 BASES (continueo) rj$ 0.j, APPLICABLE Reference 1 centains the results of analyses used to predict SAFETY ANALYSES primary containment pressure and temperature foilowing la,rg
^ and small break loss of coolant accidents. 4c inuunu v. R' _
t4e analyses -H-t-e demonstrate that the pressure reduction h, - capacity of the RHR Suppression Pool Spray System is
%' d rp <QOd=unc to maintain the primary containment conditions within design limits. The time history for primary WM @
%*#N *M containment pressur' s calculated to demonstrate that the
- maximum pressure re...ains below the design limit.i gI The RHR Sup cw.oea 7 of the NRC . Olicy Stgression Pool Spray System satis (gg y A9fLtCABLg' 5W6Ty L t==t. gg f m cpg.so.M(c.)(t/F QNA4 ns _ ___./ 2 LCO In + N avant :f : DB? ,- mini u; of die RHR suppression pool
/p8 /4g g N sorav subsystem,1 requwed uv un uwoi.e potential bypass I leakage patas =d 21':tei" the pri cry =nt;in ;nt p;;k
@f.%@e sist wdh .h>prcn urc belen the den u linuLs (Ref. 1). To ensure that w /-Ms W.b.7j= i subsystems must be OPERABLE with power from two safetythcc c;qui capa;)iqis related independent power supplies. Therefore. in the c.ent >
a.4\dle' ; cf an a-c cident, at least one subsystem +sdEERABLE assuming g6 the worst case single active failure. An RHR suppression 2001 spray subsystem is OPERABLE when one of the pumps, the leat exchanger, and associated piping. valves, instrumentation, and controls are OPERABLE.
%e. rea.k e prusu.r-iseNf b
APPLICABILITY In MODES 1. 2. and 3. - could cause pressurization of primary containment. In MODES 4 and 5. the probability and conseouences of these e'nts are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining RHR suppression pool spray subsystems OPERABLE is not required in MODE 4 or 5. ACTIONS AJ,. Pg With one RHR suppression pool spray subsystem inoperable. the inocerable subsystem must be restored to OPERABLE status 30 within 3 days. In this Condition. the remaining OPERABLE RHR suopression pool spray subsystem is adequ:t: to perform primary containment bypass leakage,miti;ucivo .~ w +iun. Shh a,wd\c. a.3 a 6ck-q h o.ssist wA b (continued) ITS -P .id 07/05 B3.6-(
ITS BASES 3.6.2.4 q q 7,o] INSERT FOR APPLICABLE SAFETY ANALYSIS > RHR Suppression Pool Spray is included in these Technical Specifications solely due to , an agreement between the NRC and DAEC to classify the original Relocated Item as "beyond the scope of the conversion to the ITS." This was done, I ot due to any technical issues, but to facilitate the NRC's completion of the Safety Evalua don for the conversion, as the necessary NRC resources were not available to complete th e review on the ITS schedule. _.m____.._._m____
1 RHR Suppression Pool Spray B 3.6.2.4 BASES TA0 ACTIONS U (continued) r However, the overall reliability is reduced because a single failure in the OPERABLE subsystem could result in reduced o
#1M ce H 9 "F ;F7 ;;GIM oi~>' L vora mibwai'en ca) ability. The day N2 Completion Time was cbosen in light ofetle redundant RHR C%d J J su)pression su) system andpool this period.
ray ca the s$ow pro) abilities
) ability of a aTforded by the DBA occurring OPERABLE during MM u
5 With both RHR suppression pool spray subsystems inoperable, at least one subsystem must be restored to OPERABLE status within 8 hours. In this Condition, there is a -"'-"^
, R io ] loss of theprimary containment bypass leakage. iti;ction a =cu er., o.e 8 hour Completion Time is based on this loss 1
Afunction and is considered acceptable due to the low rg79p'C"i3i C remove heatcontainmerit primary from are available. probability of a GB4 and because -e g C.1 and C 2 If the inoperable RHR suppression pool spray subsystem cannot be restored to OPERABLE status within the associated Completion Time. the plant must be brought to a MODE in which the LCO does not apply. To acnieve this status, the plant must be brought to at least MODE 3 within 12 hours and MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the recuired plant conditions from full power conditions in an orcerly manner and without challenging plant systems. SURVEILLANCE SR 162a1 REQUIREMENTS # Verify"ng the c rect alig ent for manuyl. power o rated and tomatic v lves in t RHR sup3resyion pool sp y mode f1 path prov des assur ce that t1e roper flow ths will i fex'stforsy y lves that em operat n. This SR oes not app y to re locked sealed. or o erwise sec red in h p -k S e ) osition si ce these lves were ve ified to be in the 1 corrart er ition ori to locking, sealing, or securing A] (6adGILLAdCr 9 E Q Lit 9 @ > (continued)
$k b n b?%Y5.--
_ _ _ _ _ _ B3.6-X -m -uo u
ITS BASES 3.6.2.4 %90] INSERT FOR SURVEILLANCE REOUTREMENTS Verifying that the spray header and nozzles are unobstructed assures that the suppression pool airspace can be sprayed when desired. An air test is specified as this test is generally performed on both the drywell and suppression pool spray nozzles at the same time and it is not desirable to spray water into the drywell, due to the adverse impact on equipment located there. Opererating experience has shown that these components usually pass the SR when performed at the 60 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint. v 5 4 4 h . .
i RHR Suppression Poci Soray B 3.6.2.4 BASES [9 % 03 SURVEILLANCE ISR- ^-- C 12 : REQUIREMENTS c.vc.uncdQ valve s also al ed to be /n the nonac dent position pro ded it can e aligned to the accide t position wit n t time assun d in the a ident analys s. This is ceotable s' ce the RHR ,,,uopression p ol coolit.g mode is
, nually i t1ated. Th s SR does not equire any tes..ing or valve man ulation: ra er. it involv s verification that those va es capable f being mispo tioned are in e
@ correc position, is SR does no apply to valve that car.no be inadvert tly misalign . such as chec valves.
Th Frequency of 31 days is just fied because e valves ar rated under rocedural contr 1. improper v ve positio uld affect y a single su ystem. the - ability of an ' vent requir ng initiation of the system is ow, and t subsystem a manually ini ated system. is Frequ cy has been own to be accep ble based on eratino (experien e. _ - -
-SR 3.6.24 2-IVerif ing each R pump devglops a flow ra e 2 [400] gam )
whil operati in the sup'pression pool s ray mode wit 1 f ow th ugh the eat exchan ensures that ump performanc has
- 1 npt degraded during t ycle. Flow i a normal test f gentrifu 1 pump perf ance requir by Section XI the
'B ASME Co 'e (Ref. 2). This test confitms one point the I pump sign curve d is indicativ4 of overall pe ormance.
Such 'nservice i pections confipdi component OP ILITY. tr d performan . and detect tncipient failur by e i icating abn al performance. The Freque of this SR [in accor he Frequen. nce with the Ifservice Testing' Program, but must not exceed 92 days].
/
LL REFERENCES 1. 4 FSAR. Section E6.2F.
-2. AS E. Ocilec and Fce w e ienei Code. 2eWuii AI.
DAEC- b t.s% 6
%4-5TS- _ _ _ _ _ B3.6-)NA
{ Rev ic 0?/07/0E-
SCIV/Ds B 3.6.4.2 I
. BASES (continued) -
APPLICABLE The SCIV/Ds must be OPERABLE to ensure the secondary SAFETY ANALYSES containment barrier to fission product releases is established. The principal accidents for which the secondary containment boundary is required are a loss of coolant accident (Ref.1) and a fuel handling accider# inside secondary containment (Ref. 2). The secondary containment _ performs no active function in response to either of these limiting events, but t!)e boundary established by SCIV/Ds is required to ensure that leakage from the primary containment is processed by the Standby Gas Treatment (SBGT) System before being released to the environment. Maintaining SCIV/Ds OPERABLE with isolation tim within limits ensures that fission products will remain trapped inside secondary containment so that they can be treated by the SBGT-System prior to discharge to the environment. SCIV/Ds satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). LCO SCIV/Ds form a part of the secondary containment boundary. The SCIV/D safety function is related to control of offsite radiation releases resulting f DBAs@ql6 bpb Kc. The power operated isolation va ves are considered OPERABLE when their isolation times are within limits and the valves actuate on an automatic isolation signal. A controlled list of Secondary Containment Automati- Isolation Valves / Dampers covered by this LCO. ..ig with their associated stroke times, are listed in Plant Administrative Procedures. d The normally closed isolation valves or blind flanges are considered OPERABLE when manual valves are closed or ope... in accordance with appropriate administrative controls.
. . automatic SCIV/Ds are de-activated and secured in their closed position, and blind flanges are in alace. A blind flange (e.g. - a utility penetration) may 3e opened, in accordance with applicable administrative procedures. if the secondary containment negative pressure surveillance is performed with an equivalent (or larger) penetration open, with secondary containment still considered OPERABLE.
(continued) DAEC B 3.6-79 Revision A
Refueling Equipment Interlocks B 3.9.1 BASES ACTIONS L.1 (continued) Suspension of in-vessel fuel movement shall not preclude completion of movement of a component to a safe position. SURVEILLANCE SR 3 0.1.1 REQUIREMENTS Performance of a CHANNEL FUNCTIONAL TEST demonstrates each required refueling equipment interlock will function properly when a simulated or actual signal indicative of a required condition is injected into the logic. The CHANNEL FUNCTIONAL TEST may be performed by any series (of sequential. overlapping, or total channel stepshso that the entire char;nel is tested, g hg The 7 day Frequency is based on engineering judgment and is considered adequate in view of other indications of refueling interlocks and their associated in are available to unit operations personnel. put status that REFERENCES 1. UFSAR. Section 3.1.2.3.7. -
- 2. UFSAR. Section 7.6.2.
- 3. UFEAR.Section15.4.3.
- 4. UFSAR. Section 15.4.4.
DAEC B 3.9-4 Revision A
INSERT A
--- - As part of the test of the entire channel, a successful test of the. required contact (s) o relay enay be performed by the verification of the change of state of a sing ~
v jy N/8. _ . _ . .._ _ . . _ . - . _ , .
= . _ .
M_
.w, .
e . a
r - - - Refuel Position One-Rod-Out Interlock . B 3.9.2 BASES SURVEILLANCE SR 1922 RE0VIREMENTS (continuea) Performance of a CHANNEL FUNCTIONAL TEST on each channel demonstrates the associated refuel position one-rod-out
- interlock will function properly when a simulated or actual signal indicative of a recuired condition is injected into y g h-,X tne logic) The CHANNEL Fl.NCTIONAL TEST may be performed by any series of sequential, overlapping, or total channel
{9916-' steps so that the entire channel is tested. The 7 day Frequency is considered adequate because of demonstrated circuit reliability. procedural controls on control- rod withdrawals, and visual-and audible indications available in the control room to alert the operator to control rods not fully inserted. To perform the required testing, the applicable condition must be entered (i.e., a control rod must be withdrawn from its full-in position). Therefore. SR 3.9.2.2 has been modified by a Note that states the CHANNEL FUNCTIONAL TEST is not required to be performed until 1 hour after any control rod is withdrawn. , s
.\
REFERENCES 1. UFSAR.-Section'3.1.2.3.7. ,
- 2. UFSAR. Section 7.6.2.2.
- 3. UFSAR. Section 15.4.3.
DAEC B 3.9-8 Revision A
INSERT 3
. As part of the test of the entire channel, a successful test of the. required contact (s) of a relay may be performed by the verification of the change of state ofa single c ~
10 _ . - . . _ ____ - . . 0.0.lb -. .
.l . . . . . _. _
.e . . _.
. _. 6
- e. .-
.9
Doc. cf7s 3/4.s.S p Speds,c.Eierns 9.i. l/'3 6.2.4/ i Ai CJ5 E/4.5.S c 5-1
.m...... x ; 7.
--- ----.---., I g.- : -- . . . n u.o : 7_ ----
~
r-
- 5. With the LPCI suosystem esos or g2 foons to ne inoserssle for any reason.*/;.-; ::: ::= --
- tr }
dg { Al0 s r b "~* retarsf.=
.-----;- 1. frestore tne LPCI th' ,
//IMJ
-Q CAMAc.ErmQ dd ACMewDj
, somsystem to OPGAELE status j Qttnin7 days. /
[0therwiss, be in at least HOT
~
- 6. o f BRT20b51 within the next 12 hours-and in COLD SIETTD0lat within the jylEput of Cardshnh I
{ (fe11 swing 24 heers. gyg3,g,l _ ^__t .._ . : fe, sv <::? ' : _ C763/kl.3.6
%.n.i 9^ , as , .s.n. z N99*3 . {The sussression sool(- evwinFlhge rs ala.s. s_'
spray sonst of the restoual heat removal (IBR) system *=11 he r OPDABLE wt th two (T; ' ^ ;-- ' -- r S LC.O3.'44.h l leess-eeab/ wnen um ruastar water-th is .. " than 212*F Qb { tes 2.5.sg pfcde/sh3.le.9.2. h, 3 2. With one suppression pesi spray} P' " IC
;T"5 3/4.5.6 8 "6 ss. ,
status within 3 ag;or ce tn aT. (least NOT SHU4wWN within the ,. % g next 12 hours ana in COLD slalTDOWN within the following 24 #
'k[Khoqt], e
, hours.j-
- 3. With bo Achu. B )
'~
I los.s: N e itnaceraale, restore at hussression
- :- m cool m msorsy u ;1
> A 2.
(O'63k.5 > least one long ofh r _ J ty ; Xsuperasston pool C:: : 72n ;J.3 e 3/Q.f.h GPERABLE status within a hourster,n ( De in MUT IHLJTDOWN within the ~ ! next 12 hours and in CDLD OWN within the following 24 i
' chen C Cfr5 3N.6. B/
f -
- The LPCI suasystem may be considered
- OP EARLE during alignment to and soeratton in, RHR Shutcown Cooling made if casable of being manually re-e11gned h l 4 gg 3,g, (remste or local) to the LPCI moca. J AMEND".ENT NO. MN,.'7F. I::0 3.5-4
Doc c3 3/q,s g SpecLhus s.s.2 4}crs sk.s.s l LIMITitlG C0t101T10'15 FORAT10tl C:?: SURVEILL A*;CE PEOUIREuggyg l l
'3.lo.N.2 EN 64ppress$o,t PooD
- 0. }-^;i. moi Serav f =1'.y h
---"' ~ @ umcac.oGQ 1
F Surveillance of the ---""- - # spray loops shall be performed as follows: i ki l
- 1. During each five year period, an air test shall be performed on the
{CT5 3/9 415M(& crneacers =Csuppression and nozzles. pool spray / se 2.ro. 4 2. . ;n 4EN0!iENT NO.10S,277. 2;D 3.5-4
Spa e $e.#1,'s 4 l.O y .,7.... ...... A s "*ca5'**y N .m: : 20 : ;r C Calikesti n I - : _m; , , OM C al t a nt W aaans. tne m:..':n 'yn ;c Hjustment of 4Ame+wnem+ _ c,L u d ' ; : . o ut ouL,4e t h at it 4earetoonos, within :::;;;;!;qange anc 4 accurac yg. to .e kneer . alve/*4 o' the re*ameter htner ri. .u
'^^^-- -- m A il [$Uc , moni tert.fh7. et t ac az 1 m.v. a accur.y ! --
***88"'
nnsgunent 4 its setpoin a (Ner. in the 1 Cesign contre Leoctritet anc 1 intestn* s us ir. t=e Tecnnte seeificatient. 2 - __ % f,, L ,,, ) 'n- ; te:.t211bratier. may be pp.rterme3 tytanv se-tet of Q_ secuential, overlapping, or total enannel steps etnat t he_ g J. NSERT" f enttre ' it
- fis calibi ated. Q'-- -
_ h . M -- r c-, W er n E d M' - - --- - c.'..: d : .: W !
@ ,. asp ~"m '::
DRn ~<!.-'." d
"" D(M CHANNE Danr.al - A cnan . 'E. ~
. i arrangstent a sensor ano ass ate c ca.2nts used to aluate plant variat t.nc produce discr L.q' If g'J"[
4q outp 5 usec in logic.
- channel s terminates nd loses its .
- 'oseti- wneer individue channel catoJ's are {=rinea in logic.
--et-- : c ::: :: C Functional Test - 9f ! :t- - -9 channel FunctionalTg gy.gg d
- ' ;; ........J ; :: :4the injection of a simulatec kignal int ,_-%
IN sid r 5'A sne enannel as close to the sensor as practicable to verif FritatILIT1, t n; r. . a r ; . ... n *- g :!:r ' '^'eu r.; .;d en. (n n4...mi. . .---i. .. m e a... .m. . .. .., e n , 4 o es , en. 4 3.. .._ : ; e g : e [4...i -'
. . ...----- i--
'~- ~ - ' ' ' ' ' ' '
4.ih . . .
. a;; r-a' t.g,)'A/=::;;:t":
4.e . . . - ..; ec
^-
-tr-cual i t~a t i v ef-* = ' 1t Chg .
r :t!, g'l ch ~W by onTervationi 5, h8#'8##"" ' ;^ :n: {1* *ge r . m4,e4,8 lude, weer enavior during operation. 'This determpnati, possible, comoarischof the ':.;'.rr--: r enanne smeDc.h,on
. er 51"a% alo;m_J J"i ' : :: -- inoependent instrunentfmensurino the same "- '- ahJ 75 7Ws cA,,,neQ ur eAacinzg fre e-- .a -
.__ a L2gi 5.ygg'i F'unct innan Tg . A Lgg_ig 5 tem Tunctional Tg, _ @r* *s A le r_
88
,',.4 -
snsTi te a test of~aljalogte comoonEts . ,, s.re l WI and Ain 9;,g centacts.4cf a lo
% p v~nTs,t.it) f ron TffTor nc;;g ic circuit . .-_the- -actuated - - - . , - - - . - ,
device, to verify
~
. E.74. I,*/
de n,Ts/ _ EARILITY The; Lg: r gi including;ctional 5 Fun Tgt may be performeo by __ ,,o any series or secuentTal, lapping or total system steps . J. aTc.d _ that the entire logic systen is tested. to
# E#' I* . ficSystem-Atripsyst' eens an arrangernent of in trunen 8'sPrack. ,Me 3 J ch nel trip signals and aux iary equipment required t initiate actio to accomplish a protecti trip function. A trip s tem up T~o~r I.wr ra7 may reo e one or more instrunent hannel trip signals rela d to I one or mor. lant persneters in orde o initiate trip system action. Init ion of protective actio ay require the trippin A of a single trip kystems.
stem or the coincident ping of two trip Pro ction Action - An etton initiated by the taction system wnen limit is reacned. protective action can at a channel k or syst level. 1.0-6 Amenoment No. )ff, ))f. Jg.150 JtA : pv b'f9 _ l
ITS 1.0
.ndf.ll lnclde f$e. INSERT 5 ffeedre chamel, felwNdy enNNBL ruNcnML TTsr gl,s paaJ g e CHANNEL CALIBRATION hall encompass icac cc=penen::, =:h =}sens U ^dis play 4 ar4d trip functions,.reqd.ed te ped;m i; speciSed ad::y f=:ica(s). Calibration of tnstrument channels with Resistance Temperature Detector (RTD) or thermocouple sensors may h j consist of an in place qualitative assessment of rnsor behavior and normal calibration of the (remaining adjustable devices in the channel.
INSERT .' '- 9Ih rquhed 3
... including dl ecmp^nents in ic chand, =ch = alarm), interlock (, displayj, and trip functionsy uixd ic pednn 6: ;pccined :dety f=; ion (s).
od c ha.acl bhre kfs INSERT 6 The CHANNEL FUNCTIONAL TEST may be performed by means of any series of sequential, overlapping, or total channel steps so that the entire channel is tested. DAEC Revision A
^
Q3.6,l-l) g gg Tame 2.2
- l g '
h ** Q SPecsrie a , ( MHlH881 JwaswdL (FRoyprogigIg) g
- Q I IAPPLICA8tE 4958A1481G.
(OPERAthE CHAleIELS PER T 1 AT z'. . . g l 7; 4A4B FUNCTI0li g QdowMVsist).= = "-- ~
-- kH00t(5) SYSif SI iACTIO@
8
1 Connon Isolation Slanals hn Reactor Water !cvel-tow 17 I s .
2 rg-j 1,2,3 6- 2 L dD j p Reactor Water Level - Low-tow-Low I
- 18. I s ,
N k Md I\ O
,5 *
'-]
Q I 3f 6~ Ja ~5.d) Drywell Pressure - High s .0 sig ~l 2 _ Z m- - (Td S C
- ff E
, ,3 2 .4 sac n'scoss4,n of o
R2 MW.,_ W 9 4 F Mptn Steam Line Isol,atto. 8 pg 1 2 O h Hain Steam Line Pressure - Low O - Main steam Line flow - High s4 of a ed 1.2.3 2/line 1 N dg te F1 gpggi-f ; Condenser Backprossure - High s2 In. 1. d
- 2 1 M6 s .00*F 1.2,3 4 1 41@ *h QiiainTemperature Steam Line- Tunnel g g,. g liigh 1.2,3 4 1 -2O l,, 0 l hTurbineBuildingTemperature-High s 200*
hMainSteasLineRadiation-High s3 -} Rated 1,2,3 2
\ M x3
** ' ;% ^
All as%as 9163.3.c.I p. r e val sas,s.w Aa-.w j
halt 7 4 SR7j
~
- h 6.l-l) !
Table (Contistdl C hian o.Asi.i$h;sotAliarumAMON hinuMENTATI0lf fg g,om spdgj [ el#1MWt V4tVE Refe <4-cel 3
- e I-2v e. siti s (4PEAA8t+ GRDllPS p, ,
o nPPLICABLE CHANNELS ISOLAT -
. $7 4//swsl.ft Vs/M' GPEAAT4NG- PER TR) BY
#D'"J :
TRif FUNCTION !.a LE"It SEU!E MODEH) SYSTEff* SIGNAL hACTION d f} acondaWtainment- c . efrel Floor Exhaust Duct - s or [ 1 , 2 , 31 and
- 1 3'*8 6 l ~~ *
- ; High Radiation ,g I
g heactorBuildingExhaustShaft
- High Radiation '
11 m hry 1,2,3 and
- g 1
l [ Mil h D 0ffgas Vent Stack - High f-CNote_A) <hoteei_ 1 3
#2 I l' d Radiation @Q u kl.; y4 ggg h hR;;n ,5vnus Shutdown Coolino*dissfy IfelgMoh ((3f p (heactor -V _ Pressure - liigh I'35ps 1,2,3 1 4 b-h Stas d. e, ow 'to 4 !.
gattor. Water Cleanuo Owcohde f 18'l2No a g g7 y: <j )* RWCll- Differential Flow - liigh [5 0 1,2,3 1 hh ((. bWGU- Area Temperature - High 13 *F 1.2.3 I}d 5 h f* O
-{ f I h RMC1 Area Ventilation A 4* 1,2,3 1 5 8
Q P (#3
~
Offferential Temperature - High q.gg] l t-andby-tiqu4d C etrel Sy5 tem Initiation NA j Systeey 5 h i Jse I 111. *F 1,2,3 FAddT*f'f I @ h h itWEU-Area Near TIP Roon Ambient Temperature - High ]j I Reactor Water Level - Low-Low 11 g5 In es 1,2,3 2 5 gi evo
Doc 3.s. I g HEC CA 9n5 7 3.b '3 6 . 2.. ( bI C.,I6 E/4.5 3 Ar. - 1
. o . -. . g _ - g - . . ; --- - - -- - an l e -" __.iH ;;_ :--- ;
( -.
- 5. With the LFCI suosystem mane or b2 founo to os i_nocertole for any
_ reason.%. . ::: r r '.;r; :: 27 gg A so f O.ntersw; bank- -. . .--*Et55
;- a E"7*I*I ^}h @ Ac b c),
---- .-- n. ] restore tna 1.PCI (kddACk6A suesystem to OPERABLI. status 1 %
(within 7 days. /
- 6. [0therwiss, he in at least HUT ~p hcNon f EWTDOlal within the next 12 hours' amt in CDLD SWTDD101 within the I
(following 24 hours. - JYl # eg 9 g C8g8g08 -TT$ 3.5, l
- n. mes4,wm isenv W CTS 3//.5.f
.b.4.2 g)W. <mann C75 3Al.f. B) T rs 3.6 4.;
ogpM5if (The suopression sosit =d M' spray moest of the restoual heat removal (RNR) system <* mil be - L.CO r 3. f 4. q - h4} I OPD ABLE with loses-eeek./wnun me tun W N(( rJ , O water' reactor h is ar==t** than 212*Fj { its 3.5.5p pf I,'C*b8 3. k. N . 1Hth one suppression sool spray. A3 2. ccrs3/4 .. s 'l.i.is.rs.is o iha-nrnF io.g3 to as uttE eag tc n
'I tus within ars;or ce 'In at -
(least HOT S&wWN within the QQ next 12 hours ana in COLD SWTDQWN within tne following 24 y ch c],, -- M r3.)
- 3. [W,ithbothsuosressionv.:.o1 3 ,,,.. - m .. -m spray ,
) ACbk 6]
)
((3p,s _ g Vieops finocertois, restore at' least one loon ofh-- _ , :g: " 4sncoression pool b : crfn:Wg e - 3/t./, E. LE :talg1_within a hours /ori f De in HUT SW TDOWN within the l next 12 hoars and in COLD CVN within tan following 24 ---i' Achev3 { css M.s. s/
- The LPCI suasystem may be considered b 6' OPERABLE during alignment to, and l operation in. RHR Shutonwn Cooling made
{ if casable of being manually re-aligned Lok l k $2. 3.5.
\(remote or local) to the LPCI moon, j AMENDMENT NO. 108.777. I::0 3.5-4 o- t's O O
Doc 3.6. 2.y' 6 9ecDc.Udems 3.1. l/3.4.2.4/ Ai cr.ss/4.s.s c s-1 p...... ; 3 ;-- -----e - m ~. ~ u l g: w_ _
. .. : :.__ y -- - -
~
r --
- 5. With the LPCI sunsystem mass or foons to se inocer e for any g2
_r . f , . -_ . _ _ - {- _ .- . . -- . _ , 3 cb g]
=='Nt'd " 7I' -- Ih Am N b '"
tats)-- --.. - -- _ __c 1-_. fressors t e LPCI subsystem to 0FDABLE status 2 dd ACMMDj within 7 days. / g
- 6. [0therwise, be in at least HOT t.b'O n f IIRITDOWN within the next 12 hours sus in COLD SIRITMnBI within the I
(following 24 hours. - -.)IlEpart d C8Msbon ggg3,g,j
- n. , - -cm ,e--
CTS 3h.6.8 6.t,.4.2. RWR. pps5 ion i
^ --- " ~
pil.rs 3/4 5'. S] -Ers 3.6 4.2 fThe suppression seeKh M sprey assag of the restaual heat r (S _1 <w srs-- IWHARLE with tus(i n he
$wn z.
49 i loses .eesh. 4s -
.. .sr water'
.w..
rM g.,37aseya...g=2r f b y .l g 3.6.9. g_ 2. A3 With one suppressina cool st. ray} c , , s, 'gE .e was;.a .
%( *pJ .
asperstle 1 to gg RABLE L%0 tus within 3 _aygjor os 1n a p
/least HOT SHInwd within the i
next 12 hours aan in COLD SmlTDOWN within tne following 24 Jteers. J y ch Q
- 3. [W.ithbothsussressionpoolspray ---[Achu B )
(76.j4.5 ( 1,,s..--_ = _ m - Vaamos ttansera.ais, rss' tore d 1 east one loss off r ... _, :f;.
,}M
's 4susoression pool L--;-fr1g o 3/Q.f.h answay_r status witn<n a hoursforn i be in NT S1EITDOWN within tne next 12 hours and in COLD SIGITDOWN within the following 24 I L
ichoy C ] L - Cfr5 34,g, g// t heers. / -rrs 3.6.y.2.
- The LPCI sunsystem may be considered 3*6*I OPBABLE during alignment to, and ,
operation in. RHR Shutsown Cosit i if casable of being manually re-a ignea mode k l g gg, g, g ,)
\(remote or local) to the LPCI mose. j i-ar no. m.m. wo 2.sa P
9 33 eh '~r 1
Doc. s c,.2.N , Spe.c; h k u s s.s.2 4}crs sh.6.5 CAEC-1 {LIMITINGCONDITIONSFORc:E:aTION lSURVEILLANCEREOUIREuENTS ! 3D
~3.b.N 1 b ppre,55iort b j y- , ..... i. Se ra v C:;1 ' ~
h
~ - @ u g m io,i f @
F Surveillance of the cr .td- : .; #
~
spray loops shall be performed as follows: ki
) l.
- During each five year period, an air test shall be performed on the P =
{CT5 3/9 5. Pa M(Un :neaaersan/:' nozzles. suppression pool spray
/
se 2.u. s. z . 9 AMENOMENT 110. 109,}77, 200 3.5-4
- t. N b O Y
DISCUSSION OF CHANGES ITS 1.0: USE AND APPLICATION ADMINISTRATIVE CHANGES Ai All reformatting and renumbering is in accordance with the NUREG. As a result, the ITS sbauld be more readable and more understandable by its users. The reformatting, renumbering, and rewording process involves no technical changes to the CTS. Editorial rewording (either adding or deleting) is made consistent with the NUREG. During NUREG development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the CTS. Additional information has also been added to more fully describe each subsection. This wording is consistent wh the NUREG. Since the design is already approved by the NRC, adding more detail does not result in a technical change. A, A note was added to ITS Section 1.1, Definitions, in order to clarify that the defined terms will appear capitalized and are applicable throughout the ITS and Bases. This addition is administrative in that it clarifies the ITS and Bases. It clarifies the use of the definitions throughout the ITS without changing the intent of any TS. This change maintains the consisteney benveen the ITS and the , NUREG. A3 The CTS definitions of Safety Limit, Limiting Safety System Setting (LSSS), and Limiting Conditims For Operation (LCO) are deleted because they already exist
- in 10 CFR 50.3' and do not need to be repeated in the ITS. The deletion of these definitions also maintains the consistency between the ITS and the NUREG. The removal of these c'efinitions is considered administrative with no impact ofits own.
A4 The definition of Operable-Operability was changed editorially to be consistent with the NUREG. No technical changes (either actual or interpretational) to the CTS have been made. A specific change to the definition of Operable-Operability is changing the "and" to an "or" in " normal and emergency electrical power sources." This is an administrative change because currently the definition along with the second DAEC 1 RevisionI l
DISCUSSION OF CIIANGES ITS 1.0: USE AND APPLICATION ADMINISTRATIVE CHANGES (continued) A4 paragraph of CTS Definition 3 for LCO, requires only one source to be Operable (cont.) as long as the redundant systems, subsystems, trains, components, and devices are Operable. The second paragraph of CTS Definition 3 for LCO requirements are incorporated into ITS 3.8.1 Actions, for when a diesel or offsite power source is inoperable. Thus, the new requirements are effectively the same as the current requirements. In ITS 3.8.1, new times have been provided to perform the determination of redundant feature Operability. These changes are discussed in the Discussion of Changes for ITS 3.8.1. A3 The definition of Operating is deleted because this state cf a system does not need to be explicitly defined when considering whether or not the design '. unction can be met. Whether a system is operating or shutdown does not provih relief concerning Operability requirements. The definition of Operable or Operability is sufficient in this case. Operability is assumed until the system, subsystem, etc. is found to be inoperable by failure anytime or during the performance of the SR at the specified frequencies. The deletion of this definition also maintains the consistency between the ITS and the NUREG. The removal of a definition is considered administrative with no impact ofits own. A6 The definition ofimmediate is being moved. It is renar.ied immediate Completion Time in the ITS. The term now appears and is defined in ITS Section 1.3, Completion Tinies. This change maintains the consistency between the ITS and the NUREG. This is an administrative change because the term is being moved from one section of Technical Specifications to another. DAEC 2 RevisionI l
DISCUSSION OF CHANGES ITS 1.0: USE AND APPLICATION ADMINISTRATIVE CHANGES (continued) A, The CTS definition for Shutdown Margin (SDM) assumes the calculation is made with the core in its most reactive state during the operating cycle. The ITS definition for SDM replaced this current wordmg with equivalent conditions of the reactor is Xenon free and the moderator temperature is 68* F (20a C). The CTS definition already contains the ITS provision for all rods inserted with the single highest worth rod withdrawn. However, the CTS requires the analytically determined strongest rod to be used; whereas, the NUREG allows either the analytically determined rod or determine the strongest rod by test. The definition has been modified to be consistent with the actual LCO for SDM. Discussion of the technical aspects of this change will be add essed in ITS Section 3.1.1, Shutdown Margin. The assumptions that the DM be calculated assuming Xenon free and moderator temperature is 68 a F (20* C) are in accordance with standard GESTAR methodologies. Since the CTS and ITS definitions are equivalent, this change is administrative. As The definitions of Primary Containment Integrity and Secondary Containment Integrity are deleted because of the confusion associated with these definitions compared to the use in their respective LCOs. All the requirements are specifically addressed in the respective LCOs along with other LCOs in the Containment Systems Section. Discussion of the technical aspects of the deletion or revision of the applicable CTS requirement will be addressed in ITS Section 3.6, Containment Systems. The Bases for these LCOs also contain a description of what constitutes Primary and Secondary Containment Integrity. The deletion of these definitions maintains the consistency between the ITS and the NUREG. The removal of these definitions is considered administrative with no impact of their own. Ao The definitions of Operating Cycle, Refueling Or,tage, Reactor Vessel Pressure, Linear Heat Generation Rate, Fraction of Rated Power (FRP). Total Peaking Factor (TPF), Maximum Total Peaking Factor (MTPF), Protection Action, Protective Function, Simulated Automatic Actuation, Primary Source Signal, Source Check, Engineered Sa'hguard, Purge-Purging, Venting, Process Control Program (PCP), and Members of The Public are deleted because they are no longer used in the Technical Specifications. The specific TS referring to these definitions no longer contain their use. Discussion of the technical aspects of the deletion or revision of the applicable requirement will be addressed in the affected DAEC 3 RevisionI l
D'SCUSSION OF CHANGES ITS 1.0: USE AND APPLICATION ADMINISTRATIVE CllANGES (continued) A, section if applicable. The term may also be dermed and/or explained in the Bases. ' (cont.) The removal of these definitions is considered administ ative with no impact ofits own. The deletion of these definitions maintains the consistency between the ITS and the NUREG. Am The dermitions of Critical Power Ratio and Transition Boiling were incorporated into the definition of Minimum Critical Power Ratio (MCPR) to enhance the clarity by using a technically precise term (transition boiling) versus a less precise term (boiling transition). Ap The CTS dermitions ofinstnment Calibration or Channel Calibration and Logic System Functional Test (LSFT) were changed. The Instrument Calitration or Channel Calibration defmition was revised to include testing of the sensor. The defmition of LSFT was revised to remove the requirement to include the sensor and end device. The end device will be tested during the system operational test requirements of the affected ITS (e.g., ITS SR 3.5.1,7, which tests to ensure an ECCS pump starts automatically on an initiation signal). Since any of the tests can be credited for performance in parts, as long as the whole channel is tested, it does not matter when the sensor and end device are tested (i.e., with the Channel Functional Test, Channel Calibration, the LSFT, or the system operational test). Similarly, the definition of Channel Functional'1 est was revised to allow testing to be performed in segments to be consistent with the Channel Calibration definition. Thus, the accumulation of these changes results in an administrative change. The CTS definition for Channel Functional Test requires the test to verify the proper response, alarm, anWor initiating action. The ITS definition requires verifying Operability including required alarm, interlock, display, and trip functions, and channel failure trips. The ITS also adds the word " required" in the Logic System Functional Test definition. As a requirement for Operability of a Technical Specification channel, noi all channels will have a required sensor or alarm function. Conversely, some channels may have a required display f'metion. This is the intent of the existing wording, and therefore, the revised wording is
, proposed to more accurately reflect this intent, consistcnt v a the NUREG.
[CRF 9916] DAEC 4 RevisionI l
i DISCUSSION OF CliANGES ITS 1.0: USE AND APPLICATION ADMINISTR.ATIVE CilANGES (continued) An The CTS definition for RPS hesponse Time was modified to state that the test can (cont.) be performed in segments, provided the total response time is measured. This is the intent of the existing wording, and therefore, the revised wording is proposed to more accurately reflect this intent, consistent with the NUREO. An The definitions for Channel. Trip System and Logic xere deleted because they are commonly undersnod and not prone to unique and inappropriate interpretation. The removal of these definitions is considered administrative with no impact ofits own. The deletion of these definitions maintains the consistency between the ITS and the NUREO. Unique or hard to interpret channel or Trip System arrangements will be describc) n the Bases. An The definition of Functional Te.=t is deleted because it is not used in eithen the LCOs or Surveillance Requirements. The definition of Functional Test is the manual operation or initiation of a system, subsystem, or component to verify that it functions within design tolerances (e.g., the manual start of a core spray pump to verify that it runs and that it pumps the required volume of water). These types of tests in the ITS are called out directly in the Surveillance Requirements (e.g., Verify the following ECCS pumps develop the specified flow rate...). Post maintenance functional testing is covered by plant procedures and is no longer in the TS. The deletion of this definition maintains the consistency between the ITS and the NUREO. The removal of this definition is considered administrative with no impact ofits own. Ag The requirements specified by the dermition of Frequc:.cy Notation for TS Surveillance Requirements and the definition of Annual are being deleted because I the SR Frequencies in the ITS do not use this type of notation. The Frequencies for the SR lists the specific number of hours, days, or months (e.g., instead of"M" for Monthly, the ITS will list 31 days). An The delimition of Shutdown Margin has been modified to address stuck control rods when the core is in its most reactive state during an operating cycle. This is consistent with the existing requirement found in CTS 3.3.A.2.f.(ii) which infers i DAEC 5 RevisionI l
DISCUSSION OF CllANGES ITS 1.0: USE AND APPLICATION ADMINISTRATIVE CllANGES (continued) An accounting for the worth of a stuck control rod when the core is in its most (cont.) reactive state during an operating cycle. A i6 The Offsite Dose Assessment Manual (ODAM) definition is moved to Section 5.0 of the ITS, consistent with the NUREG. An The definition of Reportable Event was deleted because it is not used in either the LCOs or SRs of the ITS. The use of Reportabl: Event is covered in 10 CFR 50.73 and does not need to be defined in the ITS. The deletion of this definition maintains the consistency between the ITS and the NUREG. The removal of a definition is considered administrative with no impact ofits own. An New definitions for Actions, Average Planar Linear IIcat Generation Rate (APLilGR), Turbine Bypass System Response Time, L., Physics Tests. Staggered Test Basis, and Thermal Power are being added to the ITS. These definitions were added for consistency with the NUREG. These definitions are used throughout the ITS and in the CTS. The defined terms arv used in the LCOs, SRs, and Bases of the ITS and were defined for the convenience of the users of the TS. The inclusion of these definitions are deemed administrative and have no impac. on their own. If the added defimitions are used in new requirements (which is a technical change) the discussion of changes for the individual sections of the TS will provide thejustification. An The following sections are being added to the TS. These additions aid the understanding and use of the new standard ITS format and style of presentation. Some conventions in applying the t- 'ique situations have previously been the subject of debate and interpretation by the licensee and the NRC Staff. Because the guidance in these proposed sections is presented in the NUREO as approved by the NRC Staff, and the guidance is not a specific deviation from anything in the CTS, these additions are considered to be administrative. The added sections are as follows: DAEC 6 RevisionI l c
DISCUSSION OF CilANGES ITS 1.0: USE AND APPLICATION ADMINISTRATIVE CilANGES (continued) A,i SECTION 1.2 LOGICAL CONNECTORS (cont.) ITS Section 1.2 provides specific examples of the logical connectors "AND" and "QR" and the numbering sequence associated with their use. This revision is being proposed consistent whb the NUREO. 1 SECTION 1.3 - COMPLETION TIMES ITS Section 1.3 provides proper use and interpretation of Completion Times. The proposed section also provides specific examples that aid the user in understanding Completion Times. The proposed Completion Times Section is consistent with the NUREG. SECTION 1.4 FREQUENCY ITS Section 1.4 provides proper use and interpretation of the Surveillance Frequency. The proposed section also provides specific examples that aid the user in understanding Surveillance Frequency. The proposed Frequency Section is consistent with the NUREG. Ao2 The intent of applying the Mode definition only when fuel is in the vessel is incorporated into the definition of Mode. Since the sessel head can only be removed if the head closure bolts are less than fully tensioned, there is no purpose in including "or with the head removed." These changes are considered editorial. A 21 Footnotes (c), (d),(c), and (f) on CTS Table 1.0-1 are addressed by the exceptions allowed to LCO requirements in the proposed Special Operations section, ITS 3.10. Any technical changes to these requirements will be addressed in the discussions of changes for individual Specifications. A 22 A clarification has been added to the definition of Channel Calibration which states that the calibration ofinstrument channels with Resistance Temperature Detectors (RTDs) or thermocouple sensors may consist of an in place qualitative assessment of the sensing elements. Certain types of sensing elements, by their decign, construction, and application have an inherent resistance to drift. They are designed such that they have a fixed input / output response which cannot be l DAEC 7 RevisionI l
DISCUSSION OF CilANGES ITS 1.0; USE AND APPLICATION ADMINISTRATIVE CilANGES (continued) An adjusted or changed once installed. When a credible mechanism that can cause (cont.) change or drift in this fixed response does not exist, it is unnecessary to test them in the same manner as the other remaining devices in the channel to demonstrate proper operation. RTDs and thermocouples are sensing elements that fall into such a category. Thus, for these sensors, the appropriate calibration at the Frequencies specified in the ITS would consist of a verification of OPERABILITY of the sensing element and a calibration of the remaining devices in the channel, Calibration of the other devices in the channel is performed by applying the sensing elements' (RTDs or thermocouples; fixed input / output relationships to the remainder of the channel and making the necessary adjustments to ensure range and acetiracy. This ensures that the sensing elements are consistent with one another and will identify poteniially bad sensing elements. This ITS " verification of OPERADILITY" of the sensing element (RTDs or thermocouples) is considered to be explicitly defining the currently accepted method for calibration of these instruments. As such, this change is considered to be administrative. 5 Au Minor editorial changes were made to CTS 4.1.A.2 to match the CTS definition for RPS Response Time (Definition #19) and to delete the statement that response time testing is not done as par' of the Char.nel Calibration. This is consistent with the intent of both the CTS and ITS that specify separate SRs for response time tests and calibrations. A3 CTS Table 4.2-G Footnote "*" contains the definition of the EOC RPT System Response Tirne for Turbine Control Valves. The CTS definition starts from energization of the fast acting solenoid, which is changed in the ITS to when the TCV hydraulic oil control oil pressure drops below the pressure switch setpoint. The ITS and CTS response time test requirements are equivalent and is discussed more completely in ITS Section 3.3.1.1, RPS Instrumentation, thus this change is considered administrative in nature. A3 The CTS contains a dt.finition for Instrument or Channel Check. The proposed change will delete the " Instrument part" of this definition. For this test the
" Instrument" and the " Channel" are the same. Therefore, this change is considered administrative in nature.
DAEC 8 Revision 1 l _J
DISCUSSION OF CilANGES ITS 1.0: USE AND APPLICATION I } ADMINISTRATIVE CllANGES (continued) l A3 ITS Modes Table 1.1 1 encompasses the following definitions in the CTS: Cold Condition, Cold Shutdown, llot Shutdown. Ilot Standby Condition, Reactor Power Operation, Mode of Operation (Refuel Mode, Run Mode, Shutdown Mode, and Startup/Ilot Standby Mode), Shutdown. The Modes Table defines five specific Modes, by number, title, mode switch position. and average reactor coolant temperature (where applicable for the Mode). By incorporating these definitions into the ITS Modes Table, the Modes are more definitive, and this decreases the likelihood of the interpretation of being in more than one Mode at any time. This change encompasses both Administrative and Less Restrictive changes. (See Li for the less restrictive changes to the definitions of Cold Shutdown and llot Standby) Below is a highlight of the Administrative changes from each of the existing definitions which were incorporated into the Table. Cold Condition The existing definition is incorporated into Mode 4. The Cold Condition definition requires Reactor Coolant System (RCS) temperature to be s 212*F. Ilot Shutdown This existing definition is incorporated into Mode 3. Reactor Power Ooeration The existing definition is incorporated into Mode 1 and Mode 2 (when reactor power is > 1% RTP). Individuai specifications that contain requirements for Operability during Reactor Power Operation are being changed to the appropriate Mode I and/or Mode 2 requirements in the ITS. The changes to these CTS Operability requirements have separate justifications provided in the affected specifications. Derefore, this is an administrative change. Single Loop Operation is specified in ITS 3.4.1," Recirculating Loops Operating," and need not be a definition. DAEC 9 Revision 1 l
DISCUSS!ON OF CilANGES ITS 1.0: USE AND APPLICATION ADhilNISTRATIVE CilANGES (continued) , Au Refuel hiode (cont.) This existing definition is incorporated into hiode 5 and into hiode 2 as a mode switch position. With the mode switch in Refuel, only one control rod continues to be allowed to be "not full in" at any one time. The specifics ofinterlocks for the reactor mode switch position in Refuel are an integral part of the mode switch design and continue to be specified in ITS 3.9.1 r.nd 3.9.2. The SRhi count rate need not be specified in the Definitions, since it is specified in ITS 3.3.1.2,"SRhi instrumentation." Run hiode This existing definition is incorporated into hiode 1. The specifics of the interlocks for the mode switch position in Run are an integral part of the mode switch design and do not need to be specified in the Technical Specifications. These specifics are located in the plant design documents. Changes to the interlocks and the mode switch design (and therefore the design documents) will be evaluated in accordance with the DAEC 10 CFR 50.59 Program. The
. Operability require.nents of the APRhis do not need to be specified in the definition since they are adequately addressed in ITS 3.3.1.1, " Reactor Protection System Instrumentation."
Shutdown Niode The existing definition is incorporated into the mode switch position for hiodes 3. 4, and 5. The specifics of the interlocks for the mode switch position in Shutdown are an integral part of the mode switch and do not need to be specified in the Technical Specifications. These specifics are located in the plant design documents. Changes to the interlocks and mode swi.tch design (and therefore the design documents) will be evaluated in accordance with the DAEC 10 CFR 50.59 program. DAEC 10 Revision 1 l
l DISCUSSION OF CllANGES ITS 1.0: USE AND APPLICATION ADMINISTRATIVE CilANGES (continued) A3 Startun/Ilot Standby Mode (cont.) The existing definition is incorporated into the mode switch position for Mode 2. The specifics of the interlocks for the mode switch position in Startup/liot Standby are an integral part of the mode switch and do not need to be specified in the Technical Specifications. These specifics are located in the plant design documents. Changes to the interlocks and the mode switch design (and therefore the design documents) will be evaluated in accordance with the DAEC 10 CFR 50.59 Program. Shutdown This existing definition is incorporated into Mode 3 and Mode 1. The incorporation of this definition is purely administrative since the current definition of Shutdown is mode switch in Shutdown and no Core Alterations being performed. The requirement that no Core Alterations are to be performed is indirectly required by CTS Table 1.0-1 Note (a) requirements in both modes specifying all reactor vessel head closure bolts being fully tensioned. Per the existing and proposed Alten.*..on of The Reactor Core (Core Alteration) definition, with the reactor vessel head on, Core Alterations are not possible. (l.0 2} (l.0-3} e TECilNICAI. Cl? ANGES - MORE RESTRICTIVE Mi The CTS contains definitions for Instrument Calibration or Channel Calibration and Instrument or Channel Functional Test. The proposed change will delete the
" Instrument part" of each of these CTS definitions and will adopt the NUREG terminology for these definitions. This change is more restrictive since the CTS definitions dc not necessarily include the entire channel when referring to the Instrutaent Calibration or Instrument Functional Test.
The proposed change states that the Channel Calibration shall encompass the entire channel, including the required sensor, alarm, display and trip functions. The addition of these requirements to the ITS is more restrictive than the CTS: however, DAEC current operating practice implements these requirements outside the CTS. [CRF 9916] l DAEC 11 RevisionI l
DISCUSSION OF CliANGES ITS 1.0: USE AND APPLICATION TECHNICAL CilANGES - MORE RESTRICTIVE (continued) l l M2 ITS Section 1.3 describes Completion Times in order to help the Technical Specification user correctly apply them in the ITS. One specific requirement ITS Section 1.3 describes, is the use of Completion Times for the case in which two subsystems become inoperable concurrently, without a note which allows the Conditions to be entered separately, in this case, if one subsystem were restored (within the Completion Time for two subsystems inoperable), the shorter of 24 hours or the remainder of the subsystems Completion Time (for one subsystem ineperable) is allowed to restore the other subsystem to Operable status. Although the current operating practice i similar, the CTS would allow a less conservative interpretation and it is possible that DAEC would take the remainder of the Completion time of the subsystem which is inoperable even ifit is greater than 24 hours. Thus, the addition of this requirement ofITS Section 1.3 is more restrictive. M3 Implicit in the new dermition of Operability, as spelled out in the Bases for LCO 3.0.2, is the concept that equipment removed from service for TS - required surveillances is considered to be inoperable for the purposes of satisfying the LCO and that the appropriate Conditions will be entered and Required Actions taken, unless specifically exempted. This is different from the current licensing basis, as explained in previous correspondence with the Staff (NG-94-4017, NG-95-0815, NG 96-2322 and NG-97-0847), llased upon our Response to the Staff's RAI on the ITS (NG-97-1597) and our meeting of September 9,1997, we have agreed to accept the NUREG definition and philosophy and withdraw the ITS Notes and llases clarifications added to the NUREG, except in those cases where a " hardship" would otherwise exist (e.g., LCO 3.0.3 entry / shutdown action, dismption of steady state plant operation). [See the individual specifications for the justifications for these specific allowances (Notes).] Also, based upon the September 9,1997 meeting, we understand that there are no reguiatory requirements governing the administrative controls med to document and track LCO entry and compliance (Ref. NG 97-1723). Therefore, we can implement this new requirement in such a way as to minimize the burden on the plant operating staff. DAEC 12 RevisionI l
DISCUSSION OF CilANGES ITS 1.0: USE AND APPLICATION TECilNICAL CilANGES - MORE RESTRICTIVE (continued) M3 While the adoption of this new interpretation of Operability is more restrictive (cont) than the CTS, it is considered acceptable as no new equipment manipulations are involved, the " hardships" will be individually exempted, the administrative burden on the plant operating staffis minimized and its adoption is consistent with the NUREG (standardization in the industry). (9223} TECllNICAL Cil ANGES - RELOCATIONS Ri The CTS definition of Operable-Operability contains a descr:ption of what a verification of Operability means (i.e., an administrative check, by examination of appropriate plant records, etc.) This change proposes to move this part of the definition of Operable Operability to the individual ITS Actions and relocate the details to their respective Bases for individual Technical Specifications. This change is acceptable since the definition of Operable-Operability is sufficient vithout describing the meaning of" verification of Operability." Any changes to the requirement (consistent with the TS Bases Control Program) will require 110 CFR 50.59 review. This change is consistent with the NUREG. TECilNICAL CllANGES - 1 ESS RESTRICTIVE Li ITS Modes Table 1.1-1 encompasses the following definitions in the CTS: Cold Condition, Cold Shutdown, llot Shutdown,110t Standby Condition, Reactor Power Operation, Mode of Operation (Refuel Mode, Rur. Mode, Shutdown Mode, and Startup/liot Standby Mode), Shutdown. The Modes Table defines five specific Modes, by number, title, mode switch position, and average reactor coolant temperature (where applicable for the Mode). By incorporating these definitions into the ITS Modes Table, the Modes are more definitive, and this decreases the likelihood of the interpretation of being in more than one Mode at any time. This change encompasses both Administrative and Less Restrictive changes,(See A2 s for the Administrative changes). The changes to the definitions of Cold Shutdown and 110t Standby are classified as Less Restrictive and are discussed below. (l.0 2) {l.0 3) DAEC 13 Revision 1 l
DISCllSSION OF CilANGES ITS 1.0: USE AND APPLICATION TECllNICAL CilANGES - 1.hSS RESTRICTIVE Li Cold Shutdown l The existing definition is incorporated into Mode 4. The current Cold Shutdown definition requires the mode switch to be in Shutdown, RCS temperature to be s 212*F, and the reactor vessel to be vented. The ITS definition of MODE 4 does not require the reactor vessel to be vented. Therefore, this is a less restrictive change. The proposed Technical Specifications (ITS 3.4.8, Residual Heat Removal Shutdown (RllR) Cooling System-Cold Shutdown) provide more prescriptive requirements to assure adequate decay heat removal capabilities in Mode 4. Also, with regard to pressurization c.sems (related to deletion of reactor vessel venting requirements), ITS 3.4.9, RCS Pressure and Temperature (Pff) Limits, provides requirements to preclude the reactor vessel from exceeding pressure limits. Therefore, the need to have the reactor vessei vented is not required. liot Standby Condition This existing definition is incorporated into Mode 2. The requirement to maintain
. pressure below 1055 psig is not required and has been deleted because 1055 psig is the RPS liigh Pressure nominal trip setpoint and the reactor would trip if pressure were greater than this value. As a result, the existing Ilot Standby Condition could not be maintained at a pressure greater than 1055 psig. Similarly, the specification for reactor coolant temperature to be > 212' F has also been deleted from the definition of Mode 2, consistent with the CTS Table 1.0-1 for startup (Mode 2)/Ilot Standby. The proposed ITS Table definition for Mode 2 does not specify a temperature because the temperature will be controlled by the RCS Pfr Limits curve (ITS 3.4.9).
DAEC 14 Revision I l
DISCUSSION OF CilANGES ITS 1.0: USE AND APPLICATION TECIINICAL CilANGES -i ESS RESTRICTIVE (continued) L The CTS definition A!teration Of The Reactor Core (Core Alteration),is being revised so that the term will apply only to those activities that create the potential for a reactivity excursion and, therefore, warrant special precautions or controls in the Technical Specifications. Currently, an Alteration Of The Reactor Core (Core Alteration) is defined as "The addition, removal, relocation or movement of fuel, sources, incore instruments or reactivity controls within the reactor pressure vessel with the vessel head removed and fuel in the vessel." However, routine replacement ofincore detectors (e.g. LPRMs, Traversing incore Probes, etc.) that are not otherwise required to be Operable does not constitute Core Alterations. The proposed definition for Core Alterations is intended to identify those activities that affect reactivity within the reactor vessel with the vessel head removed and fuel in the vessel. As a result, the term Core Alterations will identify those activities that create the potential for a reactivity excursion and warrant special controls and precautions. Under the revised definition, in vessel movement ofinstruments, cameras, lights, tools, etc. will not be classified as Core Alterations since special controls needed to prevent reactivity excursions are not warranted. It should be noted that control rod movement is not considered a Core Alteration provided there are no fuel assemblies in the associated core cell. The removal of the four fuel bundles surrounding a control rod very significantly reduces the reactivity worth of the associated control rod to the point where removal of that rod no longer has the potential to cause a reactivity excursion. Therefore, removal from the core of a control rod is not considered a Cere Alteration provided there are no fuel assemblies in the associated core cell. This l fact is recognized in the design of the control rod velocity limiter which precludes removal of a rod prior to the removal of the four adjacent bundles. l DAEC 15 RevisionI l
DISCUSSION OF CllANGES ITS 1.0: USE AND APPLICATION TECIINICAL C11ANGES - 1 ESS RESTRICTIVE (continued) L3 The CTS dermition for Channel Functional Test requires the injection of a simulated signal into the channel in order to perform the test. The ITS defmition for Channel Functional Test allows either a simulated or actual signal to be used. Some Channel Functional Tests may be performed by insertion of the actual signal into the logic. For others, there is no reason why an actual signal wouid preclude satisfactory performance of the test. Use of an actual signal instead of the existing requirement to use a simulated signal will not affect the performance of the channel. Operability is adequately demonstrated in either case since the channel itself cannot discriminate between " actual" or " simulated" signals. DAEC 16 RevisionI l
l l i DISCUSSION OF CllANGES TO NUREG-1433 l C11 APTER 1.0 -- USE AND APPLICATION l Pl. ANT SPECIFIC Cif ANGES ' Pi Per discussions with the NRC on February 11,1998, this change has been l withdrawn. [CRF 9916] P2 The current Dose Equivalent 1-131 delimition allowance of microcuries/mi is retained to provide clarification in the concentration ofI-131 allcwed in the NUREG. P3 ilesponse Time testing is not required in the CTS for ECCS and the Isolation System. The DAEC participated in an EPRI study, EPRI NP-7243," Investigation of Response Time Testing Requirements," May 1991, to determine if response time testing is necessary tojustify the assumptions in plant safety analyses. The results of this EPRI study indicate that RTT is generally redundant to other periodic testing (e.g., Channel Calibrations) and that RTT does not appear to identify response time degradation or failures. Since the addition of these tests are a major burden to DAEC, with little gain in safety, the SRs associated with these tests have not been added for any test associated with instrumentation. Therefore, the definitions have also not been added. P4 The CTS does not contain a definition for Pressure Boundary Leakage. Because this parameter is not directly measurable at power, a separate definition could create interpretation problems relative to whether Pressure Boundary Leakage is governed by me Identified or Unidentified Leakage limits. For the DAEC, Pressure Boundary Leakage is considered to be unidentified Leakage (Ref. UFSAR 5.2.5.2.2). This position has been found to be acceptable by the NRC, per Amendment # 203 to the DAEC TS. Therefore, the dermition was not added. P3 [Not used.] P6 Grammatical error corrected. P7 The analysis for SDM uses (20 C)instead of 68 F. Since these temperatures are equivalent, both are included for clarity. DAEC 1 Revision I 1
DISCUSSION OF CllANGES TO NUREG-1433 CllAPTER 1.0 -- USE AND APPLICATION PLANT SPECIFIC CllANGES (continued) P [Not used.] Py The CTS definition of transition boiling has been added to the MCPR definition for clarification. Pm The definition of SDM has been slightly modified to address stuck control rods when the core is in its most reactive state. This agrees with the CTS definition. Pn The definition of EOC-RPT response time has been modified to reflect the fact that the breaker are suppression time has been validated at initial breaker installation, but is not periodically reverified. See Discussion of Changes for Chapter 3.3 lbr further discussion. P i2 The PTLR concept will not be used at DAEC since an NRC approved methodology does not exist for DAEC. Po The DAEC plant specific title /name, terminology, or plant specific numbers were incorporated into this requirement. This change is based on the DAEC plant specific design and analysis. Pn Linear lleat Generation Rate (LilGR) and hiaximum Fraction of Limiting Power Density (hiFLPD) are not utilized in the ITS; therefore, these definitions are deleted. For more detailed discussion, refer to the Discussion of Changes to NUREG 1433. Chapter 3.2 " Power Distributions Limits." and the NSHC
" Technical Change Less Restrictive Li " for ITS 3.2.3.
Pn The CTS definition uses " heat generation rate per unit length of fuel rod" versus "LIIGR." P u, The bracketed material "[for each class of fuel)" in the h1CPR definition is being added to account for different h1CPR values for different fuel designs from the same vendor for fuel from different vendors { l.0-17). Pn The average reactor coolant temperature for hiodes 3 and 4 has been revised to reflect the DAEC CTS transition temperature of 212 F for Mode 3 and hiode 4. DAEC 2 Revision I l i
DISCUSSION OF C11ANGES TO NUREG-1433 C11 APTER 1.0-USE AND APPLICATION Pi ANT SPECIFIC CIIANGES (continued) Pa i The NUREG definition for L, has been deleted to be consistent with Option B to 10CFR 50. App. J, which relocates this detail to the Primary Containment Leakage Rate Testing Program (ITS 5.5.12). P, i The NUREG definition for Physics Tests has been deleted, as the corresponding Special Operations (NUREG 3.10.9) is not being incorporated into the DAEC ITS. 4 DAEC 3 Revision I
DISCUSSION OF CilANGES TO NUREG 1433 CIIAPTER 1.0 -- USE AND APPLICATION PLANT SPECIFIC CHANGES P: Per discussions with the NRC on February 11,1998, this change has been l withdrawn. [CRF 9916] P2 The current Dose Equivalent 1-131 definition allowance of microcuries/ml is retained to provide clarification in the concentration ofI-131 allowed in the NUREG. P3 Response Time testing is not required in the CTS for ECCS and the Isolation System. The DAEC participated in an EPRI study, EPRI NP-7243," Investigation of Response Time Testing Requirements," May 1991, to determine if response time testing is necessary tojustify the assumptions in plant safety analyses. The results of this EPRI study indicate that RTT is generally redundant to other periodic testing (e.g., Channel Calibrations) and that RTF does not appear to identify response time degradation or failures. Since the addition of these tests are a major burden to DAEC, with little gain in safety, the SRs associated with these i tests have not been added for any test associated with instrumentation. Therefore, i the definitions have also not been added. P4 The CTS does not contain a definition for Pressure Boundary Leakage. Because this parameter is not directly measurable at power, a separate definition could create interpretation problems relative to whether Pressure Boundary Leakage is govemed by the identified or Unidentified Leakage limits. For the DAEC, s Pressure Boundary Leakage is considered to be unidentified Leakage (Ref. UFSAR 5.2.5.2.2). This position has been found to be acceptable by the NRC, per Amendment # 203 to the DAEC TS. Therefore, the definition was not added. P3 [Not used.] P,, Grammatical error corrected. P, The analysis for SDM uses (20*C) instead of 68 F. Since these temperatures are equivalent, both are included for clarity. DAEC 1 Revision I
DISCUSSION OF CilANGES TO NUREG-1433 CliAPTER 1.0 -- USE AND APPLICATION PLANT SPECIFIC CilANGES (continued) P [Not used.] P, The CTS definition of transition boiling has been added to the MCPR definition for clarification. Pm The definition of SDM has been slightly modified to address stuck control rods when the core is in its most reactive state. This agrees with the CTS definition. Pn The definition of EOC RPT response time has been modified to reflect the fact that the breaker arc suppression time has been validated at initial breaker installation, but is not periodically reverified. See Discusion of Changes for Chapter 3.3 for fmther discussion. t 1 Pu The PTLR concept will not be used at DAEC since an NRC approved methodology does not exist for DAEC. Po The DAEC plant specific title /name, terminology, or plant specific numbers were incorporued into this requirement. This change is based on the DAEC plant specific design and analysis. Pn Linear 11 eat Generation Rate (LIIGR) and hiaximum Fraction of Limiting Power Density (MFLPD) are not utilized in the ITS: therefore, these definitions are deleted. For more detailed discussion, refer to the Discussion of Changes to NUREG 1433, Chapter 3.2 " Power Distributions Limits," and the NS11C
" Technical Change-Less Restrictive Li " for ITS 3.2.3.
Pn The CTS definition uses " heat generation rate per unit length of fuel rod" versus "LilGR." Pa The bracketed material "[for each class of fuel]" in the MCPR definition is being added to account for different MCPR values for different fuel designs from the same vendor for fuel from different vendors (1.0-17}. Pn The average reactor coolant temperature for Modes 3 and 4 has been revised to reflect the DAEC CTS transition temperature of 212*F for Mode 3 and Mode 4. DAEC 2 Revision I
DISCUSSION OF CilANGES TO NUREG 1433 CilAPTER 1.0 -- USE AND APPLICATION PLANT SPECIFIC CilANGES (continued) Pa i The NUREG definition for L, has been deleted to be consistent with Option B to 10CFR 50, App. J, which relocates this detail to the Primary Containment Leakage Rate Testing Program (ITS 5.5.12). P, i The NUREG definition for Physics Tests has been deleted, as the corresponding Special Operations (NUREG 3.10.9) is not being incorporated into the DAEC ITS. DAEC 3 Revision I
- DISCUSSION OF CliANGES ITS 3.3.6.1: PRIhiARY CONTAINhiENT ISOLATION INSTRUhiENTATION ADNilNISTRATIVE CilANGES Ai All reformatting and renumbering is in accordance with the NUREG. As a result,
*he ITS should be more readable and more understandable by its users. The reformatting, renumbering, and rewording process involves no technical changes to the CTS.
Editorial rewording (either adding or deleting) is made consistent with the NUREG. During NUREG development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the CTS. Additional infomiation has also been added to mere fully describe each subsection. This wording is consistent with the NUREG. Since the design is already approved by the NRC, adding more detail does not result in a technical change. A: This change will add a Note to ITS 3.3.6.1 Actions which allows separate Condition entry for each channel. This change provides more explicit instructions for proper application of the Actions for Technical Specification compliance. In conjunction with the ITS 1.3 " Completion Times," the Note (" Separate Condition entry ...") provides more explicit direction of the interpretation of the CTS. This change is considered administrative and is consistent with the NUREG. A3 CTS 3.2.A.I.a.1 * .d CTS 3.2A.I.b (Footnote *) for Isolation Actuation Instrumentation , aes not require placing inoperable channel (s) in trip, where this would cause a Primary Containment Isolation. CTS 3.2.A.I.a.2 applies actions to channels that would not cause an isolation if the inoperable channels were placed in trip. These requirements of the CTS have been incorporated into the Actions for ITS 3.3.6.1. If placing the inoperable channel (s)in trip would cause the isolation, the Required Action of Condition A is not completed within the required Completion Time and Condition C is entered as indicated in the Bases for Required Action A.I. Condition A is entered and Action completed where placing channel (s) 3 in trip would not cause an isolation. Since the same response is required in the CTS and the ITS, this change is one of presentation preference only and is considered administrative. DAEC 1 RevisionI l
DISCUSSION OF CHANGES ITS 3.3.6.1: PRlh1ARY CONTAINhiENT ISOLATION INSTRUhiENTATION ADhilNISTRATIVE CllANGES (continued) A4 The requirement in CTS Action 23 and Action 25 to " declare the afTected system l inoperable" is not necessary since closure of the system valve (s) makes the system inoperable and the applicable Actions in the ITS for the supported system would be entered without this CTS direction. These changes are consistent with the NUREO and are considered administrative in nature. (3.3.6.1-16} l A3 CTS Table 3.2-A contains Footnote (i) and CTS Table 4.2-A contains Footnote (b) for the Applicability of the Trip Function. RWCU Standby Liquid Control (SLC) System Initiatiori. Footnotes (i) and (b) state that this isolation function is required when the Standby Liquid Control System is required to be Operable per Specification 3.4.A. ITS 3.3.6.1 requires this trip function to be Operable in hiodes I and 2 instead of referencing the SLC Specification. This change removes a cross reference to another specification and, as such, is administrative in nature. Any changes to CTS 3.4.A for SLC Operability requirements are discussed in the Discussion of Changes for ITS 3.1.7. ITS Table 3.3.6.1-1 Footnote (d)is added to clarify that the SLC System initiation only inputs into one of the two trip systems. (3.3.6.1-1 } A6 CTS Table 4.2-A contains a Channel Functional Test (CFT) for the RWCU isolation upon SLC System Initiation. The CFT has been deleted since it is redundant to the Logic System Functional Test (LSFT). The SLC System initiation channels have no adjustable setpoints, but are based on switch manipulation. The LSFT, which tests all contacts, will provide proper testing of the channels tested by a CFT. Therefore, this deletion is considered administrative. A, CTS Tables 3.2-A and 4.2-A list the following as Secondary Containment isolation Functions:
- 1. Refuel Floor Exhaust Duct - liigh Radiation
- 2. Reacter Building Exhaust Shaft Tigh Radiation
- 3. Of fgas Vent Stack -liigh Radiation The OfTgas Vent Stack - liigh Radiation isolation Function is only required to isolate the primary containment vent and purge valves as described in CTS Table DAEC 2 Revision 1 l
DISCUSSION OF CilANGES ITS 3.3.6.1: PRIhiARY CONTAINhiENTISOLATION INSTRUh1ENTATION ADh11NISTRATIVE CilANGES (continued) A7 3.2-A Action 27. Therefore, this function will only appear in ITS 3.3.6.1 for (cont.) Primary Containment isolation Instmmentation. Since the CTS requirements for the Function are being maintained in the ITS, the change is considered to be administrative. The Refuel Floor Exhaust Duct and Reactor Building Exhaust Shaft - IUgh Radiation Functions provide isolations for both Priinary and Secondary Containment. Herefore, these functions will appear in both ITS 3.3.6.1 for Primary Containment Isolation instrumentation and in ITS 3.3.6.2 for Secondary Containment isolation Instrumentation. As CTS Tables 3.2-D and 4.2-D require Operability of the hiain Steam Line Rae ;.on Monitors when required by CTS 3/4.7.M, Mechanical Vacuum Pump. CTS 3/4.7.M Operability is whenever the main steam isolation valves are open. ITS Table 3.3.6.1-1 requires Operability of the Main Steam I.ine Radiation - liigh Function in Modes 1. 2 and 3. The ITS implements the intent of the CTS by requiring Operability of this isolation function in Modes where potential releases through open main steam lines can occur. Herefore, this change is considered administrative in nature. A, CTS Table 4.2-A, footnote (c) and CTS Table 4.2 D, footnote (a) describes the Channel Functional Test for Mainsteam Line Radiation-High as consisting of injecting a simulated eleletrical signal into the measurement channels. This information is included in the Defmition of Channel Functional Test and is therefore not required in ITS 3.3.6.1 aad may be deleted. This is considered to be an administrative change. [CRF 9166] Ao i CTS Table 3.2-A, Note m, identifies the Applicability for the offgas Vent Stack-liigh Radiation Function (ITS Function 2.c). Currently, this Function must be Operable "During venting or purging of primary containment at any time when primary containment integrity is required." Pmposed Specification 3.3.6.1 will require that tnis Function be Operable during venting or purging of primary containment in Modes 1,2, and 3. This is considered to be an administrative change since the primary contcinment is required to be Operable in Modes 1,2, and 3. His change is consistent with tne NUREG. {3.3.6.1-19) DAEC 3 RevisionI l
DISCUSSION OF CllANGES ITS 3.3.6.1: PRIMARY CONTAINh1ENT ISOLATION INSTRUh1ENTATION TECilNICAL CliANGES - hiORE RESTRICTIVE Mi CTS Tables 3.2-A and 4.2-A requires Operability of the RIIR Shutdown Cooling Reactor Vessel Low Water Level Isolation Function in Modes 1,2 ano 3. The RilR Shutdown Cooling Reactor Vessel Low Water Level isolation Function has been modified in ITS 3.3.6.1 to require the isolation to be Operable in Modes 3,4 and 5, since this is when the function is needed to isolate if an inadvertent draindown event occurred. This is consistent with NUREG 1433, and is an additional restriction on pir.nt operation. The deletion of Mode 1 and 2 Operability requirements is a less restrictive change and is discussed below in the Technical Changes Less Restrictive Section. M2 CTS Table 4.2 A has N/A for the Channel Check for RWCU Area Temperature - liigh and RWCU Area Ventilation Differential Temperature - High. ITS Table 3.3.6.1-1 Function 5.f, Area Near TIP Room Ambient Temperature - High is included in the CTS Table 4.2-A Function of RWCU Area Temperatert : High. ITS SR 3.3.6.1.2 is being added to these Functions (5.b,5.c, and 5.f) to be consistent with the performance of Channel Checks in other areas of the Technical Specifications and DAEC philosophy for good operating practices. The addition of these requirements are more restrictive on plant operations. M3 CTS Table 3.2 A uses Action 26 for the Secondary Containment isolation Functions of Refuel Floor Exhaust Duct and Reactor Building Exhaust Shaft - High Radiation. Action 26 requires isolation of the Secondary Containment with the Standby Gas Treatment System operating within one hour. Rese functicas also , close primary containment isolation valves for recirculation pump seal purge, nitrogen makeup, and primary containment vent and purge valves. Howeve , the CTS dots not contain actions for these primary containment functions. ITS 3.3.6.1 contains Action 11 for these functions which requires the plant to be in Mode 3 in 12 l hours and in Mode 4 in 36 hours. The addition of this Action is considered to be more restrictive. (3.3.6.1.16) l M. CTS Table 4.2-A has N/A for the Channel Functional Test for the RCIC Leak Detection Time Delay. ITS Table 3.3.6.1-1 identifies a Quarterly Chan ei Functional Test for this function. The cun ent operating practice at DAEC provides for conducting this quarterly Channel Functional Test outside of the CTS. The CTS does not contain this requirement and therefore the addition of the Channel Functional Test is considered to be more restrictive. DAEC 4 Revision 1 l l
DISCUSSION OF CilANGES ITS 3.3.6.1: PRlhiARY CONTAINhtENT ISOLATION INSTRUhiENTATION TECilNICAL CilANGES - h10RE RESTRICTIVE (continued) hi 3 Per our conference call with the StafTon February 18,1998, this change will be withdrawn and the current licensing basis will be retained. The Staff's position was that it was acceptable to ensure that adequate Spatial coverage of each area is maintained by use of administrative controls outside of the TS. Thus, proposed footnote (d) is $ cing deleted and subsequent footnotes (e) and (f) will be re-ordered to (d) and (c), respectively. (3.3.6.1 1 } h1 6 CTS Table 3.2-B Action 30 requires if actions are not met for inoperable Containment Cooling System Isolation channels of Containment Pressure Iligh, that the associated system be declared inoperable, in the CTS, the associated system would be Containment SF ays which contains both the Drywell vad Suppression Pool Spray Systems. The Containment Sprays and Suppression Pool Cooling Function piping share the same containment penetration. Actions have been added to ITS 3.3.6.1 in order to protect the primary containment from inadvertent spraying and to ensure the availability of Suppression Pool Cooling and Spray when required. l ITS 3.3.6.1 Required Action A.2 is added such that with one or more Containment Pressure - liigh channels inoperable, containment sprays are inhibited within 24 hours. If mitomatic isolation apability is lost, containment integrity could be threatened due to exceeding L.: containment negative design pressure limit (if spraying occurred when less than a nominal 2.0 psig in the containment). Inhibiting the containment sprays will ensure that proper actions are taken for this condition. Currently, the containment sprays are not required to be inhibited. The channel must only be piaced in trip. ITS 3.3.6.1 Required Actions K.1 and K.2 are added to address the condition where l Containment Pressure - liigh channels are not restored or placed in trip within the allowed Completion Time of Action A or B. Required Action K.1 would be entered l if a channel is not placed in trip since this results in the Suppression Pool Cooling and spray functions being inoperable. Similarly, if the inoperable channels are in l trip such that containment spray can occur when less than a nominal 2.0 psig in the containment, (i.e., the containment sprays are not inhibited) then primary containment is declared inoperable inunediately per Required Action K.2. l DAEC 5 RevisionI l
DISCUSSION OF CilANGES ITS 3.3.6.1: PRIh1ARY CONTAINhfENT ISOLATION INSTRUh1ENTATION TECilNICAL Cl{ANGES - A10RE RESTRICTIVE (continued) hi 6 The Suppression Pool Cooling and Spray Functions would be inoperable since the (cont.) primary containment isolation valves in its flowpath could not be opened. Therefore, Required Action K.1 will require the associated Suppression Pool Cooling / Spray subsystem (s) to be declared inoperable I hour from discovery ofloss ofinitiation capability. {3.3.6.1 16, S3.6.2.4-1) The addition of these Action requirements is considered to be more restrictive. hi, CTS Table 4.2-A contains a Refueling interval Channel Calibration for the Function of RCIC Turbine Exhaust Diaphragm Pressure-liigh. The cmrently installed instrumentation cannot support this testing interval. The proposed change will require a Channel Calibration on a 184 day interval consistent with the DAEC Instniment Setpoint Control Program. This change is more restrictive than CTS provisions. M. CTS Action 23 for the llPCI and RCIC System Initiation isole. tion Functions in Table 3.2-A requires, with less than the required Operable channels, closing the affected system isolation valves within one hour and declaring the associated system inoperable. These Functions are being incorporated into their associated system Operability requirements ofITS SR 3.5.1.7 (IIPCI) and 3.5.3.5 (RCIC) (see DOC R i o below). In the ITS, if this isolation function is found to be inoperable, per SR 3.0.I, the associated system will be declared inoperable immediately. Thus, the ITS will be hiore Restrictive than the CTS when this function is made or found to be inoperable, nis is acceptable, a the associated ITS LCO Completion Time is 14 days. So the elimination of one hour to repair the isolation function is not significant. (3.3.6.1-3} hi, Footnote (a) to CTS Table 4.2 A describes the Channel Functiona! Test for RWCU Area Temperature - liigh as consisting of comparing the analog signal of the active thermocouple element. It is possible to perform a " standard" Channel Functional Test of thcse instruments. Therefore, Fcetac*e (:y is proposed to be deleted and this change is considered more restrictive. This change is consistent with the NUREG. (CRF 9114,9230] DAEC 6 Revision 1 l
l DISCUSSION OF CIIANGES ITS 3.3.6.1: PRihiARY C7NTAINh1ENT ISOLATION INSTRUhiENTATION TECIINICAL Cl{ANGES - RELOCATIONS Ri CTS 3.2.A.l.b contains a "*" footnote that describes when to place channels in trip. System operational details have been relocated to plant procedures. These details are unnecessary in the ITS and can be adequately controlled in plant procedures. Required Action A.1 ofITS 3.3.6.1 requires placing allinoperable channels in trip unless it is not desired to place the channel in trip because this would cause an isolation. In this case, Condition C is entered for the inoperable channels. This implements the intent of the CTS. Changes to procedures will be evaluated in accordance with the DAEC 10 CFR 50.59 program. This change is consistent with the NUREG. R2 This change proposes to relocate the " Trip Level Setting" column in CTS Table 3.2-A and Table 3.2 B and the " alarm / trip setpoint" column in CTS Table 3.2 D, and replace then with an " Allowable Value" column in ITS Table 3.3.6.1-1. Trip setp J its are an operational detail that is not directly related to the Operability of the instrumentation and will be relocated to a licensee controlled document. The Allowable Value is the required limitation for the parameter and this value will be inserted in the table. Any change to the trip setpoints will be evaluated in accordance with the DAEC Setpoint Control Program and 10 CFR 50.59 program. This change is consistent with the NUREG. R3 CTS Table 3.2-A contains a column listing the valve groups isolated by the trip function signal. As a result of relocating the column listing the valve groups, associated CTS Table 3.2-A Footnotes (b), (c), (e), (g), and (h) are also relocated. l This type of desesiptive material is not required to be retained in the DAEC ITS and is being relocated to plant procedures or the Bases. Any changes to this descriptive material in plant procedures will be evaluated in accordance with the DAEC 10 CFR 50.59 program. Changes to the Bases will be controlled in accordance with the TS Bases Control Program. The change is consistent with the NUREG. (3.3.6.1-16) R4 CTS Table 3.2-A contains a Footnote (o) to the Trip Function of hiain Steam Line Tunnel Temperature-liigh. This Footnote states that a minimum of two temperature sensors (instrument channels) per main steam line are required. ITS Table 3.3.6.1-1 requires a minimum of 4 channels per trip system. This type of descriptive material is not contained in the NUREG TS and is being relocated to the Bases. Changes to the Bases will be controlled in accordance with the TS Bases Control Program. This change is consistent with the NUREG. DAEC 7 Revisioni j
DISCUSSION OF CllANGES ITS 3.3.6.1: PRIhiARY CONTAINhiENT ISOLATION INSTRUh1ENTATION TECIINICAL tilANGES - RELOCATIONS (continued) R3 CTS Table 4.2 A contains descriptive information in Footnotes "##", (a) and (c) that is not in the NUREG. Footnote "##" states that the Reactc: Vessel Water Level-Low Low Low Trip Function is com~on to ECCS. Footnote (a) describes the Channel Functional Test for RWCU Area Temperature - liigh as consisting of comparing the analog signal of the active thermocouple element feeding the isolation logic to a redundant thermocouple element. Footnote "# #"is being relocated to plant controlled documents. See DOC A 9 for footnote (c). See DOC hi9 for footnote (a). Changes to these requirements will be evaluated in accordance with the DAEC 10 CFR 50.59 program. (CRF 9114,9230] R6 CTS Table 3.2 A Footnotes (d), (f), and (j) contain descriptive inforrt ation that is not in the ITS. Footnote (d) states that the actual setpoint for RWCU Area Ventilation Differential Temperature - liigh shall be 14 ' F above le 100% operation ambient temperature conditions as determined by DAEC plant test procedure. Footnote (f) states that Group 9 isolation requires a system steam supply pressure-low coincident with drywell pressure-high to close the liPCl/RCIC exhaust vacuum breaker valves. Footnote (j) applies to the hiain Steam Line Radiation - liigh Trip Function and describes setpoint changes due to hydrogen injection. The information in these footnotes is being relocated to plant controlled dxuments or the Bases. Any changes to these requirements will be evaluated in accordance with the DAEC 10 CFR 50.59 program or the TS Bases Control Program. R, CTS Table 4.2-A contains a "###" footr. .: that states that the Primary Containment isolation Functions of Reactor Water Levei - Low and Drywell Pressure - High are common to the RPS and ECCS activation trip functions. The intent of this footnote is incorporated into ITS 3.3.6.1 Required Action A.1 for Primary Containment isolation Functions com. mon to RPS. The statement that these isolation Functions are common to ECCS is not in ITS 3.3.6.1 and is proposed to be relocated to plant controlled documents. Changes to these documents will be evaluated in accordance with the DAEC 10 CFR 50.59 program. This change is consistent with the NUREG. DAEC 8 RevisionI l l l
l DISCUSSION OF CIIANGES ITS 3.3.6.1: PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION TECilNICAL CliANGES - RELOCATIONS (continued) l R. CTS Table 3.2 D Footnote (c) contains descriptive material which states that the Main Steam Line Radiation Monitors trips the mechanical vacuum pump which results in a subsequent isolation of the mechanical vacuum pump suction valves. His type of descriptive material is not in the ITS and is being relocated to the Bases. Changes to the Bases will be made in accordance with the TS Bases Control Program. R, Ser. DOC A9 above. [CRF 9166] l R a, CTS Table 3.2-A contains a RCIC and a liPCI System initiation isolation function for the Group 8 valves. These isolation signals are generated when the l associated system initiates and results in closure of associated system steam line drains and the discharge line to radwaste. This design feature for RCIC and IIPCI is common to BWRs, but is not commonly included in the TSs as a separate 3 Function. The relocation of these requirements to the Bases for SRs 3.5.1.7 ! (llPCI) and 3.5.3.5 (RCIC) is acceptable since these system actuation tests of RCIC and IIPCI will test the closure of these valves on the same frequency as the CTS (i.e., once per Refuel Cycle. Note: see DOC L.CY-2 to ITS 3.5 for the extension from 18 to 24 month cycles). Because the CTS Action 23 to declare the associated system inoperable is equivalent to that ofITS SR 3.0.I, when this isolation is know to be inoperable, there is no need in the ITS to specify this function uniquely in LCO 3.3.6.1, as all the appropriate testing and Actions will be taken in LCO 3.5.1 (llPCI) and 3.5.3 (RCIC). (See new DOC Maabove for the change in Completion Time.) Any changes to these requirements will be evaluated in accordance with the DAEC Bases Control Program. This change is consistent with the NUREG. {3.3.6.1-3) l Ru CTS Table 3.2 A setpoints for RCIC isolation of the steam line low pressure l functions are specified as "100>p>50 psig." This specification of both the trip and trip reset pressure provides some assurance of the availability of RCIC following a trip on steam line low pressure. ITS 3.3.6.1 (Function 4.c) will specify the steam line low pressure trip setpoint. Ilowever, the trip reset will be relocated to plant procedures because the trip reset is not assumed in any accident analysis. Placing this requirement in the plant procedures provides assurance it will be maintained. Changes to the plant procedures are controlled so that the information will not be changed without a 10 CFR 50.59 review. This change is consistent with NUREG-1433. [CRF 9218] DAEC 9 RevisionI l e- w- , .--s
DISCUSSION OF CilANGES ITS 3.3.6.1: PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION
/
TECIINICAL CIIANGES - LESS RESTRICTIVE Li CTS 3.2.A.1 Actions for Isolation Actuation Instrumentation differentiate between whether channels are inoperable in one or both trip systems. With channels out in both trip systems, the CTS Actions require placing at least one trip system in the tripped condition (unless placing the trip system in trip would cause the isolation) and taking the action required by Table 3.2-A. The current actions require isolating the penetrations at all times when channels are inopeinble in both trip systems, Because of the varied logic in isolation actuation systems there is no relatively ) simple set of actions that can be dermed to cover all situations. f TS 3.3.6.1 has combined the Actions for inoperable channels, independent of whether one or both trip systems are affected. 'Ihis allows the conservative action of tripping the inoperable channels, which is preferable to initiating a shutdown, as is currently required in many cases. If all channels are not restored or tripped, then the Actions referenced in ITS Table 33 6.1-1 are required, similar to the CTS. This change is acceptable since the ITS Actions maintain Primary Containment Isolation capability, or if not met, estab:ishes appropriate remedial actions. L2 CTS 3.2.A.I.a.1 contains Actions for Isolation Actuation Instrumentation channels which allows 6 hours to rectore inoperable channels when placing the inoperable channel (s)in trip would cause the isolation. The CTS Action allows time for channel restoration within one trip system, without having to take the isolation. CTS 3.2.A.l.a.2 contains restoration times for inoperabk. channels where placing the channel (s) in trip would not cause an isolation. Restorction times are 12 hours for trip functions common to RPS and 24 hours for trip functions not common to RPS. ITS 3.3.6.1 Action A allows the 12 and 24 hour Completion Times for all inoperable channels (as long as primary containment isolation capability is maintained) before requiring entry into the Condition referenced in Table 3.3.6.1-1. These Completion Times have been shown to maintain an amptable risk in accordanee with pre' iously NRC-approved reliability analyses (NEDC-31677-P-A,
" Technical Specification improvement Analysis for BWR Isolation Actuation Instrumentation," July 1990, and NEDC-30851-P-A, Supplement 2," Technical Specification improvement Analysis for BWR Isolation Instrumentation Common to RPS and ECCS Instrumentation," March 1989.) The DAEC has confirmed the applicability of these analyses to its plant design. The proposed change is acceptable since the remaining Operable channels are capable of performing the necessary isolation functions.
DAEC 10 RevisionI l
DISCUSS.ON OF CllANGES ITS 3.3.6.1: F dlMARY CONTAINMENT ISOLATION INSTRUMENTATION TECHNICAL CHANGES -i.ESS RESTRICTIVE L3 CTS Table 3.2-A uses Action 23 for the Reactor Water Level Low isolation signal for the RIIR Shutdown Cooling System. Action 23 requires the affected system isolation valves be closed within one hour and the afTected system to be declared i inoperable. ITS 3.3.6.1 Act on J requires Action to be initiated immediately to l restore channels to Operable status m te initiate Action to Immediately isolate the RHP SDC System. The ITS does not require RHR-SDC System isolation if Action is proceeding on a continuing basis to restore the inoperable channel (s) to Operable status. This change is acceptable since manual isolation of the RHR-SDC isolation valves can be accomplished, if necessary. The ITS Action recognizes that RHR-SDC may be needed to provide decay heat removal and thus the allowance is provided m allow the penetration flow path to remain unisolated. Actions must continue until the channel is restored to OPERABLE status or the RHR-SDC e system is isolated. Also, the RHR-SDC System contains interlocks on valve operation to ensure that an inadvertent draindown event does not occur, {3.3.6.1-4 and 3.3.6.1-16} L4 CTS Action 21 for Main Steam Line Isolation Trip Functions requires the plant to be in at least Startup with the associated isolation valves closed within 6 hours or to be in at least Hot Shutdown wiuin 12 hours and in Cold Shutdown within the next 24 hours. CTS Action 20 for the Main Steam Line Flow-High Isolation Trip Function requires the plant to be in at least Hot Shutdown within 12 hours and in Cold Shutdown within the next 24 hours. ITS Table 3.3.6.1-1 for the Main Steam Line isolation Functions 1.a,1.c, l.d, l.e, and 1.g use Action D which allows 12 hours to isolate the associated main steam line g to be in Mode 3 in 12 hours and Mode 4 in 36 hours. For the affected Main Steam Line Isolation Functions, isolation of the main steam line associated with the inoperable channels, accomplishes the design function of the instrumentation and no further Action is needed. The Completion Time of 12 hour to isolate the associated main steam line is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. DAEC 11 RevisionI l s ,
DISCUSSION OF CllANGES ITS 3.3.6.1: PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION TECIINICAL C11ANGES - I.ESS RESTRICTIVE L5 CTS Table 3.2-A and Table 4.2-A require the RilR-SDC isolation Trip Function of Reactor Vessel Water Level-Low to be Operable in Modes 1,2, and 3. ITS 3.3.6.1 will require Operability of this function in Modes 3,4, and 5. The deletion of the Operability requirements for Modes I and 2 for this trip function is considered to be less restrictive. SDC cannot be placed into senice in Modes 1 or 2 due to ECCS Operability requirements and since SDC is not allowed to be placed in senice until the Mode Switch is placed in Shut ; vn. This change will require Operability of the trip function when it is needed to iwiate RHR-SDC if an in vivertent draindown event occurred. ITS Table 3.3.6.1-1 adds Footnote (e) which only requires one trip l system to be Operable in Modes 4 and 5 when RilR-SDC System integrity is maintained. Each trip system can close one RilR-SDC isobtion valve and, requiring one to be Operable, is su0icice. to :nsure that the isolation function can be accomplished in Modes 4 and 5. (3.3.6.1-1 } l L6 This change will delete the uactor Vessel Water Level - Low Low Low, Group 7 Isolation Function from CTS Table 3.2-A. .%e Reactor Vessel Water Level - Low Low Low, Group 7 Isolation signal functior o close the Reactor Building Closed Cooling Water (RBCCW) Drywell Outlet and Inlet Valves, and the Well Water Drywell Cooling Water Supply and Discharge Valves. The RBCCW System is a closed loop water filled system that provides cooling water to Drywell equipment sump coolers and recirculation pump seal heat exchangers. RBCCW is equipped with a radiation monitor to detect leaks into the system. The Well Water System is a closed system in the Drywell and provides a once through cooling function for the Drywell coolers. The Well Water System operates at a higher pressure than the Drywell even under accident conditions. The RBCCW and Well Water Systems are considered closeo systems with respect to GDC 57 since they are not part of the reactor coolant pressure boundary nor are they twmected to the containment atmosphere. GDC 57 requires these systems to have at least one containment isolation valve which can be either automatic, or locked closed, cr capable of remote manual operation. Funhermore, this isolation valve is required to be outside of primary containment and located as close to the containment as practical. DAEC 12 Revisioni l
DISCUSSION OF CliANGES ITS 3.3.6.1: PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION TECllNICAL CIIANGES - 1.ESS RES1RICTIVE L,, The DAEC design for the systems that are within the secpe of GDC 57 are designed (cont.) with automatic isolation capability; however, these systems are able to comply with GDC 57 requirements by utilizing remote manual closure capability and, therefore, the automatic isolation function is not required to meet the GDC requirements. DAEC wi'l continue to comply with the GDC requirements, and an adequate level of safety will still exist, even if this automatic notation function in removed from the CTS. Therefore, this change is acceptable. L7 CTS Table 3.2-A uses Action 23 for the RWCU isolation ftuiction of Standby Liquid Control System initiation. Action 23 requires the affected system isolation valves to be closed within one hour a_nd the affected system to be declared inoperable. The RWCU System by itself, does not have specific Operability requirements in the CTS or ITS. ITS 3.341 Action I requires the Standby Liquid l Control (SLC) System to be declared inoperable within one hour or the RWCU System to be isolated within one hour. The ITS will allow the RWCU System to continue in operation as long as the SLC System is declared inoperF This change is acceptable since the RWCU System can be isolated from the remchting diverse isolation signals and with SLC declared inoperable, ITS 3.1.7 will limit the time the plant can operate in this condition. {3.3.6.1-16} l La CTS Table 3.2-A includes the Manual Initiation Functions for RCIC and IIPCI. Action 25 allows 8 hours to restore an inoperabh function and if not met. allows another hour to close the afTected system isolation valves and declare the affected system inopec ble. ITS 3.3.6.1 Action G for this trip function allows 24 hours to isolate the afTected penetration flow path (s). The ITS is less restrictive than the CTS and increases tne Action Completion Time by 15 hours. This change is acceptable since there is no specific UFSAR analysis that takes credit for these Functions. They are included in the ITS for overr'l redundancy and diversity of the isolation function. Furthermore, this change is consistent with the NUREG. (3.3.6.1-16} DAEC 13 RevisionI l
DISCUSSION OF CilANGES ITS 3.3.6.1: PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION TFCIINICAL Cll ANGES - I ESS RESTRICTIVE (continued) L, CTS Table 3.2-A requires Operability of the isolation Function of OfTgas Vent Stack - liigh Radiation during venting or purging of primary containment at any time when primary containment integrity is required (i.e., in Modes 1,2, and 3 per DOC A.10). CTS Table 4.2-A requires Surveillance Requirements (SRs) for the Offgas Vent Stack - High Radiation Function to be performed in Modes 1,2,3 and
- The "*" footnote applies when handling irradiated fuel in the secondary containment and during Core Alterations and Operations with a Potential for Draining the Reactor Vessel (OPDRVs). CTS Table 4.2-A incorrectly requires SRs to be performed for Modes and conditions outside the Modes of Applicability in CTS Table 3.2-A. The Modes 1,2,3 and
- requirement for this Function in Table 4.2-A is being replaced with a requirement to only perform the SRs during venting or purging of primary containment when primary containment integrity is required (i.e., in Modes 1,2, and 3 per DOC A.10) . This change is acceptable since the Offgas Vent Stack - High Radiation Function is only assumed by accident analysis to perform a primary containment isolation of the vent and purge paths and is not assumed to isolate the secondary containment or start the Standby Gas Treatment System. The isolation is initiated to limit the release of fission pmducts should a LOCA ocet r, while the primary containment is undergoing vent or purge operations. At other times, these valves will be closed per LCO 3.6.1.3, therefon ,
the function is not required to be Operable. (3.3.6.1-15,3.3.6.1-19} Lm Based on discussions with the NRC Staff on January 14,1998, this ,e has been withdrawn. 13.3.6.1-7} Lu CTS Table 3.2-B Action 30 with more than one afTected Containment Cooling System isolation Channel of Containment Pressure - High inoperable, requires declaring the associated system inoperable. ITS 3.3.6.1 Action A allows 24 hours to place the channel (s) in trip when one or more required channels are inoperable as long as isolation capability is maintained and compensatory measures are taken to protect primary containment integrity by inhibiting containment spray. The isolation logic for this function is a one-out-of-two taken twice arrangement. Depending on which channels are inoperable, two channels could be inoperable and isolation capability would still be retained. Thus, the ITS can allow up to two channels of the function to be inoperable for up to 24 hours before requiring further action to place the channel (s) in trip and inbloit the containment spray systems. This change is acceptable since isolatica capability is re'ained during the 24 hour Completion Time for placing tne channels in trip and inhibiting containment spray. DAEC 14 RevisionI l
DISCUSSION OF CHANGES ITS 3.3.6.1: PRIMARY CONTAINMENTISOLATION INSTRUMENTATION TECIINICAL CilANGES -I ESS RESTRICTIVE (continued) Ln CTS Table 3.2-A uses Action 21 for the Main Stearr Line Radiation - Isolation Function. Action 21 requires the plant to be in at least startup with the associated isolation valves closed within six hours or be in Mode 3 in 12 hours and Mode 4 within the next 24 hours. The CTS Action is overly restrictive for this isolation function. CTS Table 3.2-A, Footnote (b) states that this Function isolates Group 1 valves except for the MSIVs. The Group 1 isolation valves closed by the MSL liigh Radiation signal are the MSL drains, re:irculation sample valves, and the mechanical vacuum pump isolation valves. The use ofITS 3.3.6.1 Acti^n F for this isolation function is appropriate since the associated penetration flow paths are required to be closed within one hour. The closure of the penetration flow paths ensures that releases to the environment are terminated without requiring a plant power reduction or shutdown. Lu CTS Table 3.2-B Action 30 with more than one channel inoperable, requires declaring the associated system inoperable immediately. ITS 3.3.6.1 Required Action B.1 allows I hour to restore isolation capability when isolation capability is not maintained from the Containment Pressure - High Function. The one hour timeframe allowed in the ITS to restore isolation capability before declaring associated systems inoperable is less restrictive than the CTS requirement of immediately. The one hour timeframe is a reasonable allowance for the operator to confirm the function is inoperable and to attempt restoration ofisolation capability. If Required Action B.1 is not met, then Action K is entered and l requires immediate action to either declare the associated Suppression Pool Cooling / Spray subsystem (s) inoperable or Primary Containment inoperable. This l change is appropriate and consistent with other CTS Actions for instrumentation that allow I hour to declare associated systems inoperable with multiple channels inoperable. (3.3.6.1-16, S3.6.2.4-1 } l DAEC 15 Revision 1 l 5 \ i l
DISCUSSION OF CliANGES ITS 3.3.6.1: PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION TECIINICAL CIIANGES - LESS RESTRICTIVE (continued) La CTS Table 3.2-A uses Action 22 for the Main Steam Line Pressure - Low Isolation Function. Action 22 requires the plant to be in at least Startup within 6 hours. ITS 3.3.6.1 Required Action E.1 allows 8 hours to be in Mode 2. The Completion Time to reach Mode 2 is intended to allow for a controlled plant i shutdown. The DAEC has determined, based on reviews of recent plant controlled shutdowns, that 6 hours is not sufficient to reach Mode 2 from 100% RTP. Three controlled shutdowns that occurred in 1993 and 1994 indicate that between 7 and 8 hours were required to reach approximately 5 - 10% RTP where a manual scram was inserted as part of the normal shutdown. The 2 hour l extension to reach Mode 2 recognizes that adequate time must be specified to perform required ITS actions while ensuring that the plant reaches a safe condition in a reasonable timeframe. The extra 2 hours is not significant since the
. plant initiates a shutdown when entering the ITS Action and must continue the shutdown in a centrolled manner in order to meet the proposed 8 hour Completion Time.- {3.3.6.1-9) l Ln Per our Response to the Staff's RAI on this Note (Ref. NG-97-1597) and our meeting with the StalTon September 9,1997, this change has been withdrawn.
{3.3.6.1-10} ' Lv3 This change revises the Technical Speci. . aon setpoints for proposed Section 3.3 instrumentation to reflect Allowable Values consistent with the philosophy of the NUREG. These Allowable Values (to be included in Technical Specifications) and the Trip Setpoints (to be included in plant procedures) have been established by the DAEC Instrument Setpoint Methodology, which is based on NEDC-31336,
" General Electric Instrumentation Setpoint Methodology." Th- NRC approval of NEDC-31336 is documented in a Revision to the Safety Evaluation Report transmitted by letter from B. Boger (NRC) to R. Pinelli (BWROG) dated November 6,1995. The setpoint evaluation used the uncertainties associated with the DAEC instrumentation and actual DAEC physical data and operating practices to ensure -
the validity of the resulting Allowable Values and Trip Setpoints. The methodologies used to derive the Allowable Values and Trip Setpoints are based on combining the uncertainties of the associated channels. In the methodologies, the Trip Setpoints take into consideration calibration accuracies which were specifically assumed in the DAEC setpoint calculations. Plant calibration procedures will DAEC 16 RevisionI l 1
DISCUSSION OF CIIANGES ITS 3.3.6.1: PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION TEC1INICAL CllANGES -I.ESS RESTRICTIVE (continued) Lv 4 ensure the assumptions regarding calibration accuracy are maintained. The (cont.) proposed Allowable Values and Trip Setpoints have been established from each design or safety analysis limit by accounting for instrument accuracy, calibration and drift uncertainties, as well as process measurement accuracy and primary element accuracy using the DAEC Instrument Setpoint Methodology. The use of this methodology for establishing Allowable Values and Trip Setpoints ensures design or safety analysis limits are not exceeded in the event of transients or accidents. As such, this proposed change does not involve a significant reduction in a margin of safety. Lci The Frequency of performing the Channel Calibration surveillance of current Surveillances 4.2.A.1 and 4.2.B.1 and Tables 4.2-A and 4.2-B (proposed SRs 3.3.6.1.7 and 3.3.6.1.8) has been extended to facilitate a change to the DAEC operating cycle from 18 months to 24 months. This change is being proposed to support limiting the amount of surveillance testing that must be performed each opereting cycle. The proposed change will extend the Surveillance Frequency for ITS Table 3.3.6.1-1 Functions 1.a,2.a. 2.b,3.a,3.b,3.d,4.c,4.b,4.d,5.a,6.b,6.c, and 7.a from the current 3 month (i.e., Quarterly) Surveillance Frequency (i.e., a maximum of 3.75 months accounting for the allowable grace period specified in CTS Definition # 26 and ITS SR 3.0.2) to a 24 month Surveillance Frequency (i.e., a maximum of 30 months accounting for the allowable grace period specified in CTS Definition # 26 and ITS SR 3.0.2); and, for ITS Table 3.3.6.1-1, Functions 1.d. 3.e,3.f,3.g,3.h,3.i,4.e,4.f,4.g,4.h,4.i,5.b,5.c, and 5.f, from the current 12 month (i.e., Annual) Surveillance Frequency (i.e., maximum of 15 months) to a 24 month Surveillance Frequency (i.e., a maximum of 30 months.) In addition, the current 3 month (i.e., Quarterly) Surveillance Frequency (i.e., a maximum of 3.75 mont's accounting for the allowable grace period specified in CTS Definition # 26 erm iTS SR 3.0.2) for ITS Table 3.3.6.1-1 Function 5.e, is being extended to a 12 manth (i.e., Annual) Surveillance Frequency (i.e., maximum of 15 months). These Channel Calibration surveillances will continue to be perfonned in the same manner as it has been in that no modifications to test methodologies or station equipment have been included in this request. Equipment required to mitigate the consequences of an accident will not be affected: although the frequency of calibrating the instrumentation will be extended to accommodate a 24 month operating cycle, operating experience indicates that the proposed frequency is adequate to ensure continued equipment reliability. DAEC 17 Revision 1 l i
DISCUSSION OF CliANGES ITS 3.3.6.1: PRIMARY CONTAINMENTISOLATION INSTRUMENTATION TECIINICAL CilANGES - LESS RESTRICTIVE (continued) Lc i The 'hannel Calibration surveillance is performed to ensure that at a previously (cont.) evaluated setpoint actuation takes place to provide the required safety function. By increasing the calibration frequency from 3 (or 12) months to 24 months (or from 3 months to 12 months), the time interval for the Channel Calibration surveillance for this instrumentation wili oc increased liowever, as currently required by DAEC CTS, Channel Functional Tests are perform-1 during the operating cycle more frequently than the Channel Calibration surveillance. The purpose of the Channel Functional Tests is to detect failures of the instrumentation channels, and thus, is performed on a more frequent basis than Channel Calibrations. Gross instrumentation failures are detected by alarms or by a comparison with redundant and independent indications (i.e., Channel Checks). instrumentation purchased for these functions are highly reliabh and mect the design criteria of safety related equipment. The instrumentation is designed with redundant and independent channels which provide means to verify proper instrumentation performance during operation, and adequate redundancy to ensure a high confidence of system performance even with the failure of a single component. Based on this evaluation and the drift analysis performed, the DAEC has concluded that the impact on instrumentation reliability, if any, would be insignificant. NRC Generic Letter 91-04 (GL 91-04) provides guidance to licensees on the type of analysis and information required to justify a change to the surveillance interval for instrument calibrations. While GL 91-04 was written to support operating cycle extensions from 18 to 24 months, the guidance has been utilized to evaluate these Channel Calibration Surveillance Frequency extensions as well. Seven specific actions were delineated in GL 91-04 and are repeated below with the applicable response. This discussion is meant as a generic discussion to provide insight into the methodology (Se DAEC used to evaluate the affects of an increased surveillance interval on instrument drift. The results support the conclusion that instrument drift is not a significant factor in increasing the surveillance interval. DAEC 18 RevisionI l
DISCUSSION OF CIIANGES ITS 3.3.6.1: PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION TECliNICAL CilANGES - LESS RESTRICTIVE (continued) Lc i 1. Confirm that instrument drift as determined by as-found and as-left calibration data from surveillance and maintenance reco.-ds has not, except on rare occasions, exceeded acceptable limits for a calibration interval. The DAEC has completed engineering calculations and evaluations to document design, allowed values (as found tolerance limits), and applicable safety, analytical and operational limits for setpoints specified :' in the Technical Specifications. Setpoint calculations are performed in accordance with DGC-El11," Instrument Setpoint Guide." This guide was prepared for the DAEC by General Electric in accordance with the
" General Electric Instrument Setpoint Methodology," NEDC-31336-A.
The GE Setpoint Methodology implements the guidelines ofISA-STD-S67.04-1982 "Setpoint for Nuclear Safety Related Instrumentation Used in Nuclear Power Plants." The NRC issued a Safety Evaluation Report (SER) with five open items for th. methodology in correspondence from B. Boger to D. Robare titled " General Electric Company Topical Report NEDC-31336 " General Electric Instrument Setpoint Methodology," dated February 9,1993. This SER was amended in correspondence from B. Boger to R. Pinelli," Revision to Safety Evaluation Report on NEDC-31336, Instrument Setpoint Methodology (NEDC-31336P)," dated November 6,1995. The amendment 3ER closed the five remaining open items and concluded that the GE Setpoint Methodology was a satisfactory method to demonstrate compliance with Regulatory Guide 1.105
" Instrument Setpoint for Safety-Related Systems," revision 2. This Regulatory Guide endorsed ISA-STD-S67.04-1982. The Current Technical Specifications (CTS) setpoints calibrat;on surveillance intervals were considered in the existing versions of the '.0 CFR Part 50 Appendix B Design Control calculations. Historical as-found and as-left data has been utilized to validate that assumptions of values for vendor-specified drift were conservative. Where these assumptions were not validated, historical drift was utilized directly using the second moment about zero (SMAZ) method described in NEDC-31336-A. The resulting performance record supports the conclusion that as found calibration data from surveillance and maintenance records have not, except on rare occasions, exceeded acceptable limits for a calibration interval.
DAEC 19 RevisionI l
1. I h DISCUSSION OF CliANGES ITS 3.3.6.1: PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION I TECIINICAL CilANGES - LESS RESTRICTIVJi (continued) Lc i 2. - Confirm that the value of drift for each instrument type (make, model, and range) and application have been determined with a high probability and a 4 high degree of confidence. Provide a summary of the methodology and assumptions used to determine the rate ofinstrument drift with times based upon historical plant calibration. The probability and statistical confidence for the drift calculations were performed to the requirements on NEDC.31556 A. As stated above, historical as-found and as-left data have been utilized to validate that assumptions of values for vendor-specified drift were conservative. Where these assumptions were not validated, historical drift was utilized directly using the second moment about zero (SMAZ) method described in NEDC-31336-A.
- 3. Confirm that the magnitude ofinstrument drift has been determined with a high probability and n high degree of confidence for a bounding calibration inteival of 30 months far each instrument type (make, model, and range) and application that performs a safety function. Provide a list of channels by TS section Unt identifies these instrument applications.
Extensions of calibration intervals have been analyzed in revisions to the 10 CFR Part 50, Appendix B Design Control engineering .meulations in accordance with the t.pproved methodology. For extension of the CTS calibration surveillance intervals, the drift was predicted using the time correction method in section 4.4.3.5 of NEDC-31336-A up to a maximum interval of 30 months.
- 4. Confirm that the comparison of the projected instrument drift errors hu 4
been made with the values of drift used in the setpoint analysis. If this results in revised setpoints to accommodate larger drift errors, provide proposed TS changes to update trip setpoints. If the drift errors result in revised safety analysis conclusions to confirm that safety limits and safety analysis assumptions are not exceeded. DAEC 20 RevisionI l
DISCUSSION OF CHANGES ITS 3.3.6.1: PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION JJUHNICAL CilANGES - LESS RESTRICTIV.ri (continued) Lc i 4. As stated above, for extension of the CTS calibration surveillance (cont.) intervals, the drift was predicted using the time correction method in section 4.4.3.5 of NEDC-31336-A up to a maximum interval of 30 months. In the Improved Technical Specification (ITS) the Allowable Values are being specified, while in the CTS the value.< specified are nominal trip setpoints in most cases. The Allowable V alues for current surveillance intervals are implemented in the as-found tolerances in the surveillance procedures. Increasing the surveillance interval results in a larger assumed value for drift. Allowance for drift is included in the margin between the Allowable Value and the instrument nominal trip setpoint. The margin between the Allowable Value and the analytical or safety limit is established based on accuracy, calibration accuracy, process measurement accuracy, and process element accuracy, and is not affected by the value ofir rument drift. A comparison has been performed of the results of ca'
- ions for current and extended surveillance intervals. If the co- .. nad revealed a need to change the current Allowable V~ .a move the instrument setpoint to a value that exceeded the G aaminal trip setpoint, these changes would be identified as changes to Technical Specifications setpoints. No cases were found where extensions of surveillance intervals being iequested would require a change to the ITS Allowable Vtues.
- 5. Confirm that the projected instrument errors caused by drift are acceptable for control of plant parameters to effect a safe shutdown with associated instrumentation.
By implementing acceptable criteria for as-found and as-left tolerances for technical specification setpoint calibrations in accordance with the setpoint methodology, the projected instrument errors caused by drift are acceptable for control of plant parameters to affect a safe shutdown with the associated instrumentation.
- 6. Confirm that all conditions and assumptions of the setpoint and safety analyses have been checked and are appropriately reflected in the acceptance criteria of plant surveillance procedures for channel checks, channel functional tests, and channel calibrations.
DALC 21 RevisionI l l
I DISCUSSION OF CHANGES ITS 3.3.6.1: PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION TECllNICAL CilANGES oESS RESTRICTIVE (continued) Lc i 6. During setpoint calculation verifications, all conditions and assumptions (cont.) of the setpoint and safety analyses have been checked. Verification that the as-found and as-left tolerance are appropriately reflected in the acceptance criteria of pla..t surveillance procedures for Channel Checks, Channel Functional Tests, and Channel Calibrations is performed during the implementation of surveillance procedure changes.
- 7. Provide a summary description of the program for monitoring and assessing the effects ofincreased calibration surveillance intervals on instrument drift and its effects on safety.
Monitaring of the effects of surveillance interval extensions is performed by collecting as-found and as-left calibration data for setpoint calibration results. When as-found calibration data is outside of the surveillance procedure tolerance specified as Technical Specifications compliance steps, an Action Request (formal corrective action process) is issued to document the discrepancy, determine Operability, initiate NRC reporting, if required, and track resolution. In addition, the DAEC has instituted engineering best practices for trending maintenance data and failure of instruments to monitor performance and as a predictive maintenance tool. Repeated out-of-tolerance conditions and identified trends are referred for investigation or corrective action. The resolution of performance problems may include instrument replacement, reduction of surveillance intervals. revision of setpoint calculations to remove excessive conservatism, performance of n:w safety analysir to remove excessive conservatism, performance of new safety analysis to justify new tolerance, or improvements to calibration or surveillance procedures. All of these activities are triggers for invoking the Setpoint Control Program and include reviews for afety signuicance under the DAEC 10 CFR 50.59 program. These activities accomplish the function to monitor and assess potential effects on safety from surveillance interval extensions. DAEC 22 RevisionI l
i DISCUSSION OF CHANGES ITS 3.3.6.1: PRIMARY CONTAINMENTISOLATION INSTRUMENTATION TECHNICAL CIIANGES - 1.ESS RESTRICTIVE (continued) Lcy The Frequency of performing the Channel Calibration surveil'ance of current ' Surveillance 4.2.A.1 and Table 4.2-A (proposed SRs 3.6.1.7) has been extended to facilitate a change to the DAEC operating cycle from IS months to 24 months. This change is being proposed to support limiting the amount of surveillance testing that must be performed each operating cycle. The proposed change will allow this Surveillance to extend the Surveiliance Frequency from the current 18 month Surveillance Frequency (i.e., a maximum of 22.5 raonths accounting for the allowable grace period specified in CTS Definition # 26 and ITS SR 3.0.2) to a 24 month Surveillance Frequency (i.e., a maximum of 30 months accounting for the allowable grace period specified in CTS Definition # 26 and ITS SR 3.0.2). This Channel Calibration surveillance will continue to be performed in the same manner as it has been in that no modifications to test methodologies or station equipment have been included in this request. E1uipment required to mitigate the consequences of an accident will not be affected; although the frequency of calibrating the instrumentation will be extended to accommodate a 24 month operating cycle, operating experience indicates tha* the proposed frequency is adequate to ensure continued equipment reliability. Surveillance 4.2.A.! and Table 4.2-A currently requires the Channel Calibration to be performed once per 18 months. The Channel Calibration surveillance is performed to ensure that at a previously evaluated setpoint actuation takes place to provide the requimd safety function. By increasing the operating cycle from 18 to 24 months, the time interval for the Channel Calibration surveillance for this instrumentation will be increased. However, as currently required by DAEC CTS, Channel Functional Tests are performed during the operating cycle more frequently than the Channci Calibration surveillance. Tht purpose of the Channel Functional Tests is to detect failures of the instrumentation -hannels, and thus, is performed on a more frequent basis than Channel Calibration. Gross instrumentation failures are also detected by alarms or by a comparison with redundant and independent indications (i.e., Channel Checks). Instrument ~ ion purchased for these functions are highly reliable and meet the design criteria of safety related equipment. The instrumentation is designed with redundant and independent channels which provide means to verify proper instrumentation , performance during operation, and adequate redundancy to ensure a high confidence of system performance even with the frilure of a single component. DAEC 23 Revision! l
DISCUSSION OF CHANGES ITS 3.3.6.1: PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION TECIINICAL CilANGES - LESS RESTRICTIVE (continued) Lcv Based on this evaluation and the drift analysis performed, the DAEC has (cont.) concluded that the impact on instrumentation reliability, if any, would be insignificant. NRC Generic Letter 91-04 (GL 91-04) provides guidance to licensees on the type of analysis and information required to justify a change to the surveillance inte val for instrument calibrations. Seven specific actions were delineated in GL 91-04 and are repeated below with the applicable response. This discussion is meant as a generic discussion to provide insight into the methodology the DAEC used to evaluate the affects of an increased surveillance interval on instrument drift. The results support the conclusion that instrument drift is not a significant factor in increasing the suneillance inten al.
- 1. Confirm that instrument drift as determined by as-found and as-left calibration data from surveillance and maintenance records has not, except on rare occasions, exceeded acceptable limits for a calibration interval.
The DAEC has completed engineering calculations and evaluations to document design, allowed values (as-found tolerance limits), and applicable safety, analytical and operational limits for setpoints specified in the Technical Specifications. Setpoint calculations are performed in accordance with DGC-El11. " Instrument Setpoint Guide." This guide was prepared for the DAEC by General Electric in accordance with the " General Electric Instrument Setpoint Methodology," NEDC-31336-A. The GE Setpoint Methodology implements the guidelines ofISA-STD-S67.04-1982 "Setpoint for Nuclear Safety Related Instrumentation Used in Nuclear Power Plants." The NRC issued a Safety Evaluation Report (SER) with five open items for this methodology in correspondence from B. Boger to D. Robare titled " General Electric Company Topical Report NEDC-31336 "Ger.eral Electric Instrument Setpoint Methodology," dated February 9,1993. This SER was amended in correspondence from B. Boger to R. Pinelli," Revision to Safety Evaluation Report on NEDC-31336, Instrument Setpoint Methodology (NEDC-31336P)," dated November 6.1995. The amendment SER closed the five remaining open items and concluded that the GE Setpoint Methodology was a satisfactory method to demonstrate compliance with Regulatory Guide 1.105 DAEC 24 RevisionI l
f DISCUSSION OF CliANGES ITS 3.3.6.1: PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION f TECHNICAL CliANGES - LESS RESTRICTIVE (continued) ,- Lcy " Instrument Setpoint for Safety-Related Systems," revision 2. This (cont.) Regulatory Guide endorsed ISA-STD-S67.04-1982. The Current Technical Specifications (CTS) setpoints calibration surveillance intervals were considered in the existing versions of the 10 CFR Part 50 Appendix B Design Control calculations. Historical as-found and as-left data has been utilized to validate that assumptions of values for vendor-specified drift were conservative. Where these assumptions were not validated, historical drin was utilized directly using the second moment about zero (SMAZ) method described in NEDC-31336-A. The resulting performance re ucd supports the conclusion that as-found calibration data tiom surveillance and maintenance records have not, except t u occasions, exceeded acceptable limits for a calibration interval.
- 2. Confirm that the value of drift for each instrument type (make, model, and range) and application have been determined with a high probability and a high degree of confidence. Provide a summary of the methodology and assumptions used to determine the rate ofinstrument drift with times based upon historical plant calibration.
The probability and statistical confidence for the drift calculations were performed to the requirements on NEDC-31556-A. As st:ted above, historical as-found and as-left data have been utilized to validate that assumptions of salues for vendor-specifi I d-ift were conservative. Where these assumptions were not validated, historical drift was utilized directly using the second moment about zero (SMAZ) method described in NEDC-31336-A.
- 3. Confirm that the magnitude ofinstrument drift has been determined with a high probability and a high degree of confidence for a bounding calibration interval of 30 months for each instrument type (make, model, and range) and application that performs a safety function. Provide a list of channels by TS section that identifies these instrument applications.
Extensions of calibration intervals have been analyzed in revisions to the 10 CFR Part 50, Appendix B Design Control engineering calculations in accordance with the approved methodology. I DAEC 25 RevisionI l
DISCUSSION OF CHANGES ITS 3.3.6.1: PRIMARY CONTAINMENT lSLATION INSTRUMENTATION TECilNICAL CliANGES - LESS RESTRICTIVE (continued) Lcy For extension of the CTS calibration surveillance intervals, the drift was (cont.) predicted using the time correction method in section 4.4.3.5 of NEDC-31336-A up to a mxhnum interval of 30 months.
- 4. Confirm that the comparison of the projected instrument drift errors has been made with the values of drift used in the setpoint analysis. If this results in revised setpoints to accommodate larger drift errors, provide proposed TS changes to update trip setpoints. If the drin errors result in revised safety ar.alysis conclusions to ccnfirm that safety limits and safety analysis assumptions are net exceeded.
As stated above, for extension of the CTS calibration surveillance intervals, the drin was predicted using the time correction method in section 4.4.3.5 of NEDC-31336-A up to a maximum interval of 30 months. In the Improved Technical Specification (ITS) the Allowable Values are being specified, while in the CTS the values specified are nominal trip setpoints in most cases. The Allowable Values for current surveillance intervals are implemented in the as-found tolerances in the surveillance procedures. Increasing the surveillance
- interval results in a larger assumed value for drift. Allowance for drin is included in the margin between the Allowable Value and the instrument nominal trip setpoint. The margin between the Allowable Value and the analytical or safety limit is established based on accuracy, calibration accuracy, process measurement accuracy, and process element accuracy, and 7 is not affected by the value ofinstrument drift. A comparison has been performed of the results of calcelations for current and extended surveillance intervals. If the comparison had revealed a need to change the current Allowable Value, or to move the instrument setpoint to a value that exceeded the CTS nominal trip setpoint, these changes would be identified as changes to Technical Specifications setpoints. No cases were found where extensions of surveillance intervals being requested would require a change to the ITS Allowable Values.
- 5. Cor. finn that the projected instrument errors caused by drift are acceptable for control of plant parameters to effect a safe shutdown with associated instrumentation.
DAEC 26 RevisionI l
DISCUSSION OF CIIANGES ITS 3.3.6.1: PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION TECIINICAL CIIANGES - I.ESS RESTRICTIVE (continued) Lev By implementing acceptable criteria for as-found and as-left tolerances for (cont.) technical specification setpoint calibrations in accordance with the setpoint methodology, the projected instrument errors caused by drift are acceptable for control of plant parameters to affect a safe shutdown with the associated instrumentation.
- 6. Confirm that all conditions and assumptions of the setpoint and safety analyses have been checked and are appropriately reflected in the acceptance criteria of plant surveillance procedures for channel checks, channel functional tests, and channel calibrations.
During setpoint calculation verifications, all conditions and assumptions of the setpoint and safety analyses have been checked. Verification that the as-found and as-left tolerance are appropriately reflected in the acceptance criteria of plant surveillance procedures for Channel Checks, Channel Functional Tests, and Channel Calibrations is performed during the implementation of surveillance procedure changes.
- 7. Provide a summary description of the program for monitoring and assessing the effects ofincreased calibration surveillance intervals on instrument drift and its effects on safety.
Monitoring of the effects of surveillance interval extensions is performed by collecting as-found and as-left calibration data for setpoint calibration results. When as-found calibration data is outside of the survei!!ance procedure tolerance specified as Technical Specifications compliance steps, an Action Request (fomtal corrective action process) is issued to document the discrepancy, determine Operability, initiate NRC reporting, if required, and track resolution. In addition, the DAEC has instituted engineering best practices for trending maintenance data and failure ofinstruments to monitor performance and as a predictive maintenance tool. Repeated out-of. tolerance conditions and identified trends are referred for investigation or corrective action. The resolution of performance problems may include instrument replacement, reduction of surveillance intervals, revision of setpoint calculations to remove excessive conservatism, performance of new safety analysis to remove DAEC 27 RevisionI l
DISCUSSION OF CIIANGES ITS 3.3.6.1: PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION TECliNICAL CIIANGES - LESS RESTRICTIVE (continued) Lcy excessive conservatism, performance of new safety analysis to justify new (cont.) tolerance, or improvements tc calibration or surveillance procedures. All of these activities are triggers for invoking the Setpoint Control Program and include reviews for safety significance under the DAEC 10 CFR 50.59 program. These activities accomplish the function to monitor and assess potential effects on safety from surveillance interval extensions. l.cy.2 Generic Letter 91-04, Chances in Technical Snecification Surveillance Intervals to Accommodate a 24-month Fuel Cycle, describes NRC requirements for preparing such license amendment requests. The Generic Letter indicates that the NRC staff has generically reviewed the extension of surveillance intervals from 18 to 24-months and found that "the effect on safety is small because safety systems use redundant electrical and mechanical components and because licensees perform other surveillances during plant operation that confirm that these systems and components can perform their safety functions. Nevertheless, Licensees should evaluate the effect on safety of an increase in 18-month surveillance intervais to accommodate a 24-month fuel cycle. This evaluation should supp,rt a conclusion that the effect on safety is small." The Generic Letter specifies the following specific items for review: Steam Not applicable to DAEC Generators Instrument Drift Addressed independent of this review by the DAEC Setpoint Control Program Annendix J TS Amendment No. 219 addressed DAEC Exemption adoption of Option B to Appendix J No additional review is required in this evaluation. In addition, the Generic Letter indicates Licensee's should review the effect on safety of the extension of other surveillances to ensure that it is supported 'ay historical maintenance and surveillance data. DAEC 28 RevisionI l
DISCUSSION OF CilANGES ITS 3.3.6.1: PRIMARY CONTAINMENTISOLATION INSTRUMENTATION TECIINICAL CliANGES - LESS RESTRICTIVE (conh~l) Lcy.2 Data was collected for a ten-year period from January 1986 to January 1996 of all (cont.) deliciencies which occurred for the surveillances for which a frequency extension is being sought. The ten-year period was selected to ensure a broad overview of long term performance and because a similar comprehensive review was performed in 1986 for preceding years to support changes from 12-month to 18-month inter'
- As a supplemental check, the database for 10CFR50.65 (Maintenance Rule) compliance was reviewed to confirm that equipment performance overall was compatible with a decreased surveillance frequency. The DAEC program for Maintenance Rule includes targets for safety system train availability and reliability compatibb with assumptions in the DAEC Probabilistic Safety Analysis (data for the Maintenance Rule is limited to the period since 1991).
Data for the following surveillance tests were reviewed: Description CTS Section ITS SR SBI C Squib Valve Firing 4.4.A.2.b 3.1.7.7 SB!.C Flow Verification 4.4.A.2.c 3.1.7.8 SDV Vent and Drain Cycling 4.3.B.3 3.1.8.3 Reactor Mode Switch Channel 4.1. A.1 3.3.1.13 Functional RPS Response Time 4.1. A.2 3.3.1.18/3.3.1.19 MSL Radiation Monitor Logic 4.2.D.2.c 3.3.6.1.9 System Functional ATWS RPT Logic System 4.2.G.2 3.3.4.2.4 Functional RPT Breaker Response Time 4.2.G.3 3.3.4.1.3/3.3.4.1. 5 SV Setpoint Verification 4.6.D.1 3.4.3.1 SRV Setpoint Verification 4.6.D.1 3.4.3.1 SRV Manual Opening 4.6.D.3 3.4.3.2 IIPCI Low Pressure Flow 4.5.D. I .e 3.5.1.6 CS Logic System Functional 4.2.B.2.a 3.3.5.1.9 RilR Logic System Functional 4.2.B.2.b 3.3.5.1.9 DAEC 29
. Revision I l l
1 DISC 'SSION OF CIIANGES ITS 3.3.6.1: PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION TECIINICAL CllANGES -I ESS RESTRICTIVE (continued) I *CY.2 (cont.) Description CTS Section ITS SR Containment Spray Interlock 4.2.B.2.c 3.3.6.1.9 Logic System Functional llPCI Logic System Functional 4.2.B.2.d 3.3.5.1.9/3.3.6.1.10 l IIPCl/RCIC Suction Transfer 4.5.D. I .f 3.5.1.7/3.5.3.5 (relocated) ADS Logic System Functional 4.2.B.2.e 3.3.5.1.9 ADS Simulated Automatic 4.5.F.1.a 3.5.1.8 Actuation ADS Valve Manual Opening 4.6.D.3 3.5.1.9 RCIC Low Pressure 4.5.E.1.e 3.5.3.4 Drywell to Torus Leak Test 4.7.E.4 3.6.1.1.2 PCIV Simubted Automatic 4.7.B.I.a 3.6.1.3.6 Actuation ' Groups 1 - 6,8,9) PCIV Logic System Functional 4.2.A.2.a - g 3.3.6.1.9/3.3.6.1-10 l Test (Groups 1-6)
'EFCV isolation 4.7 B.I.c 3.6.1.3.7 LLS Valve Manual Opening 4.6.D.3 3.6.1.5.1 LLS Logic System Functional 4.2.B.2.g 3.3.6.3.6/3.6.1.5.2 Secondary Containment Integrity 4.7.J. l .a 3.6.4.1.3 SCIV/D Simulated Automatic 4.7.K.1 3.6.4.2.2 Actuations SBGT Simulated Automatic 4.7.L.l.d 3.6.4.3.3 Actuation River Water Supply Simulated 4.5.J.l.a .7.2.4 -
Automatic Actuation ESW Automatic Start w/ DG 4.8.E.1.a 3.7.3.2 SFU Simulated Automatic 4.10.A.a 3.7.4.3 Actuation Control Building Posinve 4.10.A.3 3.7.4.4 Pressure LOOP /LOCA fest 4.8.A.2.b 3.8.1.13 i DAEC 30 RevisionI l l
DISCUSSION OF CHANGES ITS 3.3.6.1: PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION
~
Battery Senice Discharge l 4.8.B.I.c l 3.8.4.7 TECHNICAL . CHANGES - LESS RESTRICTIVE (continued) Lc in each of these tests, no train failures were identified by performance of the (i .) eference cyclic test during the ten year period reviewed. In each case, the system performance was within targets established under the Maintenance Rule. This combination of no test failures and acceptable system performance is viewed as a strong indicator that interval extension is acceptable without more detailed review. For six Surveillance Tests, more than one failure was identified during performance of the test during the ten year interval. These tests were singled out as requiring further review prior to extending the interval. Diesel Generator and Emergency Service Water Automatic Actuation (ITS SR 3.7.3.2) HPCI System Cycle Operability Test (ITS SR 3.5.1.6) HPCI Logic System Functional Test (ITS SR 3.3.5.1.8) Safety and Relief Valve Setpoint Verification and Inspection Tests (3 tests)(ITS SR 3.4.3.1) The majority of problems associated with failures of the Diesel Generator and Emergency Senice Water automatic actuation are related to personnel or procedural errors. The single exception was a failure in a diesel generator output breaker. The failures associated with the HPCI logic system ftmetional test include the failure of the turbine control valve to open due to the failure of a newly installed relay, the failure of a pump suction motor-operated valve to cycle (the valve is routinely cycled by the IST Program and would have been detected at another time), and the failure of the turbine stop valve to close due to a sticking limit switch. The failures associated with the HPCI System cycle operability test were mainly associated with the inability to reach rated flow within the specified tima of 30 seconds. In each case, the system responded within the analyzed 45 seconds. These and 'he other failures associated with this test would have been identified during the performance of similar quarterly testing. The failures associated with the SRV setpoint verification and inspection tests include DAEC 31 Revision I l
DISCUSSION OF CliANGES ITS 3.3.6.1: PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION DAEC 32 RevisionI l l
DISCUSSION OF CIIANGES ITS 3.3.6.1: PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION TECIINICAL CI1ANGES - 1.ESS RESTRICTIVE (continued) Lev.2 numerous instances of as-found valves lifting more than 1% below the specified (cont.) setpoint and a single failure of an SRV being above the 1% setpoint tolerance (see ITS change in setpoint tolerance from -l% to -3%). For each of these tests, the nature of the failures, corrective actions that were ' taken, system redundancy, or detectability of the f.,hes by other mid-cycle testing resulted in acceptable conditions for interval extension. The equipment performance supports interval extensions from 18 to 24 months, with a maximum proposed interval of 30 months in each case. {3.3.6.1-7} l s DAEC 33 RevisionI l l
DISCUSSION OF CIIANGES TO NUREG-1433 SECTION 3.3 --INSTRUMENTATION PLANT SPECIFIC ClIANGES Pi The Frequency has been modified to be consistent with the DAEC current licensing bash:. Plant operating experience has shown that the proposed Frequency is acceptable. P2 ITS SR 3.3.1.1.11, which is a 92 day Channel Calibration, has been added for Function 3, Reactor Vessel Steam Dome Pressure - High. The addition of this Surveillance is based on DAEC plant specific design, operating history, and setpoint analysis. The NUREG allows an 18 month Frequency. P3 This change deletes NURE9 SR 3.3.1.1.14. This SR is specific to plants with the APRM Flow Biased Simulated Thermal Power - liigh Function. The DAEC design does not include this specific Function. P4 The Note to the SRs in NUREG 3.3.4.2, allowing a delay of up to 6 hours to perform surveillances without entering Required Actions and Conditions, has been deleted. Only one trip system for ATWS RPT is required to be Operable in ITS 3.3.4.2 in accordance with CTS provisions. Since only one trip system is required, when a channel is inoperable for testing, the associated Function will not maintain ATSW-RPT trip capability. Therefore, entering the Required Actions and Conditions is appropriate. P5 The Frequency of 7 days in NUREG SR 3.3.1.1.3 (ITS SR 3.3.1.1.17) for the APRM Flow Biased liigh Function has been revised to 24 months. The CTS requires performance of this SR on a Refueling Frequency which is currently 18 months. A 24 month operating cycle has been proposed and justification provided as part of this DAEC ITS conversion. DAEC 1 Revision I l 1
DISCUSSION OF CHANGES TO NUREG-1433 SECTION 3.3 -- INSTRUhiENTATION PLANT SPECIFIC Cll ANGES (continued) Ps in the DAEC CTS there are two types of RPS Response Times. One is described in CTS 3.1.A as the time from opening of the sensor contact up to and including the opening of the trip actuator contacts. This response time does not include the time interval from when the monitored parameter exceeds its trip setpoint to the sensor output contact. This CTS test only measures the response time of the RPS logic with an acceptance criteria of s 50 milliseconds. His CTS test is ITS SR 3.3.1.1.19. The second type of RPS Response Time in the CTS is described in CTS Definition 29 as the Reactor Trip System Response Time. This response time is measured from when the monitored parameter exceeds its trip setpoint at the channel sensor until deengerization of the scram pilot valve solenoids. This CTS test is the RPS nesponse Time test in ITS SR 3.3.1.1.18. The CTS RPS logic system response time test in SR 3.3.1.1.19 is rcquired to be 1 performed on all RPS Functions except the Reactor hiode Switch - Shutdown Position and the Manual Scram. This is the present interpretation of CTS requirements for the following reasons: 1) for this response time test the CTS excludes the sensor, which in these cases would be the Manual Scram buttons and the Reactor hiode switch and; 2) these devices directly trip their scram solenoid relays such that there are no intervening devices to response time test. The frequency of 24 months on a Staggered Test Basis is applicable to both SR 3.3.1.1.19 and SR 3.3.1.1.18 as allowed by CTS 4.1.A.2. The RPS Response Time Test of CTS Definition 29 and ITS SR 3.3.1.1,18 are only required to be performed on the two RPS Functions listed on CTS Table 3.1-2 as stated in CTS 3.1.A. These RPS Functions are Reactor Vessel Steam Dome Pressure - Iligh and Reactor Vessel Water Level - Low. The Notes in NUREG SR 3.3.1.1.19 are not needed in ITS SR 3.3.1.1.18 since the two affected RPS Functions do not have neutron detectors and the second note only applies to the Main Steam Isolation Valve - Closure Function. DAEC 2 RevisionI l
DISCUSSION OF CilANGES TO NUREG-1433 SECTION 3.3 -INSTRUMENTATION PL ANT SPECIFIC CIlANGES (continued) P7 Ad!usting APRM gain is the simplest and most timely way oflowering the APRM Flow Biased Scram setpoint and Rod Block setpoint when entering single recirculation loop operation (SLO). Current operating practice is to use gain adjust when first entering SLO to allow time for troubleshooting and retuming to two recirculation loop operation. If troubleshooting indicates the plant can not be retumed to two loop operation in a timely manner, the APRMs are recalibrated to lower the setpoint by 3.5%. Currently, a 72 hour limit has been arbitrarily chosen to give enough time for troubleshooting but limit the time Operators must be adjusting gains. Ilowever, recent troubleshooting efforts have shown that 72 hours is not always long enough to determine if the plant will be required to remain in SLO for an extended period of time or retum to two loop operation. For this reason, the ITS will continue to allow using the gain adjust method when entering SLO but the time limit will be controlled procedurally and evaluated in accordance with the DAEC 10 CFR 50.59 program. His practice has been previously reviewed by the NRC. In the DAEC response for additional information for the DAEC SLO Technical Specification Amendment APRM gain adjust was identified as the method to be used to implement the reduction in Flow Biased Scram and !bd Block setpoints. Subsequently, CTS Amendment i19 was approved. P At DAEC, the SRM count rate is required to be 2 3.0 cps. The signal to noise ratios of 2:1 or 20:1 are not used. Po The DAEC plant specific title /name, terminology, plant specific numbers or plant specific surveillances were incorporated into this requirement. This change is based on the DAEC plant specific design and analysis. DAEC 3 RevisionI l
;e DISCUSSION OF CliANGES TO NUREG 1433 -
SECTION 3.3 -INSTRUMENTATION PLANT SPECIFIC CHANGES (continued) Pm The Allowable Values for the RBM trips and Analytical Limits for the ; corresponding applicable power levels were taken from NEDC-30813-P," Average Power Range Monitor, Rod Block Monitor and Technical Specificetion improvement (ARTS) Program for the Duane Amold Energy Center," December 1984. NEDC-30813-P does not require an Allowable Value for the RBM Downscale Trip Function. The CTS contains the Trip Setpoint for the RBM Downscale Function which is being relocated to plant contrciled documents. Pn NUREG SR 3.3.2.1.5 verifies the RWM is not bypassed when Thermal Power is s [10]% RTP. This SR is being deleted since the DAEC does not have this design feature. The RWM has been modified at the DAEC so that it controls rod pattems over the entire operating range, up to 100% RTP. Pa The DAEC design for ECCS Instrumentation includes LPCI Loop Select Logic. These Functions (2.g-2.i) including Actions and Surveillances have been added to ITS 3.3.5.1. In addition, Function 2.k,4.16 kV Emergency Bus Sequential Loading Relay has been added to ITS 3.3.5.1, as its safety function is to protect the Low Pressure ECCS pumps from starting with insufficient bus voltage. The required Actions and Surveillances to support this function are included. Pn The proposed change to the NUREG will delete the following ECCS Instrumentation Functions on Tekle 3.3.5.1-1:
- 1. Fui.ction 1.e - Core Spray System - Manual Initiation.
- 2. Function 2.d - LPCI - Reactor Steam Dome Pressure - Low (Recirculation Discharge Valve Permissive) and (c) Footnote.
- 3. Function 2.h - LPCI - Manual Initiation.
- 4. Function 3.g - HPCI - Manual Initiation.
- 5. Functions 4.b and 5.b - ADS - Drywell Pressure - Iligh.
- 6. Functions 4.g and 5.g - ADS - Low Water Level Actuation Timer.
- 7. Functions 4.h and 5.h - ADS - Manual Initiation.
These ECCS Functions are not included in the DAEC design. Table 3.3.5.1-1 Function numbering is revised to reflect the above deletions. DAEC 4 Revision 1 l
DISCUSSION OF CilANGES TO NUIEG 1433 SECTION 3.3 - INSTRUMENTATION PLANT SPECIFIC Cll ANGES (continued) Pu This change proposes to add two new Functions to 'luble 3.3.5.1-1, ECCS Instrumentation. Function 1.e, Core Spray Pump Start Time Delay Relay is specific to the DAEC design and is analogous to NUREO Function 2.f(ITS 2.e) for the LPCI system. Fonction 1.f,4.16 kV Emergency Bus Sequential Loading Relay has also been added to ITS 3.3.5.1, as its safety function is to protect the Low Pressure ECCS pumps from starting with insufficient bus voltage. The required Actions and i Stuveillances to support these Functions have bnen included. Pn The NUREG Required Actions B.1, C.1, and E.1 apply to the CS and LPCI Functions and requires declaring supported features inoperable when its r.:dundant
- feature ECCS initiation capability is inoperable. At DAEC, the low pressure ECCS has two CS subsystems and LPC' system that are " redundant" ta each other. (The LPCI System (all 4 pumps) constitutes one system due to LPCI Loop Select Logic design). The proposed change to the Completion Time wording of Required Actions B.1, C.1, and E.1 ensures that all required supported features of the redundant systems (whether CS or LPCI) are declared inoperable within one hour of discovery of the Condition.
Pa The change proposes to delete the Note in Acti an G.1 of LCO 3.3.5.1. The Note is no longer needed since the Action is applicable to all the Functions that reference it. Pn NUREG .1.3.5.1 contains only a 12 hour Channel Check (SR 3.3.5.1.1); u 92 day Channel Functional Test (SR 3.3.5.1.2); and, a 92 day and 18 inonth Channel Calibration (SR 3.3.5.1.4 and 3.3.5.1.5, respectively). Based upon DAEC plant specific design, operating history, and setpoint analysis for ECCS Functions, the l DAEC ITS requires a 24 hour Channel Check (17 SR 3.3.5.1.1); and, an 5 additional 31 day and a 12. month Channel Funcuonal Test (ITS 3.3.5.1.2 and 3.3.5.1.5, respectively); and,12 month and 24 month Channel Calibration (ITS SR 3.3.5.1.6 and 3.3.5.1.8, respectively). Pa Based on discussions with the NRC Staff on January 14,1998, this change has been whndrawn. (3.3.5.1 1,3.3.5.2-11 DAEC 5 RevisionI l
DISCUSSION OF CllANGES TO NUREG-1433 SECTION 3.3 --INSTRUMENTATION PldNT SPECIFIC CIIANGES (continued) Pn Response time testing (R1T) is not required in tb C'fS for ECCS or Isolation Instrumentation. Generic studies (EPRI Study, NP-7243," Investigation of Response Time l esting Requirements," May,1991.) show that response time changes (times increasing) that could impact safety do not iiormally vary such that they would not be detected during other required surveillances (e.g., Channel Calibrations). Since the addition of these tests is a major burden to DAEC, with little gain in safety, the SRs associated with these terts have not been added for any tests associated with instrumentation. P3 The DAEC design does not include PSW T/B isolation valves. Therefore, this bracketed requirement has been deleted. P:2 ITS Table 3.3.5.1-1 Footnote (b), which states "Also required to initiate the associated DG," has been deleted from the LPCI Reactor Vessel Water Level - Ltw Low Low and Drywell Pressure - liigh Functions (Functions 2.a and 2.b). At DAEC, the Diesel Ge.; rators (DGs) are initiated from the Core Spray (CS) System initiation logic. The CS and LPCI Reactor Vessel Water Level - Low Low Low and Drywell Pressure - liigh Functions are derived from the same instrumentation. Ilowever, any inoperability of the LPCI Reactor Vessel Water Level - Low Low Low or Drywell Pressure - liigh Function that could negatively impact DG initiation will also result in the CS Reactor Vec el Water Level - Low Low Low or Drywell Pressure - liigh Function being inoperable. Accordingly, the CS Reactor Vessel Water Level - Low Low Low and Drywell Pressure - liigh Functions will still include Footnote (b). Therefore, this change has no impact on DG initiation capability and is being made for consistency with the DAEC design. Corresponding changes have also been made to the associated Bases. Pu His proposed change adds a Footnote (d) to the ADS Functions in Table 3.3.5.1-1. Footnote (d) reflects the Applicability of the ADS System in Modd and 3 when n: actor steam dome pressure is > 100 psig. This change is based on the DAEC plant specific design. Pu The NUREG SRs that require a calibration of the trip units every 92 days have been deleted For these instrumentation functions at DAEC, the instrument loops consist of relays or on-off sensors and do not include trip units. DAEC 6 RevisionI l
DISC _'SSION OF CilANGES TO NUREG-1433 SECTION 3.3 --INSTRUMENTATION PLANT SPEC,lFIC C11ANGES (continued) l Pu This change proposes to delete the RCIC Suppression Pool Water -liigh and Manual Initiation Functiona from Table 3.3.5.2-1. These Functions . not design features at DAEC and thus are not applicable. This change is based on the plant specific difTerences between DAEC and NUREG 1433. P 25 Function 7.a Containment Cooling System Isolation - Containment Pressure - liigh has been added to the DAEC ITS. This Function is in CTS Table 3.2-B as Core and Containment Cooling Systems initiation / Control Instrumentation. This Contairunent Pressure - liigh signal will provide a permissive (as long as Reactor Water Level is above 2/3 Core lleight and a LPCI initiation signal is present) to open the Containment Cooling isolation valves. Actions, Applicability, Required Channels per Trip System and SRs have also been added. P6 NUREG 3.3.6.1 contains only a 12 hour Channel Check (SR 3.3.6.1.1); a 92 day and 184 day Channel Functional Test (SR 3.3.6.1.2 and 3.3.6.1.5, respecuvely); and a 92 day and 18 month Channel Calibration (SR 3.3.6.1.4 and 3.3.6.1.6, respectively). Based upon DAEC plant specific design, operating history, and etpoint analysis for PCIS Functions, the DAEC ITS requires an additional 24 hour Channel Check (ITS SR 3.3.6.1.2); a 31 day and 24 month Channel Functional Test (ITS 3.3.6.1.3 and 3.3.6.1.10 respectively); and,184 day,12 month and 24 month Channel Calibrations (ITS SR 3.3.6.1.6,3.3.6.1.7an.1 3.3.6.1.8, respectively). {3.3.6.1-2 and 3.3.6.1-16} P,2 The proposed change to the NUREG will delete the following Primary Containment Isolation instrumentation Functions on Table 3.3.6.1-1:
- 1. Function 1.h - Main Steam Line Isolation - Manual Initiation.
- 2. Function 2.f- Primary Containment Isolation - Manual Initiation.
- 3. Function 3.e - liPCI System Isolation - IIPCi Pipe Penetration Room Temperature - liigit
- 4. Function 3.i - IIPCI System Isolation - Eme, gency Area Cooler Temperature - liigh.
S. Function 4.h - RCIC System isolation - Emergency Area Cooler Temperature - liigh.
- 6. Function 5.f- RWCU System isolation - Manual Initiation.
DAEC 7 Revision 1 l
DISCUSSION OF CllANGES TO NUREG 1433 SECTION 3.3 --INSTRUMENTATION PLANT SPECIFIC ClI ANGES (continued) Pn Rese Isolation Functions are not in the DAEC design. Table 3.3.6-1 Function (cont.) numbering is revised to reflect the above deletions. P:s ITS 3.3.6.2 Required Action A.! specifies placing the inoperable channel in trip in 12 hours for Function 1 (Reactor Vessel Water Level - Low) and Function 2 (Drywe , Pressure-liigh) and 24 hours for Function 3 (Reactor Building Exhaust Shall n.gh Radiation) and Function 4 (Refueling Floor Exhaust Duct - liigh Radiation). The 12 hour allowable out of senice time was determined to be acceptable for PCIS channels common to RPS in NEDC-30851P-A Supplement 2,
" Technical Specifications improvement Analysis for BWR isolation Instrumentation Common to RPS and ECCS Instmmentation," dated March,1989.
Table 3.3.6.2-1 Functions I and 2 are common to RPS and as a result are provided with a 12 hour allowable out of service time. The 24 hour allowable out of senice time was detennined to be acceptable for PCIS channels not common to RPS in NEDC 31677P-A, July,1990," Technical Specification improvement Analysis for BWR isolation Actuation Instmmentation." Functions 3 and 4 are not common to RPS and as a result are provided with a 24 hour allowable out of senice time. Therefore, Completion Times for Required Action A.1 have been revised accordingly. P,2 The Manual Initiation Function for Secondary Containment Isolation Instrumentation in NUREG 3.3.6.2 has been deleted. The DAEC design does not include this feature. Consequently, Condition B was reworded, as all functions are automatic. Pa3 The change will make NUREG 3.3.2.1 Required Action D.1 wording match that for Required Action C.2.2. Pn The DAEC design includes three tailpipe pressure switches for each SRV. Each switch constitutes a channel for each SRV Two of the three channels are required to initiate a trip signal to LLS from a SRV. Tais DAEC design is reflected in ITS 3.3.6.3. {3.3.6.3-7} l DAEC 8 RevisionI l
DISCUSSION OF CilANGES TO NUREG 1433 SECTION 3.3 --INSTRUMENTATION P!, ANT SPECIFIC CllANGES (continued) P 32 ne Actions for NUREG 3.3.8.1 have been revised to reflect DAEC design. NUREG Action A applies to ITS Table 3.3.8.1-1 Functions 1 and 3, and separate Action has been written for Function 2. Function 2,4.16 kv Emergency Bus Undervoltage (Degraded Voltage) contains 4 channels per bus arranged in a one-out-of two taken twice logic. ITS Action B has been written to relax the requirements of Action A for Function 2 to reflect this logic arrangement. P 33 NUREG 3.3.7.1 has br r chaard to reflect DAEC design for the Main Control Room Standby Filter bnn (SFU) System Instnanentation. The DAEC SFU System contains two filter units with automatic initiation from only the Control Building Intake Area Radiation-liigh Function, consisting of two channels with one channel dedicated to each of the two SFU units. With only one trip Function for SFU initiation, NUREG Table 3.3.7.1-1 is not needed and the rec,uirements in the Table for this Function are moved to ITS 3.3.7.1. The changes to the Actions reflect DAEC design such that loss of a Control Building intake Area Radiation-High channel will remove the automatic initiation signal for its associated SFU. Therefore, the one hour Completion Time for declaring the associated SFU inoperable or placing the Control Building Ventilation System in the isola. ion mode is appropriate. P 34 For EOC-RPT System Response Time testing, the NUREG requires the determination of RPT breaker interruption time every 60 months. At the DAEC, this breaker are suppression time was validated once at initial breaker installation and is not periodically reverified. The CTS Definition for EOC RPT System Response Time is from actuation of either the Turbine Stop Valve poaition switch or Turbine Control Valve fast acting solenoid, to the actuation of the RPT breaker secondary (auxiliary) conta:ts, which does not include the are suppression time, ne NRC has approved this definition, inost recently in Amendment #216 to the CTS. Therefore, these NUREG provisions have been deleted as they are not consistent with the DAEC current licensing basis. DAEC 9 RevisionI l
, I
DISCUSSION OF CilANGES TO NUREG-1433 SECTION 3.3 -INSTRUhiENTATION PLANT SPECIFIC CliANGES (continued) Pu The Remote Shutdown System Instrumentation Table (Table 3.3.3.2-1) is proposed to be removed from the Technical Specifications and relocated the ITS Bases. This change is consistent with the provisions of Generic Letter 91-08 for the removal of lists and has been recently approved for Clinton Power Station (Amendment No.
- 68) on that basis. At DAEC, the Remote Shutdown System Table will be placed h the ITS Bases where changes are centrolled in accordance with the TS Bases Control Program.
P3 Based on discussionz with the NRC Staff on January 8,1998, this change has been withdrawn. {3.3.3.17} Pn The Post Accident hionitoring Functions in Table 3.3.3.1-1 have been changed to include the DAEC Regulatory Guide 1.97, Category I variables. The DAEC design does not :aclude any instmments that mon 90r any Type A variables. Pn NUREG 3.3.2.2,"Feedwater and hiain Turbine High Water Level Trip instrumentation,"is not included in the DAEC ITS. The DAEC design includes the reactor vessel high level trip Function, but the CTS does not contain this Function. The NRC issued an SER to the DAEC in a letter dated hiay 24,1994, that describes the NRC position for resolution of Generic Letter 89-19. In a response to this SER dated June 30,1994 (J. Franz to W. Russell), the DAEC concluded that the inclusion of this instrumentation in the CTS was not required because they do not 9:rve to protect any safety limits. At the DAEC, the turbine trip and feedwater pump trip on high level are provided for protection of the main turbine, not for protection of the hiCPR safety limits. I P3 Based on discussions with the NRC Staff on January 8,1998, this change has been withdrawn. {3.3.3.19) P. ITS Table 3.3.5.1-1 Functions 1.d,2.f, and 3.f have been revised to delete the Surveillance Requirement SR 3.3.5.1.1. These Functions deal with Core Spray, LPCI, and llPCI pump discharge flows - low. At DAEC, these Functions do not have two instruments available to compare to each other in the perfomlance of a Channel Check. These systems are normally in standby (not running) and therefore would be indicating zero. Thus, a Channel Check does not add any value and has not been included. DAEC 10 RevisionI l t
DISCUSSION OF C11ANGES TO NUREG 1433 SECTION 3.3 -INSTRUMENTATION PL ANT SPECIFIC ClIANGPS.(continued) i Pu NUREO SR 3.3.6.3.1, Low - Low Set (LLS) Instrumentation requires a Channel Check to be performed every 12 hours. NUREO 1.1 Definition, Channel Check stat.:s that this shall be the qualitative assessn.ent, by observation, of channel behavior duiing operation. This determination shall include, where possible, comparison of the channel indication and stetus to other indications or status derived from independent instrument channels measuring the same parameter. This SR is being deleted based on DAEC design and licensing bases. DAEC does not have other channels measuring or indicating the same parameter in order to make s ich a comparison. The only possible independent indication of LLS would be the LLS Logic status lights on panel 1C45. This would only indicate the status of the logie, not the parameter. NUREO SR 3.3.6.3.3 requires that a Channel Functional Test for portions of the channel inside primary containment be performed every 92 days. This SR is being ( deleted. A portion of the channels are located inside containment and thus not available for testing. DAEC current licensing bases does not require those portions of the channels inside containment to be tested since containment entry is not allowed during operation. TI':se instruments are currently calibrated and functionally tested every 18 months. The instruments have not failed a Channel Functional Test at this Frequency over the last 5 years. Based on this performance history, functional testing during forced outages would not provide any additional
.crety benefit and would just lengthen the forced outage unnecessarily.
Pu NUREG Table 3.3.6.1-1, Function 2.c for Drywell Radiation - lligh has been replaced with the CTS Table 3.2-A Function of Offgas Vent Stack - liigh Radiation. This CTS Function is required to isolate the primary containment vent and purge valves during venting or purging of primary comainment in Modes 1,2. and 3. The l CTS Actions, Applicability, setpoint determination method and Surveillance Requirements have been included in the ITS as described in the Discussions of Changes for ITS 3.3.6.1. {3.3.6.1-19} l Pu Based on discussions with the NRC Staff on ht.ary 14,1998, this change has been withdrawn. (3.3.6.1-7} DAEC 11 Revision 1 l
I DISCUSSION OF CllANGES TO NUREG-1433 SECTION 3.3 --INSTRUhlENTATION PLANT SPECIFIC CIIANGES (continued) Pu Per our conference call with the StafTon February 18,1998, the number cf required channels per trip system will be revised back to agree with the CTS requirement of one per trip system for each variable (i.e., RWCU liigh Area Temperature and liigh Area Differential Temperature) . Proper Spatial (i.e., area) coverage will be allowed to be controlled administratively outside the TS. Consequently, proposed footnote (d) will be deleted and subsequent footnotes (e) and (f) will be re-ordered to be (d) and (e), respectively. (3.3.6.1 1 } Pc Typographical error corrected. (CRF 9023) l Pu, The Applicability of NUREG 1433 Specification 3.3.8.2, RPS Electric Power Monitoring is revised to be consistent with the DAEC current licensing basis as described in NRC SER for Technical Specification Amendment 79. This SER states that the change (which added the RPS Electric Power Monitoring Specification to the DAEC Technical Specifications) is intended to ensure that the power produced by the RPS MG sets is of a quality acceptable to the RPS. As a result, the Applicability of the DAEC ITS 3.3.8.2 is revised to be consistent with the applicability of RPS Functions in ITS 3.3.1.1 (Modes 1 and 2, and Mode 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies) and Special Operations LCOs 3.10.3 and 3.10.4 (Modes 3 and 4 any control rod withdrawn from a core cell containing one or more fuel assemblies, respectively. Commensurate changes to the Actions section ofNUREG-1433 Specification 3.3.8.2 are also made to delete Required Actions C.2 D.2.1, and D.2.2. This reflects only the requirement of placing the plant in a Mode or specified condition outside the revh. a Applicability. The purpose of NUREG 3.3.8.2, Required Actions D.2.1 and D.2.2 were to provide protection and actions to restore the instrumentation isolation Functions powered from the RPS bus. The Note to SR 3.3.8.2.1 was also changed to reflect the change to the Applicability. At DAEC, the licensing basis and design basis for the EPAs is only to protect the RPS equipment powered from the RPS buses, not to protect all of the other equipmer,t or logic powered from the RPS buses. Since the EPA breakers are not required to be Operable to ensure that the RilR - Shutdown Cooling (SDC) valves can automatically close, no compensatory measures for them are required. DAEC 12 Revision 1 l
DISCUSSION OF C11ANGES TO NUREG-1433 SECTION 3.3 -- INSTRUMENTATION PLANT SPECIFIC Cll ANGES (continued) P.u, Therefore, Required Actions D.2.1 and D.2.2, which provide the Actions to restore (cont.) the instrumentation isolation capability or to isolate the R11R Shutdown Cooling, are not required. In the ITS. some RPS Functions are required to be Operable under certain conditions in Modes 3 and 4. A control rod may be withdrawn from a core cell containing one or more fuel assemblies in accordance with ITS Sp cial Operations LCO 3.10.3," Single Control Rod Withdrawal - llot Shutdown," and LCO 3.10.4," Single Control Rod Withdrawal - Cold Shutdown." Therefore, ITS 3.10.3 and 3.10.4 include requirements for RPS Functions to be Operable. As a result. NUREG-1433, LCO 3.10.3 and LCO 3.10.4 are modified to also ir.clude requirements for the RPS - EPAs to be Operable when the RPS Functions are required to be Operable. [CRF 9919] l Pu The time delay requirements in NUREG SR 3.3.8.2.2 setpoints b.,(undervoltage) and c. (underfrequency) have been deleted. The removal of the time delay settings from the CTS was approved in a NRC SER for Amendment No.185 for the DAEC CTS, dated August 4,1992, which relocated thes: requirements to the UFSAR. P: 4 NUREG 3.3.4.1 Applicability requires EOC-RPT to be Operable when > 30% RTP. This has been changed to be 2 30% RTP consistent with the NUREG Bases, NUREG SR 3.3.4.1.5 and CTS Table 3.2-G. Pa Note 2 to the Actions for NUREG 3.3.31 allows separate Condition entry for each PAM Function. The change will also allow separate Condition entry for each penetration flow path for the PCIV Position Function which matches the same allowance in NUREG 3.6.1.3 for PCIVs. This change is nccessary to clarify NUREG provisions and to avoid an unnecessary entry into LCO 3.0.3. NUREG 3.3.3.1 requires one channel of PCIV position indication in the control room to be Operable for each active PCIV in a containment penetration flow path. NUREG 3.3.3.1 Action A addresses the Condition where one channel is inoperable and Action C addresses the Condition where two channels of this Function are inoperable. If three or more penetrations contain one inoperable PCIV position channel (or if any three or more channels are inoperable), the NUREG does not address this Condition and LCO 3.0.3 would be entered. DAEC 13 RevisionI l
DISCUSSION OF CilANGES TO NUREG-1433 SECTION 3.3 --INSTRUMENTATION PLANT SPECIFIC CHANGES (continued) Po Similar to NUREG 3.6.1.3 for PCIVs, each penetration flow path should be (cont.) evaluated separately for Operability of the PAM Function. Current NUXREG Actions provide appropriate compensatory actions for each inoperable PCIV position indication channel. Po 3 NUREG 3.3.4.2 for ATWS-RPT requires two channels of each ATWS RPT Function to be Operable per trip system. The DAEC design for ATWS includes two instrumentation trip systems each consisting of two channels of each ATWS-RPT Function with each arranged in a two-out-of-two taken once logic. The DAEC design contains four breakers (two in series in each recirculation pump circuit) with one trip system feeding one breaker to e .ch pump and the other trip system, reparately feeding the other two breakers (one to each recirculation pump). Even though the DAEC design contains redundancy, this is not required by tia ATWS Rule or by the DAEC CTS. CTS Table 3.2-G Footnote (a) only requires one Operable trip system for each ATWS RPT Function. This allows both Operable functions to be in one trip system or one function to be Opeiable in one trip system and the other function to be Operable in the second trip system. The CTS ensures that both recirculation pumps will receive a trip signal from one trip system for ATWS-RPT. The CTS y allowances have been incorporated into LCO 3.3.4.2 by only requiring two channels in a trip system for each A'l WS-RPT instrumentation Function to be Operable. xConsequently, NUREG Action A has been deleted, as having one channel inoperable is the same as NUREG Condition B at the DAEC. CTS Table 3.2-G Action 80 requirements have been incorporated into ITS Action A (NUREG Action B) by only allowing a 72 hour Completion Time to restore ATWS-RPT trip capability when one Function is not maintaining trip capability. The CTS allows 72
- hours to restore channels if both ATWS-RPT Functions are inoperable. The more restrictive NUREG Action C Completion Time of I hour has been adopted in the ITS (Action B) when complete loss of ATWS-RPT Function has occurred. The ATWS-RPT requirements were added to the CTS by Amendment 151 and found acceptable by the NRC in the associated SER dated July 7,1988.
DAEC 14 RevisionI l
DISCUSSION OF CllANGES TO NUREG 1433 SECTION 3.3 --INSTRUMENTATION PLANT SPECIFIC CIIANGES (coruinued) P 3i ITS SR 3.3.4.2.1 is added to perform a Channel Check every 12 hours on the Reactor Vessel Water Level - Low Low Function for ATWS RPT. The DAEC design contains instrumentation in this Function that allows a Channel Check to be performed. The Function of Reactor Steam Dome Pressure - High is taken f om pressure switches and does not have indication and thus a Channel Check is not practical. Pn These changes to the NUREG represent editorial changes that t.se being made for clarity, consistency, and grammatical reasons. Renumberir.g has been done due to additions / deletions or Frequency changes. Pu NUREG 3.3.1.1 Required Action F.1, NUREG 3.3.4.2 Required Action D.2 (ITS C.2) and NUREG 3.3.6.1 Required Action E.1 require the plant to be in Mode 2 in 6 hours. The intent of the NUREG is to perform a controlled thutdown. Experience at the DAEC has shown that six hours is not enough time to perform this controlled shutdown and reach Mode 2 in the allowed six hours. Review of three controlled plant shutdowns in (1993 and 1994) indicctes that between seven and eight hours are required even without performing the RWM SR (which would add
. approximately another 45 minutes). These DAEC shutdown times reflect the ability of the plant to reach approximately 5-10% RTP where a plant scram is manually inserted as part of the shutdown rather than continuing to insert control rods. This change is reasonable based on plant operating experience and considering that the LCO 3.0.3 time of 13 hours to be in Modes 3 has not changed.
P 3., NUREG Table 3.3.1-1 contains an equation for the Allowable Value for the APRM Neutron Flux - Upscale (Flow Biased - High) for two loop operation of s (.58 W + 62%) and s (.58 W + 58.5%) for single loop operation. These equations are not being retained in the ITS. The ITS Allowable Values are calculated from these nominal trip setpoint straight line equations at discreet flow points. Because the instrument uncertainties are non-linear, the Allowable Values do not lie in a straight line and do not bnd themselves to being characterized by a simple equation. Consequently, the actual Allowable Values at these discreet flow points are provided. DAEC 15 RevisionI l
DISCUSSION OF CllANGES TO NUREG-1433 SECTION 3.3 -INSTRUMENTATION PLANT SPECIFIC CliANGES (continued) P 55 The lower limit for the Allowable Value (AV) for the Tailpipe liigh Pressure Function in Table 3.3.6.3-1 has been dcleted. The lower limit for this AV would serve to minimize the probability ofincorrectly indicating that a SRV is open when it is really closed; although undesirable, this is not a safety concern, as the other input to the arming logic (i.e., Reactor Steam Dome Pressure - liigh) must be satisfied, as well as having multiple Tailpipe High Pressure switches have their setpoints drift low, before an SRV would open. 1836 Although 'ne NUREG specifies only an upper limit for the LLS Pressure Setpoint Allowable Values listed in Table 3.3.6.3-1, both upper and lower limits for AVs specified in ITS Table 3.3.6.3 1. Specifying lower limits is necessary to ensure that the LLS valves perform their function satisfactorily (e.g., the lower limit ensures that the length of time between successive SRV openings is long enough to allow water to drain from the SRV tailpipe. I'57 Based on discussions with the NRC Staff on January 27,1998, this change has been withdrawn. The llPCI and RCIC ManualInitiation Functions have been added as Functions 3.j and 4.j, respectively. (3.3.6.1-16} Ps 3 NUREG SR 3.3.1.1.1 has been deleted for Table 3.3.1.1-1, Function 2c, APRM liigh Value Clamp; Function 3, Reactor Vessel Steam Dome Pressure - liigh; Function 6, Drywell Pressure-liigh; and Function 7a, SDV Water Level-High, Resistance Temperature Detector. The instruments that provide these functions at the DAEC do not have any direct indicauon making it impossible to compare them C to another instrument monitoring the same parameter. P, 3 NUREG 3.3.5.2 contains a 12 hour Channel Check (SR 3.3.5.2.1); and a 92 day and 18 month Channel Calibration (SR 3.3.5.2.4 and 3.3.5.2.5, respectively). Based upon DAEC plant specific design, operating history, and setpoint analysis for RCIC Functions, the DAEC ITS requires a 24 hour Channel Check (ITS SR 3.3.5.'.1); and a 12 month and 24 month Channel Calibration (ITS SR 3.3.5.2.3 and 3.3.5.2.4. respectively). DAEC 16 Fevisioni l
DISCUSSION OF CllANGES TO NUREG-1433 SECTION 3.3 --INSTRUMENTATION PLANT SPECIFIC CIIANGES (continued) P,,o N1 REG 3.3.6.1 uses Action D for Function 1.f Main Steam Line Radiation liigh. Action D requires the associated Main Steam Lines to be isolated in 12 hours or the plant to shutdown. At DAEC, Function 1.f does not close the MSIVs but isolates the MSL drains, recirculation sample valves, and the mechanical vacuum pump isolation valves. Therefore, NUREG 3.3.6.1 Action F is used for Function 1.f. l i Pu The Allowable Valve for the Control Building Intake Area Radiation-liigh Functior is actually 2200 mr/hr. ITS SR 3.3.7.1.3 uses an administrative limit of s 50 mr/hr l which represents the upper limit of the range of the detection instrument. Po CTS T;ble 3..:-A identifies the trip level setting for the RCIC and ilPCI Turbine Exhaust Diaphragm Pressure - liigh as s 10 psig. The Allowable Values for thesc Functions (ITS Table 3.3.6.1-1,3.c for IIPCI and 4.e for RCIC) in the DAEC ITS are 2 2.5 psig for liPCI and 2 3.3 psig for RCIC. These isolations are for equipment and personnel protection only and are not assumed in any transient or accident analysis in the UFSAR. These instruments are included in the TS, because of the potential for risk due to possible failure of the instnunents preventing liPCI and RCIC initiations per NEDO 31466," Technical Specification Screening Criteria Application and Risk Assessment," November,1987. While the Allowable Values established in the DAEC ITS are high enough to prevent ::purious isolation of the 1IPCI or RCIC Systems, they are actually set low enough to preclude extended operation with a degraded inner diaphragm, leaving only the cuter diaphragm as the system pressure boundary. Pg Per our Response to the Staff's RAI on this Note (Ref. NG-97-1597) and our meeting with the Staffon September 9,1997, this change has been withdrawn. {3.3.1.1-27,3.3.5.2-6, and 3.3.6.1-10} Ps A new SR (ITS 3.3.1.1.3) has been added for the functional testing of the scram contactors on a weekly basis. The generic model used in the BWR Owners' Group Licensing Topical Report on RPS,(NEDE-30851P-A," Technical Specification Improvement Analyses for BWR Reactor Protection System," March,1998), used the plant design which has four Manual Scram pushbuttons, one for each channel l of RPS, which are connected to the same scram contactors as the automatic RPS trips. The DAEC design only has two Manual Scram pushbuttons, which are connected to a separate logic string from the autcmatic trips. DAEC 17 RevisionI l l
DISCUSSION OF CilANGES TO NUREG-1433 SECrlON 3.3 --INSTRUMENTATION PLANT SPECIFIC CllANGES (continued) Pu Thus, to nsure that the automatic scram contactors are exercised weekly, in (cont.) accordance wnh the conclusions of NEDE-30851P A, the DAEC uses the RPS Test Switches, instead of the Manual Scram pushbuttons. In turn, the weekly test frequency for the Manual Scram pushbuttons is extended to quarterly (i.e.,92 days) to be consistent with the frequency for the testing of the automatic RPS trips. The NUREG has been revised accordingly. Pu Based on discussions with the NRC on January 27,1998, this change has been withdrawn. {3.3.6.1-16} P% Footnote (a) to Table 3.3.5.1 1 is being changed to specify that Functions associated with footnote (a) are required to be OPERABLE only when associated subsystems are required to be OPERABLE per LCO 3.5.2. This change clarifies the requirement to have the Reactor Water Level, Low, Low, Low-Level 1 instrumentation OPERABLE in MODE 5 Mth RPV Level;t 21 feet 1 inch above the RPV flange to support EDG OPERABILITY. This change will only require this Function to be OPERABLE when the asweiated ECs ' is required to be OPERABLE per LCO 3.5.2. Consistent with the OPERABILITY requirements in LCO 3.5.2, ECCS is not required to be OPERABLE when the plant is at high water level. If ECCS is not required, tnen the instrument whose function is to initiate ECCS should not be required. This change is consistent with BWROO-34. [CRF 9014] Po The CTS Completion Time of 7 days to restore one inoperable Hydrogen or Oxygen Analyzer to Operable status when two are inoperable has been reta:ned in Condition C. To reflect this change, the Note to Condition C stating its nonapplicability to hydrogen monitor channels has been deleted, NUREG Condition D has been deleted, and subsequent Actions have been renumbered. {3.3.3.1-7} DAEC 18 Revision! l
DISCUSSION OF CilANGES TO NUREG-1433 BASES SECTION 3.3 --INSTRUMENTATION PLANT SPECIFIC CilANGES Pi nese changes reflect the DAEC specific design, analyses, licensing bases, and/or nomenclature. P These references have been revised and renumbered to reflect the appropriate plant specific DAEC references. Also, the temi FSAR has been changed to UFSAR to be consistent with DAEC terminology. P3 This change was made to be consistent with changes made to the DAEC Specifications. P4 The pu tion of this paragraph which is referenced LCO 3.2.4 " Average Power Range M*mitor (APRM) Gain and Setpoints," will be deleted because this section was not included in the DAEC ITS. In its place is added a description of LCO 3.4.1," Recirculation Loops Operating." P5 Plant specific rswording, additional information/ detail, grammatical, and/or punctuation changes were made to improve the clarity and readability of the Bases. P6 . Changed all references to "the NRC Policy Statement," to its associated Section in 10 CFR 50.36. Added reference to Criterion 4. P7 This table has been deleted since it provides generic and not plant specific types of information. This information in the Table would be misleading as to which plant specific analyses takes credit for these channels to perform a function during accident and transient scenarios. Ps Table B 3.3.3.2-1 listing the required Remote Shutdown System instrumentation was added to the Remote Shutdown System Bases since this provides an appropriately controlled location for this information. P, NUREG Bases 3.3.6.2 Background Section assumes a SGT System drawdown time for secondary containment. The SGT System drawdown test was deleted in NUREG SR 3.6.4.1.4 and reference to a time limit for drawdown in NUREG Bases 3.3.6.2 is also being deleted. The DAEC accident ralves do not require secondary containment drawdown within a given time periou . nigate the consequences of any accident. DAEC 1 RevisionI l J
DISCUSSION OF CilANGES TO NUREG-1433 DASES SECTION 3.3 -INSTRUh1ENTATION Pl ANT SPECIFIC CllANGES (continued) Pm The contents of the PAhi Report are being deleted here since they are detailed tu ITS 5.6.6 "PAhi Report." The report is required to be done in accordance with specification 5.6.6 and therefore does not have to be repeated. Pu The BASES for the ECCS Pump Discharge Pressure - liigh for Ftmetions 4.d,4.e, 5.d and 5.e (ADS Logics "A" and "B", respectively) has been modified to explain that the Allowable Value is based on one pump operating in the minimum flow bypass mode, rather than one pump operating at full flew. This is acceptable since accidents are assumed to not occur when low pressure ECCS subsystems are operating i . modes other than standby readiness, and since the time required for a system to realign from a secondary mode to the minimum flow bypass mode will not ex'end the time required for ADS actuation. Fu ne Bases for Functions 8 and 9 are being changed to eliminate the unnecessary restriction N NUIEG-1433 which requires these Functions to be declared inoperable to perform monthly Turbine Bypass Valve testing required by SR 3.7.7.1. This change is acceptable, because the trip Functions would only be disabled, and therefore rendered inope:able, if sufficient steam was bypassed to result in a lower turbine first stage pressure and the actual bypassing of the trip Functions occur. At power levels greater than 30% RTP, the affect of opening a single Turbine Bypass valve will not necessarily result in a bypassing of the trip functions. By defining the OPERABILITY rquirement as simply requiring the Turbine Bypass valves to be closed, this unnecessarily requires the trip Functions to be declared inoperable during required TS Testing. Furthermore, if the Functions are bypassed, an alarm in the control room will identify the condition to control room operators identifying the functions were inappropriately bypassed and the revised TS Bases will require the Functions to be declared inoperable. Therefore. this change will maintain the requirement for OPERABILITY of the trip Functions and remove the need to unnecessarily declare the Functions inoperable. This change is being made in accordance with letter NG-97-1597, dated September 5, 1997 and BWROG-39. {3.7.7-2} r DAEC 2 Revision 1 l
DISCUSSION OF CilANGES TO NUREG 1433 BASES SECTION 3.3 -- INSTRUMENTATION Pl ANT SPECIFIC CHANGES (continued) Po The Bases for ITS 3.3.5.1,3.3.5.2 and 3.3.6.1 have been modified to explain that i: is acceptable to leave the blocking device used to prevent trip actuation (e.g., jumpers, lifled leads, relay blocks, etc.) in place between consecutive sun cillance tests on channels in-series in the same trip logic, provided the allowed outage time (A0T) is not exceeded for each instmment channel. This is acceptable, as the topical reports on which the AOT allowances are based, made no assumptions regarding the elapsed time between individual channel tests. In addition, leaving the blocking device in place reduces the probability of a test-caused error due to the removal and immediate re installation of the blocking device sole'y for the purpose of staning and s apping of the AOT " clock." As this is not the intent of the AOT limit .'i is acceptable to keep track of the time a channel is in test by administrative means only. {3.3.5.1-1,3.3.5.2-1 and 3.3.6.17} Pa Per discussions with the NRC on Febmary 11,1998, this clarification of the requirements for performance of Channel Functional Testing is being added to the Bases in lieu of the changes to the Definition of Channel Functional Test proposed by rejected TSTF-64 and TSTF-205. [CRF 9916] DAEC 3 RevisionI l
NO SIGNIFICANT llAZARDS CONSIDERATIONS CilAPTER 3.3-INSTRUMENTATION TECilNICAL CllANGES - 1.ESS RESTRICTIVE (continued) (L, Labeled Comment / Discussion for ITS 3.3.6.1) DAEC has evaluated this proposed CTS change and has determined that it involves no significant hazards consideration. His determination has been performed in accordance with the criteria set forth in 10 CFR 50.92. The following evaluation is provided for the three categories of the significant hazards consideration standards:
- 1. Does the change involve a significant increase in the prol rJlity or consequences of an accident previously evaluated?
The proposed change will delete the requirement for the CTS isolation Signal of Offgas Vent Stack - liigh Radiation to have Surveillance Requirements (SRs) performed in conditions or Modes other than when venting or purging the primary cor.tainment at any time when primary containment integrity is required (i.e., in Modes 1,2, and 3 per DOC A.10). He Operability of the Isolation Function of Offgas Vent Stack - liigh Radiation in conditions or Mod:s other than when venting or purging the primary containment has not been identified as an initiator for any previously analyzed accidents. Therefore, this change does not significantly increase the probability of a previously analyzed accident. CTS Table 3.2-A only requires Operability of this Function when venting or purging the primary containment at any time when primary containment is required (i.e., in Modes 1,2, and 3 per DOC A.10). CTS Table 4.2-A incorrectly requires this isolation Function to have SRs perfonned in Modes 1,2,3 and when handling irradiated fuel in the secondary containment, during Core Alterations, and Operations with a Potential for Draining the Reactor Vessel (OPDRVs). The OfTgas Vent Stack - High Radiation isolation Function is only 1 :redit for in the accident analyses for closing the primary containment vent and purge ! .s when primary containmen!!megrity is required. This change maintains the analysis assumptions for Operability of the isolation function. Therefore, this change does not significantly increase the consequences of a previously analyzed accident. DAEC 112 Revision I l
NO SIGNIFICANT llAZARDS CONSIDERATIONS CliAPTER 3.3--INSTRUMENTATION TECilNICAL C11ANGES - LESS RESTRICTIVE (14 Labeled Comment / Discussion for ITS 3.3.6.1) (continued)
- 2. Does the change create the possibility of a new or different kind of accident from any accident previously evaluated? s The proposed change introduces no new mode of plant operation and does not involve physical modification to the plant. Therefore it does not create the possibility of a new or different kind of accident from any accident previously evaluated.
- 3. Does this change involve a significant reduction in a margin of safety?
This change corrects an inconsistency in the CTS. CTS Table 3.2 A requires Operability of the isolation Function of OITgas Vent Stack - liigh Radiation when venting or purging the primary containment at any time when primary contairunent is required (i.e., in Modes 1,2, and 3 per DOC A.10). CTS Table 4.2 A requires SRs for this Function to be performed in Modes 1,2,3 and when handling irradiated fuel in the secondary containment, during Core Alterations, and OPDRVs. CTS Table 4.2-A is being corrected in the ITS by only requiring the SRs to be performed when venting or purging the primary containment in Modes 1,2, and 3. The Offgas Vent Stack - liigh Radiation Function is only assumed to provide an isolation signal to the primary containment vent and purge valves and is not assumed to isolate secondary containment or to start the Standby Gas Treatment System. 'Iherefore, this change does not involve a significant reduction in a margin of safety (3.3.6.1-19). l DAEC 113 Revision I l
4 DISCUSSION OF CIIANGES TO NUREG-1433 BASES SECTION 3.4 - REACTOR COOLANT SYSTEM Pl. ANT SPECIFIC C11ANGES Pi The Bases have been revised for consistency with the Specification. P2 References and their associated numbering have been revised to reflect DAEC specific information and nomenclature. P3 The Bt.ses have been revised to reflect the DAEC specific design, analysis and nomenclature. P4 D AEC was not licensed to the GDC's. Ilowever, the DAEC has been evaluated to show the intent of each GDC is substantially met. The appropriate UFSAR Section that docunients these evaluations is referenced in place of the GDC itself. P3 'Ihe Basec for RCS PlV Leakage have been deleted since the Specification is not applicable to DAEC. The Discussio.: of Changes for NUREG 3.4.5 contains the , reasons for this change. The subsequent Bases have been renumbered due to this deletion. P6 DAEC is not committed to Regulatory Guide 1.45 for determining acceptable methods for selecting leakage detection systems. P7 The proper 10 CFR reference for the criterion has been used. The current wording was developed prior to the issuance of the Final Rule and referred to the NRC Policy Statement. P The discharge of the SRVs are hard piped to the Suppression Pool. Weepage past the SRVs collects in the Suppression Pool and not in an area monitored by the Drywell Sump System e the Primary Containment Air Sampling System. Therefore, SRV v s.7mge is not considered in the RCS Leakage limits. This is consistent with the "Y:C current licensing basis.
/ P, The CTS Bases for RCS Coolant Leakage 3.6.C/4.6.C explains that once Leakage is attributed to a specific source, that it can be considered as identified and applied against the identified limit. This clarification has been retained in the ITS Bases and is consistent with the DAEC current licensing basis.
DAEC 1 Revision I
DISCUSSION OF CilANGES TO NUREG 1433 BASES SECTION 3.4 . - REACTOR COOLANT SYSTEM Pl. ANT SPECIFIC ClI ANGES (continued) Pm ne ITS Bases for RIIR Shutdown Co.,ang indicate that losses to ambient can be considered as, or contributing to, the altemate method capabilit' . He change adds a description of how losses to ambient can fulfill the altemate decay heat removal capability. Pn Clarification was added to SR 3.4.2.1 to ensure that the intent of the CTS is maintained. Successful completion of SR 3.4.2.1 criterion a removes the need to perform criterion b. Information was added to explain Note 3 to the SR and how it affects criteria a and b consistent with the changes made to the specification. Pn The Bases is revised to more accurately reflect the contributors to RCS Specific Activity during normal plant operations. " Tramp" uranium on the outside of the fuel cladding and activation of corrosion products in the reactor coolant are the main contributors. Fuel leaks are potential contributors but are less likely, and if they do occur will cause large spikes in RCS Specific Activity levels. Po The Bases have been clarified to allow the saturation temperature corresponding to reactor steam dome pressure to be an acceptable method of measuring RPV coolant temperature. Pu The NUREG 3.4.4 Bases for Actions B.1 and B.2 implies that certain susceptible components must be determined not to be the source of LEAKAGE. Since that option (B.2) is required only if Actio i B.1 is not taken, the word "must" is misleading. The ITS Bases for Actions B.1 and B.2 have been revised to reflect that the determination of susceptible components is an option rather than a requ' nent. This is consistent with the intent of the NUREG. Pu Bases revised for enhanced clarity. Grammatical and editorial changes were also made. Pn, Change the reference for the Frequency of SR 3.4.3.2 for ASME Section XI to NUREG 1482 as this reference better addresses the 24 month Frequency. Added NUREG 1482 to Reference Section as item 4. DAEC 2 Revision 1 (
DISCUSSION OF CliANGES TO NUREG-1433 UASES SECTION 3.4 -- REACTOR COOLANT SYSTEM Pl. ANT SPECIFIC CilANGES (continued) l'i7 The Bases for this supported system have been changed to include a discussion of the necessary support features (e.g., Emergency Service Water, River Water Supply, etc.) that are required to support Operability of the supported systems in Modes 4 ands. Pn i Per discussions with the NRC on February 11,1998, this clarification of the requirements for performance of Channel Functional Testing is being added to the Dm .n lieu of the changes to the Definition of Channel Functional Test proposed i by rejected TSTF-64 and TSTF-205. [CRF 9916] I s DAEC 3 Revision i 1
DISCUSSION OF CilANGES ITS 3.6.2.4: RESIDUAL llEAT REMOVAL IUIR SUPPRESSION POOL COOLING ADMINISTRATIVE CIIANGES A All reformatting and renumbering is in accordance with the NUREG. As a result, the ITS should be nwre readable and more understandable by its users. The reformatting, renumbering, and rewording process involves no technical changes to the CTS. Editorial rewording (either adding or deleting) is made consistent with the NUREG. During NUREG development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the CTS. Additional information has also been added to more fully describe each subsection. This wording is consistent with the NUREG. Since the design is already approved by the NRC, adding more detail does not result in a technical change. {S3.6.2.4-11 A2 CTS 3/4.5.B is applicable to both the drywell and suppression poc! spray modes of RiiR. As the drywell spray mode is not being retained in the ITS (Ref. DOC R.1 for CTS 3/4.5.0), the CTS wording used to clarify the requirements, such as
" independent" and "cach spray type," are no longer required and are being deleted.
in addition, the CTS phrase " Containment Spray," which included both drywell and suppression pool sprays, is being revised to only refer to suppression pool spray. These changes to the CTS wording are administrative as to which mode of spray is being discussed. {S3.6.2.4-1 } A3 CTS 3.5.B.1 contains cross-references to other CTS specifications (3.5.B.2,3.5.B.3. These cross-referenced specifications refer to the Conditions, Required Actions and Completion Times within the same specification. This type of cross-reference is not needed in the NUREG format and therefore, is being deleted. This is considered to be an administrative change. (S3.6.2.4-1 } TECilNICAL CllANGES - MORE RESTRICTIVE Mi The CTS 3.5.B.i Applicability for the RIIR Suppression Pool Spray is "when reactor coolant temperature is rater than 212' F," whereas ITS 3.6.2.4 specifies Modes 1,2 and 3. The CTS anu ITS Applicabilities are equivalent for Modes 1 and
- 3. Ilowever, the CTS only requires Operability of the RHR Suppression Pool Spray in Mode 2 when greater than 212' F. Since the ITS requires Operability at all times in Mode 2, the proposed change is considered to be more restrictive. Current operating practice requires these systems (components) to be Operable prior to start-up, regardless of the mode being exited. {S3.6.2.4-1 }
DAEC 1 Revision 1 l
DISCUSSION OF CliANGES ITS 3.6.2.4: RESIDUAL IIEAT REMOVAL RiiR SUPPRESSION POOL COOLING TECIINICAL CIIANGES - RELOCATIONS None
- TECliNICAL CIIANGES - i ESS RESTRICTIVE None s
a DAEC 2 Revision 1 l
DISCUSSION OF CilANGES TO NUREG 1433 SECTION 3.6--CONTAINh1ENT SYSTEhis Pl. ANT SPECIFIC CliANGES Pi NUREG SR 3.6.1.2.1 has been revised to reflect DAEC Request for Technical Specification Change RTS-269 (NG-95-2985, dated Dec. 22,1995). P2 The Drywell Pressure LCO (NUREG 3.6.1.4) has been deleted. The NUREG LCO is based on the initial assumption of.75 psig in the safety analysis, and is required in hiodes 1,2, and 3. A recent O'd evaluation shows that an initial dowell pressure of 2.0 psig is acceptable for ensuring containment pressure design limits are not exceeded. This LCO is not needed since the RPS high drywell pressure scram will trip the unit prior to exceeding 2.0 psig, effectively placing the unit in hiode 3. While the RPS trip is not required in hiode 3, the DAEC Emergency Operating Procedures (EOPs) will govem actions if the drywell pressure exceeds 2.0 psig (effectively bounding the 2.0 psig limit). The EOPs will require entry into the RPV Control and Primary Containment Control actions. These actions require steps to be taken to reduce primary containment pressure to less than 2.0 psig and to cooldown the reactor at normal cooldown rates to hiode 4 if pressure cannot be reduced to less than 2.0 psig. P3 Conditions A and B contain in brackets, an exception for purge valve leakage not within limits. In addition to purge valve leakage, MSIV leakage is also added as an excep. ion to Conditions A and B. Changes to Condition D will replace secondary containment bypass leakage rate not within limits, with a requirement for one or more penetration flow paths with one or more htSIVs not within leakage limits. These changes are made to account for h1SIV leakage in addition to purge valve leakage, which is accounted for in Condition E. Secondary Containment bypass leakage is not in the DAEC current licensing basis. At DAEC leakage from hydrostatically tested lines is included in the Type C test total as required by CTS 4.7.A.l.c.4. (3.6.1.3-2) l DAEC 1 Revision I __,__m____._..-._-.._
DISCUSSION OF CllANGES TO NUREG 1433 SECTION 3.6--CONTAINhiENT SYSTEhis Pl. ANT SPECIFIC Cl!ANGES (continued) P4 The time tn *estore h1SIV leakage to within limits has been changed to 8 hours, consistent with the time to restore an inoperable MSIV (for icasons other than leakage)in Action A. Action A allows 8 hours to isolate the affected main steam line when an htSIV is inoperable due to a reason not involving leakage. This could ! include a MSIV that will not automatically isolate (which means it is essemially I fully open). Action D was modified to include h1SIV leakages (Generic Change BWR-15, C4), and it appears to not have fully been changed to allow the 8 hours in Action A, which is the Action that would have been entered for a leakage problem prior to the generic change. P3 At DAEC the containment purge valves are located outside contain nent and there are no penetration isolation devices inside containment. Therefore, the nilowance in NUREG 3.6.1.3 Required Action E.2 for these devices is not needed and is deleted. P. The changes to NUREG SR 3.6.1.1.2 are made to reflect testing methods currently in place at DAEC. The current testing method verifies the average rate of suppression chamber pressure change over a 10 minute period is < 0.009 psi / minute. DAEC UFSAR Section 6.2.6.3.5.1 assumes a differential pressure of greater than 1 psid. ! 1 P, NUREG SR 3.6.1.3.3 and SR 3.6.1.3.4 require each primary containment manual isolation valve and blind flange that is located either inside or outside primary contairunent, ar.J ihat is required to be closed during accident conditions, is verified to be closed every 31 days. DAEC will not adopt these SRs for the following reasons; i
- 1. The current DAEC TSs do not contain these SRs and the valve lineup checks are not in current licensing basis.
- 2. Administrative controls are adequate to ensure manual valves and flanges are maintained in the proper position. These controls include
I a. Independent valve lineup verifications following outages when a system has been taken out ofits normal lineup.
- b. Independent licensed operator preparation and verification of tagouts and independent placement and verification of placement of these tagouts.
DAFC 2 Revision I l
DISCUSSION OF CllANGES TO NUREG 1433 SECTION 3.6--CONTAINMENT SYSTEhtS PLANT SPECIFIC CllANGES (continued) I'7 c. Flanges are only positioned using controlled mainteu ce work (cont.) documents.
- 3. The Locked Valve Program at DAEC requires that all Safety System manual velves that could prevent the fulfillment of the safety function of the system shall be locked in their proper position as indicated on the Locked Valve Licting when the system is required to be Operable. Therefore, additional, periodic requirements to check manual valve positions are unnecessary.
- 4. Out af position, open, manual valves and flanges on primary conta'nment penetrations may cause increased drywell nitrogen usage and sho9d be detected by current trending ofliquid nitrogen inventory.
Primary containment integrity is ensured by performance ofIntegrated Leak Rate Testing, Local Leak Rate Testing and online nitrogen makeup. Any small leaks in containment are readily detectable by monitoring nitrogen makeup. {3.6.1.3-4 } P. NUREG SR 3.6.1.3.12 has not been used in the DAEC ITS submittal since the current license does not include this requirement. This type ofleakage is part of the overall containment leakage and no special limits apply. P, The current licensing basis for leak rate testing of the htSIVs is contained in CTS . 4.7.A.l.b. Rese CTS allowances are retained in ITS SR 3.6.1.3.9. The maximum leakage from any one htSIV shall not exceed 100 scfh at a test pressure of 24 psig and the combined maximum pathway leakage rate for all four main steam lines shall not exceed 200 scih at a test pressure of 24 psig.11 a htSIV exceeds 100 scfh,it will be restored to s 11.5 scth. l Pm At DAEC, the 18 inch purge valves are permanently blocked to restrict opening to 30* Therefore, NUREG SR 3.6.1.3.15 is not applicable and can be deleted. Pn At DAEC there are only two LLS valves and Condition B ofITS 3.6.1.5 has been revised to reflect this design. DAEC 3 Revision 1
OiSCUSSION OF CllANGES TO NUREO 1433 SECTION 3.6--CONTAINMENT SYSTEMS Pl. ANT SPECIFIC CIIANGES (continued) Pu The second frequency to NUREG SR 3.6.1.8.1 requires the Suppression Chamber-to-Drywell Vacuum Breakers to be verified closed after they may have been opened. This second Frequency is being deleted, based on DAEC current licensing basis and consistency with other ITS sections. Surveillances must be continually met (ITS SR 3.0.1), thus if the vacuum breakers are open and the Surveillance Frequency is not due yet, the SR would still be considered not met, and appropriate Actions taken. There are many other instances where valves are required to be closed, and verified closed on a periodic basis. If these other valves are cycled (e.g., ( ECCS valves), existing plant administrative controls ensure they c: len in the l correct position; a "special frequency" of the Surveillance is not required. In addition, these vacuum breakers have position indication in the control room, and are continuously monitored by control room operators. If conditions exist for the vacuum breakers to be potentially opened (e.g., venting the drywell), control room operators would be alert to the possibility and ensure the vacuum breakers were closed at the completion of the evolution. (3.6.1,i-5) l Po The second and third frequencies to NUREG SR 3.6.1.8.2 require a functional test of the vacuum breakers (i.e., cycle the vacuum breakers) within 12 hours aRer the vacuum breakers have cycled, or after an opeution that may have caused them to cycle. Since the vacuum breakers are designed to operate and assumed to function after a LOCA blowdown, their operation as designed after some other minor steam release from the SRVs should not raise questions regarding the immediate Operability of the vacuum breakers. Steam discharged to the Torus, resulting in increased wetwell l pressure and vacuum breaker opening, might pose a long term equipment degradation issue, rather than any immediate Operability concem. The 12 hour frequency would be meaningless to detect long term degradation, while the normal 31 day frequency would more than suffice for this concem. In addition, a review of vacuum breaker failures was performed and noted ths; no failures were due to the valves not opening. Thus it is not appropriate for DAEC, which does not have these current frequencies, to verify the vacuum breakers will open aner they havejust opened. {3.6.1.7-6} l DAEC 4 Revision 1
DISCUSSION OF CHANGES TO NUREG 1433 SECT!ON 3.6--CONTA1NMENT SYSTEMS PLANT SPECIFIC CilANGES (continued) Pn This Sircification was deleted because the function does not exist at DAEC. Pu ITS 3.6.3.2 Applicability was revised for clarity and to reflect the DAEC specific licensing basis. Additionally, the change achieves consistency with the Bases of the NUREG for the Applicability of the Primary Containment Oxygen Concentration Specification. c Pa NUREO SR 3.6.2.3.1 requires that every 31 days, each RHR suppression pool cooling subsystem manual, power operated, and automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, be verified in the correct position or can be aligned to the correct position. The current DAEC TS does not contain this SR and the valve lineup check is not in current licensing basis. DAEC has agreed to perform this SR by administrative means per the meeting with the NRC dated December 18,1997 and the conference call dated January 6,1998. The controls on manual vdves are as follows: i
- 1. Administrative . , trols are adequate to ensure manual valves are maintained 4 in the proper position. These controls include: y
- a. Independent valve lineup verifications following outages when a system has been taken out ofits normal lineup.
- b. Independent licensed operator preparation and verification of tagouts and independent placement and verification of placement of these tagouts.
2 The Locked Valve Program at DAEC requires that all Safety System manual valves that could prevent the fulfillment of the safety function of the system shall be locked in their proper position as indicated on the t.ocked Valve Listing when the system is required to be Operable. Therefore, additional, periodic requirements to check manual valve positions are unnecessary.
- 3. Verifying some system valve positions will require entry into radit. tion areas and will result in increased dose. Not performing these position checks will help maintain dose ALARA.
DAEC 5 Revision i
I DISCUSSION OF CHANGES TO NUREG 1433 SECTION 3.6-CONTAINMENT SYSTEMS PLANT SPECIFIC CHANGES (continued) Pa 4. Mispositioned open vents and drains will be detectable by water on floors, (cont.) increased sump leakage or by decreases in tank inventories much sooner than the 31 day surveillance. Additionally, periodic walkdowns (required by CTS 6.8.5.1 and CTS 6.8.5.2 and ITS 5.5.2) would detect mispositioned open vents and drains.
- 5. Verifying positions of remotely operated MOV's ensures that major diversion flowpaths (i.e., minimum flow, test, etc.) are properly aligned.
(3.6.2.3-1 } Pn Per agreement between the NRC and DAEC in our conference call of Febmary 2, 1998, we agreed to add LCO 3.6.2.4 (RHR Suppression Pool Spray) back into the ITS in order to expedite the StafTs completion of the Safety Evaluation Report for the conversion. He DAEC will re-submit the change to remove the LCO from the ITS after the initial amendment is issued, when sufficient Staff resources are available to complete the review of the DAEC UFSAR to verify that RHR Suppression Pool Spray does not satisfy the 10 CFR 50.36 screening criteria, in particular Criterion 3. As part of that agreement, the DAEC will retain its current licensing basis in the ITS and will not adopt those STS requirements that go beyond those in the CTS. Specifically, the CTS Completion Time for one subsystem inoperable will be retained as 30 days and the two STS Surveillances (SR 3.6.2.4.1 and SR 3.6.2.4.2 for valv: lineup verification and pump flowrate verification. respectively) will be replaced with the CTS surveillance to check the spray beaders and no721es for obstruction by an air test every five years. (S3.6.2.4-1 } Pu NUREG 3.6.2.5. D:ywell-to-Suppression Chamber DifTerential Pressure, was deleted since the DAEC specific analysis does not assume a differential pressure is maintained between the drywell and the suppression chamber.
% NUREG 3.6.3.2, Drywell Cooling System Fans was deleted since the DAEC accident analysis does not assume Drywell Cooling System fans are available to assure adequate mixing.
Pm NUREG SR 3.6.3.4.2 rt' quires that every 31 days each CAD subsystem manual, power operated, and automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, be verified in the correct position or can be aligned to the correct position. The co 4 DAEC TS does not contain this SR and the valve lineup check is not in cui nsing basis. DAEC o Revision I
DISCUSSION OF CHANGES TO NUREG 1433 SECTION 3.6--CONTAINMENT SYSTEMS PI ANT SPECIFIC CilANGES (continued) Pn DAEC has agreed to perform this SR by administrative means per the meeting with (ccat.) the NRC dated December 18,1997 and the conference call dated January 6,1998. The controls on manual valves are as follows:
- 1. Administrative controls are adequate to ensure manual valves are maintained in the proper position. These controls include:
- a. Independent valve lineup verifications following outages when a system has been taken out ofits normal lineup.
P,o b. Independent licensed operator preparation and verification of tagouts and independent placement and verification of placement of these tagoute. 2. The Locked Valve Program at DAEC requires that all Safety System manual valves that could prevent the fulfillment of the safety function of the system shall be locked in their proper position as indicated on the Locked Valve Listing when the system is required to be Operable. Therefore, additional, periodic requirements to check manual valve positionr are unnecessary.
- 3. Verifying some system valve positions will require entry into radiation areas and will result in increased dose. Not performing these position checks will help maintain dose ALARA. (3.6.3.1-2}
l Pu Clarification provided to reflect the DAEC specific design and terminology. g Editorial changes made including renumbering, as necessary. Pn NUREG SR 3.6.4.2.1 requires every 31 days that each secondary containment - isolation manual valve and blind flange that is required to be closed during accident conditions, be verified closed. The current DAi!C TS ooes not contain this SR and the valve lineup check is not in current licensing basis. DAEC has adequate i controls on the manual valves and flanges such that monthly checks are not required. These controls are as follows:
- 1. Administrative controls are adequate to ensure manual valves and flanges are maintainea in the proper position. These controls include:
DAEC 7 Revision I
l I DISCUSSION OF CHANGES TO NUREG 1433 SECTION 3.6--CONTAINMENT SYSTEMS PL ANT SPECIFIC CHANGES (continued) P 22 (continued)
- a. Independent valve lineup verifications following outages when a system has been taken out ofits normal lineup.
- b. Independent licensed operator preparation and verification of tagouts and independent placement cad verification of placement of these tagouts.
- c. Flanges are only positioned using maintenance work control documents.
- 2. The I_ ocked Valve Program at DAEC requires that all Safety System manual valves that could prevent the fulfillment of the safety function of the system shall be locked in their proper position as indicated on the Locked Valve Listing when the system is required to be Opemble. Therefore, additional, periodic requirements to check manual valve positions are unnecessary.
- 3. Verifying some system valve positions will require entry into radiation areas and will result in increased dose. Not performing these position checks will help maintain dose ALARA.
Secondary Containment integrity is ensured principally by the 1/4" drawdown test, 2 which includes a 13 inch opening for margin. Accident analyses do not specify individual leakage pathways, only that the overall Reactor Building pressure is maintained negative with respect to the outside emironment and all otaflow is filtered via the SBGT system. {3.6.4.2-4} Pu ITS SR 3.6.4.1.1 has been revised to verify all secondary containment equipment hatches are closed. The terminology "and sealed", as currently stated in the NUREG has been deleted. As stated in the NUREG Bases," sealed"in this context has no connotation ofleak tightness. The intent of this requirement is to verify that there is some form of seal (gasket) between the door and the flange. DAEC is deleting this requirement to verify the seals for the following reasons:
- 1. The subject seals are inspected in accordance with plant procedures any time the equipment hatches are opened or when any maintenance is performed.
- 2. Gross seal leakage or degradation will be identified as a result of the DAEC 8 Revision 1
DISCUSSION OF CHANGES TO NUREG 1433 SECTION 3.6--CONTAINMENT SYSTEMS secondary containment leak rate test. Pl. ANT SPECIFIC CHANGES (continued) P 23 3. The subject seals cannot be entirely inspected and verified unless the (cont.) equipment hatches are opened in order to view the entire seal. To open the equipment hatch to verify the seal will require the reactor to be brought to Mode 4 since opening the hatch will breach secondary containment integrity. Pu NUREG 3.6.1.3 Note I to Actions contains bracketed provisions that prohibit purge valve flow paths from being unisolated intermittently under administrative controls. This restriction is being deleted in the DAEC ITS since it is not in the CTS. the pure valves will close during a LOCA event and these valves are not currently opened routinely during plant operson. P25 Per our Response to NRC Question 3.6.1.3-7 and the DAEC's prior commitment under Amendment #219, the second frequency of STS SR 3.6.1.3.7 (ITS SR 3.6.1.3.4) will be retained. (3.6.1.3-7} P 26 NUREG SR 3.6.1.6.1 for manually opening the LLS valves, contains a frequency of I 8 months on a Staggered Test Basis for each valve solenoid. Since DAEC only has one solenoid per valve, testing on a Staggered Test Basis is not applicable. Pn Per our meeting with the StatTon December 18,1997, this change is being withdrawn. (3.6.2.1-3} P:s At DAEC, gaseous nitrogen is used in the CAD System. P29 NUREG SR 3.6.1.1.2 contains a second frequency of 9 months after two consecutive tests fail (and continues until two consecutive tests pass). This testing is not in the DAEC current licensing basis.and is not being adopted. This new test frequency would require mid-cycle testing which wou uire a plant shutdown due to the current testing method. The current test rn avolves blocking open the suppression chamber-to-reactor building vacuum breakers to establish initial conditions, pressurizing and maintaining the drywell at 1.2 psid above suppression chamber pressure, and then measuring the rate at which suppression chamber pressure incteases. Po3 The acceptance criteria of restricting flow to s 1 gph for EFCVs is not applicable at l DAEC. Per UFSAR 6.2.6.3.3. the acceptance criteria is obsening a marked decrease in flow rate. DAEC 9 Revision I
l DISCUSSION OF CHANGES TO NUREG 1433 SECTION 3.6--CONTAINMENT SYSTEMS ELANT SPECIFIC CHANGES (continued) P3 Per our Response to the Staff's RAI on this Note (Ref. NG-97-1597) and our meeting with the Staff on September 9,1997, this change has been withdrawn. { 3.6.1.3-8 } Pn DAEC uses the terminology " vacuum breaker assembly" in the CTS and this is being retained in the ITS. At DAEC there are two vacuum breaker assemblies located in parallel in two branch lino ofTa single penetration going into the. cuppression chamber. Each vacuum breaker assembly contains two vacuum breaker valves, an air operated butterfly valve and a check valve. ITS 3.6.1.6 has been modified to reflect the DAEC terminology without changing the intent of the TS. P 33 CTS 3.7.H allows the Containment Atmcsphere Dilution System to be inoperable for 7 days with no alternate hydrogen control available. At DAEC venting of the s Primary Containment through the Standby Gas Treatment (SBGT) System for hydrogen control, even though not required in the original licensing basis, can be used as an alternate means of hydrogen control. Since the SBGT System is a TS required function with its own Operability requirements, which are more restrictive thvi CAD (i.e., enter LCO 3.0.3 upon loss of both SBGT subsystems), it is not necessary to include NUREG Action B.I. Because of the diversity within the hydrogen control function at the DAEC (i.e., inerted containment), the NUREG has been modified to recognize that TS Action is not required until the eutire CAD System is inoperable (i.e., either because both nitrogen injection subsystems are inoperable or the common nitrogen bank is inoperable). The C'l S allowance of 7 days has then been implemented in the ITS to require establishing Operability of one nitrogen injection subsystem and the n::rogen storage bank and establishment of a " required" flowpath to both the Drywell and Suppression Pool. In addition, the NUREG has been changed to reflect the CTS Mode of Applicability of the reactor in " reactor power operation"(i.e.,21% RTP) and the primary containment inerted per CTS 3.7.1.1. (ITS 3.6.3.2). [ Note: Because the requirements of CTS 3.7.1.1 bound those of 3.7.H.1, they will be used.] This change is recessary as the design of the DAEC CAD System can not, by itself, inert the primary containment (Ref. UFSAR 6.2.5.3). Thus, the CAD system is not Operable until the containment is already inerted. Consequently, the LCO Applicauility has been changed to be consistent with that for the containment to be inerted (ITS 3.6.3.2); otherwise, the plant could never startup from Modes 3 or 4. per LCO 3.0.4. l3.6.3.1-1 } and (3.6.3.1-5 } DAEC 10 Revision 1
DISCU.NION OF CilANGES TO NUREG 1433 SECTION 3.6--CONTAINMENT SYSTEMS PLANT SPECIFIC CHANGES (continued) Pu NUREG 3.6.2.3, RHR Suppression Pool Cooling, has been changed to reflect DAEC cunent licensing basis assumptions for Operability. UFSAR Section 6.2.1.3.3.2 and Table 6.2-16 documents the long term primary containment response for a LOCA. The LOCA analysis shows that one Ri!R pump with one beat exenanger (with 2 RHRSW pumps) discharging via the LPCI injection valve is sufficient to limit peak suppression pool temperature to 200 F. In response to l NUREG-0783, which imposed local and bulk suppression pool temperature limits, NEDC-22082 (and Supplement 1) and NEDE-30051 (for power uprate and reduced RHRSW flow) were generated. These analyses document suppression pool temperature response to certain non-limiting LOCAs (small breaks) and transients (stuck open SRV). In order to meet the requirements of NUREG-0783 for suppression pool temperature limits, one loop of suppression pool cooling is required, consisting of two RHR pumps, one heat exchanger and 2 RHRSW pumps. The DAEC analysis supports the changes to the NUREG by requiring a minimum of two RIIR pumps to be Operable in Modes 1,2 and 3. Requiring subsystem Operability ensures that the necessary heat exchangers and pumps are available. In addition, a new Action has been added (Action D) to provide a restoration time for when both suppression pool cooling subsystems are inoperable. The proposed 8 hour Completion Time is consistent with the time provided in the NUREG when both RHRSW subsystems are inoperable. The time is considered appropriate since an immediate shutdown has the potential for causing a plant trip or transient. The 8 hours provides some time to restore one of the subsystems prior to requiring a shutdown (thus precluding the potential to cause a plant trip or transient), yet is short enough that it does not significantly increase the probability of an accident occurring during this additional time. DAEC i1 Revision I 1
I DISCUSSION OF CHANGES TO NUREG 1433 SECTION 3.6--CONTAINMENT SYSTEMS PLANT SPECIFIC CHANGES (continued) P35 ITS SR 3.6.4.3.2 has been modified by a Note delaying entry into the Conditions and Required Actions for one hour. During the performance of this SR, the Note is I necessary because due to a cross-tie duct between the two SBGT subsystems, the flowpath through the SBGT subsystem not being tested must be isolated, making it inoperable, to establish conditions necessary to ensure the tested SBGT subsystem meets the filter train differential pressurs requirements of the VFTP. The ability to draw a vacuum on Secondary Containment is maintained by the subsystem under test. One hour minimizes the amount of time the SBGT subsystem is inoperable while providing enough time to redorm the required testing. The allowance provided by the Note avoids potential entry into LCO 3.0.3 (Condition D) during required routine Surveillances and during demonstration of Opernbility under LCO 3.0.5. The addition of the Note to this SR is considered acceptable due to the low probability of an event requiring system actuation during this one hour time frame balanced against the need to perform Surveillances to demonstrate Operability and avoidance of an unnecessary plant shutdown while performing testing for Operability under LCO 3.0.5. {3.6.4.3-5} P 36 NULEG SR 3.6.2.3.2 has been revised to change ">" to "2" DAEC's RHR pumps are each required to be able to deliver a minimum flowrate of 4800 gpm. The addition of the " equal to" allowance is less restrictive but the additional margin is so , small that it is insignificant and, therefore, is acceptable. Pn NUREG 3.6.1.3 Action I has been changed by modifying the Required Action to initiate action to suspend OPDRVs. The use of the term "or operations with the potential for draining the reactor vessel (OPDRV's)" in the Condition is inconsistent with the Mode of Applicability specified in LCO 3.6.1.3. The DAEC Current Licensing Basis does not require any PCIVs to be Operable in Modes 4 or 5, nor does it require PCIVs to be Operable when performing OPDRVs. The only PCIV functions required Operable by the STS for DAEC would be the shutdown cooling valves will not mitigate any OPDRVs except those within the RHR system. Either Required Action G.1 or G.2 may be applied. This is acceptable since either Required Action is a proper compensstory measure to restore compliance with the LCO. Therefore, the only "OPDRVs" that need to be suspended are those associated wnh the RHR Shutdown Cooling System. {3.6.1.3-3 } DAEC 12 Revision I L
i DISCUSSION OF CHANGES TO NUREG 1433 SECTION 3.6-CONTAINMENT SYSTEMS PLANT SPECIFIC CHANGES (continued) Ps 3 The one hour requirement to maintain 2 0.25 inch vacuum has been deleted. l DAEC's plant procedures require a 10 minute hold to allow conditiens to stabilize before taking readings. The 10 minute stabilization has been adequate in the past to ensure adequate equilibrium conditions are obtained and maintaining conditions for one hour would cause undo burden on refuel outage scheduling without any real safety benefit. Additionally, DAEC does not have instrumentation which can record Secondary Containment vacuum continuously. DAEC uses the average of four manometers with one manometer mounted on each face of the Reactor Building to negate the effects of wind direction. These manometers must each be read locally and then manually averaged to determine the Secondary Containment vacuum value. P, 3 Revised ITS 3.6.1.3 second Applicability to more clearly state what valves are applicable (Shutdown Cooling System Isolation Valves). The second Applicability statement as originally written was confusing as to when it applied and to what it applied. The revised Applicability statement defines the Modes and System to which this statement applies. For DAEC, the only instrumentation required to be m Operable in Modes 4 and 5 is Reactor Low Level which will close the Shutdown
- Cooling System Isolation Valves.
Po 4 NUREG SR 3.6.1.3.8 requires MSIV Isolation time to be "2" and "s" the DAEC l specific times. Current DAEC testing requires isolation time "between 3 and 5 seconds." DAEC will change "2" to ">" and "s" to "<." l P.n NUREG SR 3.6.1.3.11 requires testing of the explosive squib every 18 months on a STAGGERED TEST BASIS. CTS does not have any requirements for testing TIP Squibs but DAEC has been testing them per the ASME program. This change will be consistent with current DAEC practices and is still a more restrictive change. P.u Per the response to NRC Question 3.6.1.6-6, this change has been withdrawn. { 3.6.1.6-6 } P 43 Pei our Response to NRC Question 3.6.2.2-1, this change has been with& awn. (3.6.2.2-1 } DAEC 13 Revision I
DISCUSSION OF CHANGES TO NUREG 1433 SECTION 3.6--CONTAINMENT SYSTEMS PLANT SPECIFIC CHANGES (continued) Pu NUREG SR 3.6.4.1.1 and SR 3.6.4.1.4 are being deleted. Maintaining a negative pressure in the secondary containment during normal plant operations is not assumed by any of DAEC's accident analyses, nor is attainment of a negative 1/4-inch required within a given time period to mitigate the consequences of any accident. P43 Correction of typographical error. [CRF 9108] Pu Based upon discussions with the Staff on September 9,1997 regarding our response to the Staff's Request for Additional Information (RAI) of Februarj 24, 1997 (Ref. NG-97-1597, September 5,1997), the proposed change to add Note 2 to ITS SR 3.6.4.3.2 has been withdrawn. {3.6.4.3-5} g Pu This Note has been deleted since it is not needed; purge valves are not required to be Operable in Modes other than 1,2, and 3. Th- Applicability of this LCO is only in Modes 1,2, and 3; Modes 4 and 5 are only applicable for Shutdown Cooling System Isolation valves when the associated instrumentation is required to be Operable per LCO 3.3.6.1. Pa NUREG SR 3.6.1.3.1 has been deleted since DAEC is not required to maintain the purge valves sealed closed. CTS 3.7.B.4 requires "... purge valves may not be opened so as to create a flow path from the primary containment while PRIMARY CONTAINMENT INTEGRITY is required except for inerting, de-inerting, vent / purge valve testing, or pressure control." This CTS requirement is being retained in the Note to NUREG SR 3.6.1.3.2 (ITS SR 3.6.1.3.1). Po NUREG 3.6.1.3 Actions G and H are in brackets and have been deleted since they are not applicable to DAEC. In the Mark I containment design, the Refuel Floor is part of the secondary containment, not the Primary Containment where the purge / vent valves are located. Po 3 NUREG SR 3.6.1.3.14 requires that the combined leakage rate through hydrostatically tested lines that penetrate the primary containment be verified to be within limits given in the Primary Containment Leakage Rate Testing Program. At the DAEC, the leakage from tests conducted with water is added to the air leakage totals to demonstrate that total leakage is within acceptable limits. The Technical Evaluation Report (TER) for the DAEC's Containment Leakage Rate Testing, dated March 17,1982. states that this is acceptable DAEC 14 Revision I
DISCUSSION OF CHANGES TO NUREG 1433 SECf10N 3.6--CONTAINMENT SYSTEMS Pl. ANT SPECIFIC CHANGES (continued) Pa 3 The TER states performing tests with water and adding the results to the air leakage (cont.) totals to determine compliance with leakage limits is conservative with regards to the requirements of Appendix J. ITS SR 3.6.1.1.1 requires the performance of leakage rate testing in accordance with the Primary Containment Leakage Rate Testing Program and thereby adequately addresses testing ofhydrostatically tested lines, making this SR iedundant and unnecessary. Therefore, NUREG SR 3.6.1.3.14 has been deleted from the ITS. Psi SR 3.6.1.2.2 is being revised to require testing of the airlock door interlocks at an interval of 24 months. This is consistent with Appendix J, Option B, which allows for an extension of the overall airlock leakage test frequency to a maximum interval of 30 month'. The Note to the SR is deleted since it will no longer be required due to the frequency change. This change is consistent with Generic Traveler TSTF-17. Ps2 NUREG SRs 3.6.1.3.6 ITS SR 3.6.1.3.3 and 3.6.4.2.2 (ITS SR 3.6.4.2.1) are being revised for clarity. 'Ihe purpose ofITS SRs 3.6.1.3.3 and 3.6.4.2.1 are to ensure the valves and dampers will isolate in a time period less than or equal to that assumed in the safety analysis. There may be valves and dampers credited as coninment isolation valves which are power operated that do not receive a containment isolation signal. These power operated v dves and dampers do not have an isolation l time as assumed in the accident analysis since they require operator action. Therefore, restricting the SR to power operated automatic isolation valve and damper time testing reduces the potential for misinterpreting the requirements of this SR while maintaining the assumptions of the accident analysis. This revision is consistent with the Generic Traveler TSTF-46, Rev.1. {3.6.1.3-11 and3.6.4.2-9}. P 33 ITS SR 3.6.4.1.2 has been modified from NUREG 1433 to retain the current licensing basis for the DAEC. Definition 16.a of the CTS requires that "At least one door in each access opening is closed." Because the DAEC design has secondary containment penetrations with three access doors, the NUREG wording was modified to allow multiple doors to be open that do not compromise secondary containment integrity. Closure of either an inner or outer access opening ensures that any other access opening will not prevent the Secondary containment from performing its intended safety function. DAEC 15 Revision I
DISCUSSION OF CHANGES TO NUREG 1433 SECTION 3.6-CONTAINMENT SYSTEMS
- PLANT SPECIFIC CHANGES (contmued)
P 53 Also, a Note specifying that doors in high radiation areas may be verified by (cont.) administrative means has been added, since the DAEC design has some access doors that may be in high radiation areas when the plant is operating. Allowing ve-ification by administrative means is acceptable, since access to these areas is typically restricited. Therefore, the probability of misalignment of these doors, once they have been verified in the proper position, is low. {3.6.4.1-2} - P 54 In 60 FR 49495 dated September 26,1995, the NRC published an amendment to Appendix J to 10 CFR Part 50. This amendment became effective on October 26, 1995 and revised Appendix J to allow Licensees the choice of complying with either the new performance based requirements (Option B) or previously existing perspective requirements (Option A). Regulatory Guide 1.163," Performance - Based Containment Leak - Test Program " was issued to provice guidance on the implementation of Option B. The CTS and NUREG are being modified consistent with DAEC Request for Technica1 Specification Change RTS-269 (NG-95-2985) dated December 22,1995 and NRC letter from Christopher I. Grimes (Chief Technicel Specifications Branch, USNRC) to David J. Modeen (Director, Operations and Management, NEI) dated November 2,1995, implementing Option B. P 33 This change relaxes the Completion Time for isolating a penetration with one PCIV inoperable from 4 hours to 72 hours for GDC-57 lines (i.e., closed systems inside containment) except for excess flow check valves. This change is consistent weh Revision 2 to TSTF-30 approved by the NRC on October 1,1997. [CRF 9232] P 36 A NOTE has been added to SR 3.6.1.3.6 to allow, for the MSIVs, the SR may be satisfied by any series of sequential, overlapping, or total steps so that proper operation of the MSIVs on receipt of an actual or simulated isolation signal can be verified. This is being done to reflect the DAEC current licensing basis for testing the MSIVs, as allowed by the footnote (#) to CTS 4.7.B.I.a. Operability continues to be demonstrated by the Logic System Functional Test ofITS 3.3.6.1 and the stroke time test of SR 3.6.1.5. [CRF 9138] DAEC 16 Revision ! l
DISC'f mN P'HANGES TO NUREG 1433 BASES ShCTION : o - CONTAINMENT SYSTEMS PLANT SPECIFIC CHANGES Pi The plant specific nomenclature, number, reference, system description, or analysis description was used to reflect DAEC (additions, deletions, and/or changes are included). P Bases revised for enhanced clarity, to correct typographical errors, or to be consistent with . milar phrases in other parts of the Bases. P3 Note 4 to the Actions and Conditions A and B ofITS 3.6.i.3 have been modified from the current NUREG exception for purge salve leakage not within limits, to include exceptions also to MSIV leakage not within limits. These exceptions are acceptable since other Actions in ITS 3.6.1.3 address these exceptions. T'ie Bases
- have been changed to reflect the changes to the Specificaticns.
P4 At DAEC the reduced pressure test is not used and 'he reference to this Type A Testing is deleted. P5 DAEC was not licensed to the GDC's. However, the DAEC has been evaluated to show that the intent of each GDC is substantially met. The appropriate UFSC. Section thet documents these evaluations is referenced in place of the GDr. ;tself. P6 A discussion has been added to the Applicable Safety Analyses for the Bases of ITS 3.6.1.4 (Drywell Air Temperature). This discussion merely reflects the Current Licensing Basis, as discussed in UFSAR 6.2, and as such, is acceptable. P7 A discussion has been added to the Background section of the Bases for NUREG 3.6.4.3 explaining that the 0.25 inches water gauge negative pressure in Secondary Containment is an average of four manometer type pressure gauges, and that 0.25 inches watt. gauge negative pressure includes margin to a negative pressure that ensures zero exfiltration. This is true since maintaining 0.25 inches a negative pressure under calm wind conditions ensures a negative pressure (with respect to the lowest pressure building face with wind present) under worst case conditions. P. The Bases have been revised to reflect changes to the associated technical specification. DAEC 1 Revision I
f DISCUSSION OF CHANGES TO NUREG 1433 BASES SECTION 3.6--CONTAINMENT SYSTEMS Pl. ANT SPECIFIC CIIANGES (continued) P9 Amendment No. 201 to DAEC CTS allows the functions of"inerting c : pressure adjustment" as part of the drywell vacuum breakers intended fimetion and is acceptable so inclusion of"inerting or de-inerting containment"into the Basis for ITS LCO 3.6.1.7 is acceptable. Poi Changes to References made to reflect specific DAEC requirements. Pn The sentence in the Background section of the Bases for 3.6.4.1 (Secondary Containment) regarding a possible control volume pressure rise due to pump and motor heat has been deleted. This sentence was confusing and did not add value to the discussion. Pu Examples of hatches subject to the Surveillance Requirements has been added to the Bases discussion for SRs 3.6.4.1.1 and 3.6.4.1.2 Po The Bases for the 31 day Frequency for SR 3.6.4.3.1 has been changed to reflect that preventing moisture build-up in the charcoal is the primary reason for the surveillance. This agrees with the preceding statement in the Bases. Also, the reference to excessive vibration has been deleted, since vibration data is not collected during this surveillance. Lastly, the Bases have been clarified to say that it is not always necessary to run the system for the full 10 hours to demonstrate Operability following maintenance, if that maintenance did not affect the filters and charcoal beds. This is consistent with the Bases for similar components in the Standby Filter Units (SFU) in section 3.7.4. {3.6.4.3-8} Pu ITS SR 3.6.1.6.3 frequency discussion has been changed to reflect the ability to perform this surveillance at any time and to agree with the assumption of a 12 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis. Pn This sentence is being deleted. Current DAEC operating practice involves controlling the passive Secondary Containment boundary as a single general category. No component testing for the individual passive devices was relied on in the Licensing Bases for the DAEC Administrative Control Procedure (ACP) 1410.6, Temporary Modification Control, contains the appropriate precautions / procedures to ensure secondary containment penetrations are
, adequately controlled. Changes to this procedure will be evaluated in accordance with the DAEC 10 CFR 50.59 program. [3.6.4.2-7} l DAEC 2 Revision I i
f l DISCUSSION OF CHANGES TO NUREG 1433 B ASES SECTION 3.6--CONTAINMENT SYSTEMS PLANT SPECIFIC CHANGES (continued) Ps i A statement was added to Bases LCO 3.6.4.2 stating that a utility penetration may be open and SecoMary Containment maintained Operable as long as it can meet the negative pressure Surveillance Requirements. P;7 Per our Response to the Staff's RAI on this Note (Ref. NG-97-1597) and our meeting with the Staff on September 9,1997, this change has been withdrawn. {3.6.2.3-5) {3.6.3.1-4} Pei In 60 FR 49495 dated September 26,1995, the NRC published an amendment to Appendix J to 10 CFR Part 50. This amendment became effective on October 26, 1995 and revised Appendix J to allow Licensees the choice of complying with either the new performance based requirements (Option B) or previously existing perspective requirements (Option A). Regulatory Guide 1.163," Performance - Based Containment Leak - Test Program," was issued to provide guidance on the implementaticn of Option B.- The CTS is being modified in the NUREG consistent with DAEC Request for Tecimical Specification Change RTS-269 (NG-95-2985) dated December 22,1995 and NRC letter from Christopher I. Grimes (Chief Technical Specificctions Branch, USNRC) to David J. Modeen (Director, Operations and Management, NEI) dated November 2,1995, implementing Option B. Ps Changed all references to "the NRC Policy Statement" to its associated Section in 10 CFR 50.36. P 20 To verify the setting of the suppression chamber-to-drywell vacuum breakers, personnel must physically enter the suppression chamber which is not possible with the containment inerted. Therefore, it is impossible to perform this surveillance with the reactor at power and this statement in the Bases is inappropriate and has been deleted. P 2i As part of the agreement between the NRC and DAEC to retain RHR Suppression Pool Spuy in the ITS, the STS Bases have been revised to remove the statements that this system is needed to mitigate any design basis event or transient or that it satisfies the 10CFR 50.36 screening criteria for incilusion in the ITS. (S3.6.2.4-1 } s DAEC 3 Revision I l
DISCUSSION OF CHANGES TO NUREG-1433 BASES SECTION 3.9-REFUELING OPERATIONS Els\NT SPECIFIC CilANGES Pi The plant specific nomenclature, numbers, references, system descriptions, system design, operating practices or analysis description was used to reflect the DAEC (additions, deletions, and/or changes are included). P2 Bases revised to enhance clarity. P3 Bases avised for consistency with other Bases sections. P4 This Bases section was deleted because the associated Specification / Surveillance was deleted. P5 DAEC was not licensed to the GDC's. However, the DAEC has been evaluated to show that the intent of each GDC is substantially n :. The appropriate UFSAR Section that documents these evaluations is referenced in place of the GDC itself. P. This change to the Bases was made to reflect similar changes to the Technical Specifications. P7 Changed all reference to "the NRC Policy Statement" to its associated section in 10 CFR 50.36. P The reference to APRM Operability in Mode 5 is being deleted since Operability of this Function is not required in ITS 3.3.1.1. . P, ITS Bases for RHR Shutdown Cooling indicate that losses to ambient can be
' con.:idered as, or co tributing to, the altemate method capability. The change adds a description of how losses to ambient can fulfill tne alternate heat removal capability.
Po i SR 3.9.7.1 and SR 3.9.8.1 only verify Shutdown Cooling operation. No specific flow rate is required and so the word " required" is deleted. Flow ra,e is determined by the decay heat load that is present and is procedurally controlled. 4 DAEC 1 RevisionI l
DISCUSSION OF Cl!ANGES TO NUREG-1433 BASES SECTION 3.9--REFUELING OPERATIONS PLANT SPECIFIC CHANGES (continued) Pn Typographical errors corrected. Pn RHR Shutdown Cooling subsystem requirements, the subject of this LCO, are not covered in other Modes in Sections 3.5 or 3.6. Therefore, this statement has been deleted. Pn The ITS 3.9.2 Bases have been modified to reflect the fact that the DAEC design includes only one reed switch for each control rod that feeds both one-rod-out channels. The ITS 3.9.2 Bases LCO discussion has been modified to state that another full-in indication may be used to provide input to both of the one-rod-out channels (using appropriate administrative controls), and the LCO may be considered to be met. This is acceptable, since the other full in indicmion will provide identical protection from inadvertent criticality ifits output is temporarily provided to the one-rod-out logic. This is necessary so that the failure of a single component (reed switch) will not prevent refueling operations from continuing. Pn Per discussions with the NRC on February 11,1998, this clarification of the requirements for performance of Channel Functional Testing is being added to the Bases in lieu of the changes to the Definition of Channel Functional Test proposed by reject:d TSTF-64 and TSTF-205. [CRF 9916] DAEC 2 RevisionI l
Enclosure 2 to NG-98-0342 Relocated Items Matrix for the DAEC Improved Technical Specifications
~
Relocated Itt ms Matrix 16-Feb-98 HS DOC CTS Description Locatiori 1.0 R1 1.5 Operability Definition Bases i 2.0 R1 1.1. D Definition of " Top of Active Fuel" UFSAR 2.0 R2 6.7.3 Notification of VP on SL violation QAPD 3.0 R1 1.26 25% extension convenience Bases 31.2 R1 3 3 E.3 Perform reactivity difference analysic Bases R1 3.3 A.2.e Details on how to disarm CRDs Bases 3 1.3 R1 4.3.D.1 Details on scram time testing Bases 3.1.4 R1 4.3.A.2.a 1R accumulator leve! switch Deleted by DOC L3 3.1.5 surveillance 3 1.7 R1 4.4.A.2.a Surveillance on operation /setpoint of IST Program SLC reliefs R2 4.4.A 2 b Details on how to verify SLC flow Bases 3 1.7 3.1.7 'R2 4.4. A.2.c Details on how to verify SLC flow Bases 3.1.7 R3 4.4.A.1 Details on SLC pump loop testing Bases 3.10.3 R1 3 9.A.3.b Details concerning shutdown margin Bases ' testing R1 3.9.A.3.a.2 Single rod! drive mechanism Bases 3.10.3 withdrawal R2 3 9.A.3 How to disarm control rods Bases 3.10.3 1
DOC CTS Description Location [TS 3.10.4 R1 3.9 A.3 a.2 Single rod / drive mechanism Bases withdrawal 3104 R1 3.9 A 3 b Details concerning shutdown me- 4, Bases testing 3 10.4 R2 3 9.A.3 How to disarm control rods Bases 3.10.5 R1 3.9.A.3 b Details concerning shutdown margin Bases testing 3 10.5 R2 3.9 A.3 How to disarm control rods Bases 322 R1 4 12.C.1.b Verify MCPR following significant Deleted by DOC L2 power change 323 R1 312.B tHGR TRM 3 3.1.1 R1 Table 4.1-1 note f Calbrate LPRMs using the TIP Bases l system 3 3.1.1 R1 Table 4.1-1 note b 1/2 decade overlap for SRMs/lRMs Bases 3.3 1.1 R10 Table 4.1-1 notes g, k, i Testing requirements for RPS trip g: Bases functions k,1: Deleted by DOCS A9, A14 3.3.1.1 R11 Table 3.1-1 note i Additional trip functions actuate EOC- Bases RPT system 3.3 1.1 R12 Table 3.1-1 Relomte " Trip Level Settings" UFSAR 3 3 1.1 R12 2.1 Relocate" Limiting Safety System tFSAR Settings" 3.3.1.1 R12 2.2 Relocate " Limiting Safety System UFSAR Settings" 2
DOC CTS Description Location [LS 3 3.1.1 R13 3 1.A Details of RPS logic system Bases response time test 3 3 1.1 R2 2.1 A.1 APPM flow biased high scram UFSAR equation 3 3 1.1 R2 Figure 2.1-1 Core power vs. recirculation flow UFSAR 331.1 R3 Table 31-2 RPS respcase times UFSAR 3 3 1.1 R3 31A RPS response times UFSAR 3.3.1.1 R4 3.1. A notes *," Wnen not to place RPS channels in Bases trip 3 3 1.1 R5 Table 3.1-1 r.ote b IRMs automaticahy bypassed when Bases mode sw. in RUN 3.3.1.1 R6 Table 3.1-1 note c APRM inoperabihty requirements Bases 1 3 3 1.1 R7 Table 3.1-1 note e MSIV casure trip bypassed when Bases mode sw not in RUN 3 3.1 1 R8 4.1.A.2 Staggered test basis of RPS functions Deleted by DOC A15 3 3 1.1 R9 Ta.31e 3.1-1 Turbine First Stage Pressure Bases Permissive 1 3.3 1.1 R9 Tab!e 4.1-1 Turbine First Stage Pressure Bases Permissive 3 3 1.2 R1 3 9.B.1 SRMs be inserted during Core Alts UFSAR 3 3.1.2 R2 3 9 B.3 Get 3 cps by 2 of 4 assemblies Bases loaded near 4 SRMs 3 3.2.1 R1 Table 4.2-C APRM, IRM, SRM, SDV & Recirc TRM Flow Rd Blocks ! 1 3 . l l _ _ _ - a
DOC CTS Description Location US 3.3.2.1 R1 Table 3.2-C APRM, IRM, SRM, SDV & Recirc TRM Flow Rod Blocks 3 3 2.1 R2 Table 3 2-C note a RBM bypassed when peripheral rod Bases selected 3.3 2.1 R3 Table 4.2-C Channel check RBM upscale and Dcleted by DOC L8 downsca% functions 3.3.2.1 R4 Table 4.2-C note c include RMC multiplexing system Bases input in RBM CFT 3.3 2.1 RS Table 3.2-C Relocate " Trip Level Settings" UFSAR l R6 4.3 C.1 b Details on RWM testing UFSAR 3 3.2.1 R6 4.3. C.1.c Details on RWM testing Bases 3.3.2.1 R6 4.3.C.1.d Details on RWM testing Bases 3 3.2.1 3331 R1 3.2.H Extra PAM instruments TRM 3331 R1 4 2.H Extra PAM Instruments TRM 3 3 3.1 R1 3 2.F Surveillance instruments TRM 3.3.3.1 R1 4.2.F Surveillance instruments TRM
~3 3 3 1 R2 Table 3.2-H Descriptive details for various PAM Bases instruments R2 Table 4.2 H Descriptive details for various PAM Bases 3.3.3 1 instruments 3 3.3.1 R3 Table 4.2-H notes b, e Testing method for Rad Monitors and Bases H2/02 Monitors 3331 R3 Table 3.2-H note b Normal for Containment H2/02 Bases Monitor is Standby 4
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ITS DOC CTS Description Location 3.3 3.2 R1 310 B Verify Remote Shutdown Panels UFSAR locked once/ week 3 3 3.2 R1 4.10 B Venfy Remote Chatdown Panels UFSAR
.xked once/ week 334.1 R1 Table 4.2-G EOC-RPT Response Times UFSAR 3341 R2 Table 3 2-G Relocate " Trip Level Settings" UFSAR 3.3.4.1 R3 Table 3.2-G note b Trip system description for ATWS- Bases RPT and EOC-RPT 3.34.2 R1 3.2.G ARI functions TRM 3 3.4 2 R1 4 2.G ARI functions TRM ;
3 3.4.2 R2 Table 3.2-G Relocate " Trip Level Settings" UFSAR 1 3.3.4 2 R3 Table 3 2-G note b Trip system description for ATWS- Bases RPT and EOC-RPT 3 3.5 1 R1 4.2.B 2.f Perform LSFT on Safeguards TRM Systems Area Cooling 3 3.5.1 R2 Table 3.2-B Relocate " Trip Level Setting" UFSAR 3 3.5.1 R3 Table 3.2-B notes c, d Descriptive material for HPCI pump Bases trips 3.3.5 2 R1 Table 3.2-8 notes c, d Description for RCIC pump trips Bases 3 3.5 2 R2 Table 3 2-B Relocate " Trip Level Settings" UFSAR 3361 R1 3 ? A 1.b note
- Descobes when to place channels in Bases trip 3.3 6.1 R10 Table 3 2-A RCIC and HPCIisolation function Bases 5
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a ITS DOC CTS Description Location 3361 R11 Table 3 2-A RCIC steam low pressure '. rip reset UFSAR setpoint l 3 3 6.1 R2 Table 3.2-A Relocate " Trip Level Settings" UFSAR 3 3-.6.1 R2 Table 3 2-B Relocate " Trip Level Settings" UFSAR 3.3 6.1 R3 Tbl 3.2-A notes b,c e.g.h Descriptive material Bases 3 3 6.1 R4 Table 3.2-A note o 2 MSL tunnel temperature sensors Bases per MSL required ' 3.3.6.1 R5 Tab:e 4.2-A notes ##,a,c Descriptive information on various a, c: Deleted by DOCS A9 SRs and M9
##: UFSAR j 3 3 6.1 R6 Table 3.2-A notes d, f, j Descriptive information for various f:B?ses functions d, J: UFSAR 3.3 6.1 R7 Table 4 2-A note ### RPV Level-Lo and DW Pressure-Hi UFSAR l co' simon to RPS/ECCS 3.3 6.1 R8 Table 3.2-D note c MSL Rad Monitors trip Mech. Vac. Bases Pump 3.3 6.1 R9 Table 4.2-D note a Method for CFT for MSL Rad Deleted by DOC A9 Monitors 5.3.6.2 R1 3 2 A.1.b note
- Describes when to place channels in Bases trip 3362 R2 1able 3 2-A Relocate " Trip Level Settings" UFSAR 3 3 6.2 R3 Table 3.2-A note c Respective signals start the SBGT Bases system 3362 R4 Table 4 2-A note ### RPV Level-Lo and DW Pressure-Hi UFSAR common to RPS/ECCS 6
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i ITS DOC CTS Description Location 3 3 6.3 R1 2.2.1 Relocate " Limiting Safety System UFSAR Setthgs" l 3.3.8.1 R1 Table 3.2-8 Relocate " Trip Level Settiags" UFSAR 3.4.1 R1 3.3.F.3 Methods to exit the Exclusion Region Bases 3.4.1 R2 3.3 F.S.b Regs ior opening lower speed recirc UFSAR pump disch viv 3 4.1 R3 3.3.F.4 c Methods to ensure idle loop is Bases isolated 3 4.2 R1 4.6 E.1 Performance of Jet Pump SRs after Deleted by DOC A3 abnormal changes 3.4.2 R2 4 3.F.4.a Update baseline data ASAP Bases 3.4.2 R2 4.6.E.4 Update baseline data ASAP Bases 3 4.3 R1 4 6.D.2 Disassemble and inspect 1 SRV per ISI Program cycle l 3.4.3 R2 4 6.D.3 How to verify SRV is manually Bases opened 34.5 R1 Table 3.2-E notes a, b Descriptions of Sump System & Air Bases Sampling System 3.4.0 R1 Table 4.6.B.1-1 Requirements for sampling and gress iodine: Deleted by analysis DOCL5 filter: Bases 3.4.9 R1 3.6.A.2 Meet restrictions of operating curves, Deleted by DOC L3 vent RPV l 3.4.9 R2 4.6 A.1 Details on when RCS temperature Bases SRs caa be stopped 7
DOC CTS Descripti_on Location I_TS 3 4.9 R3 4 6.A.2 Areas for RPV temperature Bases monitoring 3 4.9 R3 4.61.1 Areas for RPV temperature Bases monitoring 34.9 R4 3.6.A.4.b Perform engineering evalif P-Tlimits Bases exceeded 34.9 R5 4 6 A.2 Record surveillance results OAPD 3 4.9 R5 4 6 A.3 Record surveillance results OAPD 349 R5 4.6 A.4 Record surveillance results OAPD 3.5.1 R1 4.5.H.1 Test LPCI and CS line pressure UFSAR switches 3.5.1 R2 3.5.1 ES Compartments Cooling & TRM Ventilation 3.5.1 R3 4.6.D.3 Manual operation of each relief valve Bases j 3.5.1 R4 4.5 A.1.b Pump operability and MOV IST Program operability tests l 3.5.1 R4 4.5.A.1.c Pump operability and MOV IST Program operability tests 3.5.1 R4 4.5.A.3 b Pump operability and MOV IST Program operability tests 351 R4 4.5.A.3 c Pump operability and MOV IST Program operability tests 3.5.1 R4 4.5.D.1.b Pump operability and MOV IST Program operability tests 8
DOC CTS Description Location l ES 3 5.1 R4 4.5 D.1.c Pump operability and MOV IST Program operability tests 3 5.1 R5 4.5.A 3 e Verify RHR valve panelinstruments Deleted by DOC L12 operate nonnal j 3.5.1 R6 4.5 D 1.f Verify HPCI suction can be Bases transferred 3 5.1 R7 4.5 F.1.b Leak test ADS N2 accumulator check Bases, IST Program i valves { 352 R1 4.5 H.1 Test LPCI & CS line pressure UFSAR switches l
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3.5.2 R2 4.5.1 SRs for all ECCS room coolers TRM ! 352 R3 3 5 G.3 Operability regs for RHR and CS Bases pumps in Mode 4/5 3,5,3 R1 4.5 E.1.a inc!ude RCIC auto-start on low water Bases level signal l 353 R2 4.5 E.1.c Pump operability and MOV IST Program operability tests l IST Program I 3.5.3 R2 4.5 E.1.b RCIC Pump operability and MOV operability tests 3 5.3 R3 4.5 E.1.f Verify RCIC suction can be Bases i transferred l 3.5.3 R4 3.5.1 ES Compartments Cooling & TRM Ventilation 3.6,1.1 R1 1.15 Blind flange and manway details Bases 3 6.1.2 R1 1.15.b Closure of at least one airlock door Bases 9
IT_S DOC CTS Description Location 3 6 1.3 R1 1.15 PCIV details Bases l 3 6.1.3 R2 4.7.8.1 b.1 Close & reopen normally open power IST Program operated PCIVs 3 6.1.3 R3 4.7.B.1. b.2 Requirement fcr power to be <75% IST Program for !'SIV testing 3 6.1.3 R4 3.7.8.4 a List of containment vent / purge valves UFSAR and groups 3 6.1.3 R4 47A1c List of containment vent / purge valves Bases and groups 3 6 1.5 R1 4 6.D.3 How to verify LLS valve has Bases ! i manually opened 3 6,1 5 R2 4.6 D 2 Disassemble and inspect 1 SRV per ISI Program cyct? 3616 R1 3.7.D.1 Details on operable vacuum breakers Bases 3 6 1.6 R2 3.7.D.2 Venfication of closed inoperable Bases vacuum breakers 3 6.2.1 R1 4.7.G 2.c Visualinspection of torus UFSAR 3 6.3.1 R1 3.7.H.1 Details on operable CAD system Bases 3 6.3.1 R2 4.7.H.1 Test CAD system annually JJFSAR 3 6.3.1 R3 3.7.H.2 Determine CAD system contains UFSAR minimum reg N2 3641 R1 3 7.J.1 d Maintain secondary containment if UFSAR cask being moved 364.1 R2 4.7.J.1.a Requirements for wind conditions Bases and filter train 10
vo c - " - . . . m. I_TS DOC CTS Description Locatior! 3 E 4.1 R3 1.16 SCIV Details Bases 3642 R1 3.7.K.1 SCIVs operable to move cask UFSAR 3642 R2 1 16 SCIV details Bases 3.4, R1 3.7.L.1 SBGT operable to move ca: UFSAR 3.6 4 3 R2 4 7.L1.f Inspect SBGT systern drains UFSAR 3 7.1 R1 45C1b SRs for RHRSW pumps and valves IST Program 3.7 1 R1 4.5 C.1.a SRs for RHRSW pumps and valves IST Prograr : 3.7.2 R1 45J1d SPs for RWS pumps and valves IS ( Program
; .2 R1 4.5 J.1.c SRs for RWS pumps and valves IST Program 3.7.2 R1 4.5.J.1 b SRs for RWS pumps and valves IST Program 3.7.3 R1 9 E.1.b SRs for ESW pumps and valves IST Program 3 7.3 R1 4 E1c SRs for ESW pumps ar d valves IST Program l 3 7.4 R1 4.10 A.2.d Details on SFU system UFSAR demonstration of operabihty 3 7.4 R1 4.10. A 3 Details on demonstrating the SFU Bases system operable 3.74 R2 413 A 3 Rer;uiremerits for wind condit.. .s Bases 3 7.8 R1 3 9 C.1 a 1 Place loads above pool /RPVin safe Bases confrguration
'38.1 R1 4.8.A.2.b Record survei!!ance results OAPD 3 8 '. R1 48A2a2 Record survei!!ance results OAPD 11 1
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ITS DOC CTS D2scription Location 3 8.1 92 4.8.A.2.c inspect DGs once per operating cycle UFSAR 3 8.3 R1 4.8.A 2.e Record DG fuel monthly and after QAPD DG use 3 8.3 R2 4.8 A 2 a i c Check proper air compressor UFSAR operation 384 R5 4.8 8 2.a Monitor battery room H2 TRM con ..nration 3.8.4 R1 3 8.8 2 a Provide portable battery rm TRM ventilntion equipment 384 R2 3 8 B 2.d 24 volt battenes a.xf chargers TRM operabdity 3 8.4 R2 3 8 B.1 24 voit batteries and chargers TRM operability 3.8 4 R3 4.8.B.1.c Det. specific gravity & voltage during Bases, QAPD disch test 384 P4 3 8.8 2 b Perform cross-train checks SFDP 386 R1 4.8.8 i b Measure and record Battery cell OAPD parameters 3.8.7 R1 3 8 C.2.a Details on operable distribution Bases system 3 8.7 R1 3 8 C.2 b Details on operable distributsn Bases system 387 R1 3.8.C.1 Details on operable distribution Bases system 3 8.7 R2 4 8.C.1 Inspect each essential AC breaker UFSAR 12
ES DOC CTS Descriphon Location 3.8.7 R3 3 8 B.2 b Perform cross-train checks SFDP 3 9.1 R1 4.9A1b Hoist load setpoints UFSAR 3 9.1 R1 4.9 A.1.a Hoist load setpo;nts UFSAR 40 R1 5 's RPV description UFSAR 40 R1 5.4 Containment desenption UFSAR 4.0 R1 5.6 Seismic design details UFSAR 40 R2 1.37 Definition for Site Boundary UFSAR 50 R1 6.4.2 Fire Protecticu Program UFSAR 50 R1 6 1.2 Fire Protection Program Fire Plan 50 R10 6 8.5 Preventative and corrective UFSAR maintenance program 5.0 R11 6 9.2 notes **, *** Radiation measurement distances Added to ITS per NRC question 5.0-8 50 R12 6.9.4.b Radiological Environmental ODAM Monitoring Program 50 R13 7 9.5 Sourceleakage tests TRM,QAPD 5.0 R13 695 Source leakage tests TRM QAPD 50 R14 6.10 Record re'ention OAPD 50 R15 6.11.1 a Startup Report QAPD 50 R10 6.6 1.b Reportable Event Action
- QAPD 50 R17 6.15 Proc.ess Control Program OAPD 13 i
,lTS .D O C CTS Desertcihn Location 50 R18 32.1 Monitonng (Fs downstream of off- TRM gas recomt:siers 50 R18 42.1 Monitoring gas enunstream of off- TRM gas reco;nbiners 50 R19 3.14 3 Liquid k.uup tank instrumentation ODAM 50 R19 414 B Liquid holdup tank instrumentation ODAM S0 Rt3 4.14. A Liquid holdup tanks ODAM 5.0 R19 3.14 A Liquid holdup tanks ODAM 5.0 R2 6.1.3 OR Program QAPD 50 R20 4 8 A 2.f Testing new and stored DG fuel oil Bases. QAPD 50 R20 4.8.A.2.g Testing new and stored DG fuel oil Bases 50 R20 48A2.d Testing new a.x! stored DG fuel oil Bases 50 R3 611.2 a 2 LilGR TRM 5.0 R4 Table 6.2-1 Minimum shift crew and license ZSAR requirements 5C RS 6 3.4 Training requirements for plant UFSAR management 50 R6 64.1 Staff training requirements UFSAR S0 R7 6.5 Review and audit functions QAPD 50 R8 6 9.1 Radiation protection procedt.ms UFSAR 50 R8 681.12 lodine Monitorbg Program UFSAR S0 R9 6 8.2 Review and approval process QAPD 14
ES DOC CTS Description Location fa R9 683 Temporary change process OAPD CTS 3.11 R1 3.11 River I.evel TRM CTS 3.2.D R1 3.2.D Radiation Momtoring Instrumentation ODAM CTS 3 5 B R1 3.5 B Drywell Spray TRM l CTS 3 6 B 2 R1 3 6.8.2 Chemistry TRM C TS 3 6 G R1 36G StructuralIntegrity TRM CTS 3 6 H R1 3 6.H Snubbers TRM,QAPD CTS 3 7 M R1 3.7. M MechanicalVacuum Pump TRM.ODAM CTS 411 R1 4.11 River Level TRM CTS 4 2 D R1 4.2.D Radiation Monitoring Instrumentation ODAM CTS 4.EB R1 45B Drywell Spray TRM l CTS 4 6 B 2 R1 4 6 B.2 Chemistry TRM CTS 4 6 G R1 46G StructuralIntegrity TRM CTS 4.6 H R1 4 6.H Snuboers TRM,CAPD C TS 4.7.M R1 4 7.M MechanicalVacuum Pump TRM,ODAM TRM T 3 3.1 R1 Table 3.2-G ARI trip Level settings UFSAR TRM T 3.3 2 R1 Table 3.2-C Rod Block trip Level settings UFSAR TRM T 3.3.3 R1 Table 3.2-H Various details for PAM instruments TRM Bases TRM T 3.3.6 R1 Table 3.2-F Total channels for Surveillance inst UFSAR 15
w _ _ _ _ _ _ _ _ _ _ . _ _ 5 DOC CTS Description Location US TRM T 3 3.7 R1 4.2.1.1.b Perform inst ca! for hydrogen TRf1 Bases monitors TRM T 3 3.7 R1 3 2.11. Note " Locaten of hydrogen sampling points TRM Bases TRM T 3.7.2 R1 4 6.H 4 Required engineering evaluation far TRM Bases snubbers TRM T 3 7.2 R2 46H8 Documentation requirements for QAPD snubber-TRM T 3.7.4 R1 3 7.M 2 Max allowed rad release rate for ODAM me.h vac pump TRM T 3 81 R1 4.8 B 1.c Record specific gravity / voltage each TRM Bases 24VDC ce!! TRM T 3 9 R1 f.9.5 B Repcrting requirements for sealed QAPD sources
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Enclosure 3 to NG-99-0342 IES Responses to NRC Questions on the DAEC ITS Conversion
DAEC ITS 3 3.6.1 PRIMARY CONTAINMENT ISO'. ATION INSTRUMENTATION 3.3.6.1 DOC JFD CHANGE / DIFFERENCE COMMENT STATUS 1 MS P44 Footnots (d) is added to ITS Table 3.3.6.1-1 and Change the ITS Table 3.3.6.1-1 to list applies to Function 5.b for RWCU Area Temperature - each area as a separate TS function High and to Function 5.c for RWCU Area Ventilation consistent with STS format. Differential Temperature - High. Footnote (d) prop 7ses to require each RWCU area to an operable 5.b or 5.c channel. The proposed Table has four roorr.s identified with each TS Function 5.h and 5.c. DAEC Response: Per our conference call with the Staff en February 18,1998 change M.5 and P.44 will be withdrawn. The Staff indicated that control of the spatial coverage of the RWCU instrumentation was not necessar,< in the specifications. Retention of ITS channe' requirement is acceptable. Control of spatial coverage can be acceptably maintained under licensee control. Proposed footnote (d) will be de!cted and "1" will be inserted in ths Required Channels c; mn for Functions 5.b and 5.c. Subsequent Footnotes (e) and (i) will be re-ordered accordingly. The revised ITS mark-up, ITS and Bases changes, along with corresponding DOCS and JFDs are enclosed. 2 P26 STS 3.3.6.1 contains only a ? 2 hour Channel Check Provide iustification for STS deviation. (SR 3.3.6.1.1); a 92 day and 184 day Char.nel include discussion based on current Functional Test (SR 3.3.6.1.2 and 3.3.6.1.5, licensing basis, system design, and/or respectively); and a 92 day and 18 month Channel operational constraints. Calibration (SR 3.3.6.1.4 and 3.3.6.1.6, respectively). ITS SR 3.3.6.1.8, which requires a Channel Calibration every 24 months, is added to the STS 3.3.6.1 SRs without justification. In addition, surveillances for ITS Table 3.3.6.1-1, Functions 4.c, 5.b, 5.c, and 5.f are based on an unrefe-enced setpoint analysis for PCIS Functions. This analysis should be identified. DAEC Response: ITS SR 3.3.6.1.8 was inadventently not listed in JFD P.26. P.26 has been revised and includes appropriate discuss;on of the CLB, system design and operating constraints. ITS Table 3.3.6.1-1 Functien 4.c setpoint analysis is described in P.62. Functions 5.b,5.c and 5.f are plant specific design for RWCU Steam Leak Detection temperatures as dascribed in P.9. The AVs for these functions were determined in accordance with the DAEC setpoint control program. I _. u
i DAEC ITS 3.3.6.1 PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION l t 3.3.6.1 DOC JFD CHANGE / DIFFERENCE COMMENT STATUS l l ! 3 R10 HPCI and RCIC initiation signals which isolate Reject the relocation of these CTS contain.nent are proposed to be relocated because its requirements. These manualisolation an uncommon practice to TS these isolation functions. functions should be retained for overall redundancy and diversity of the isolation ; function as required by the plant { licensing basis. ! DAEC Response: The HPCI and RCIC iS Aem initiation isolation functions are necessary to ensure the respective systems will perform their design functions. These isolation signals are generated when the associated systera initiates and results in closure of associated ; system steam line drains and the discharge line to radwaste (i.e., the Group 8 valves referenced in Table 3.2-A). The relocation of the i details concerning these isolation functions to the Bases of 3.5 means that the functions are being maintained in the ITS. ITS SR 3.5.1.7 i is a 24 month test that verifies that the HPCI subsystem actuates on an actual (or simulated) automatic initiation signal. ITS SR 3.5.3.5 , is a 24 month test that verifies that the RCIC System actuates on an actual (or simulated) automatic in;tiation signal. Per the associated Bases for these SRs, the tests verifies, in addition to other system functions, such as pump starts, that all valves reposition to their l accident positions, which includes the Group 8 valves. Per CTS Table 4.2-A, the only SR for this function is a Channel Functional Test I (CFT) which is performed "once each Refuel Cycle," (i.e., every 18 months). There are no instruments to calibrate, a the logic is initiated by limit switches on the system steam supply valves. Thus, the CFT of 4.2-A is functionally equivalent to the ITS automatic actuation ' test. If these valves do not close during this test (or are known to be inoperable any other time the associated system is required to be Operable), then the associated system is declared inoperable immediately per ITS SR 3.0.1. However, in the CTS, one hour is allowed j before the system is declared inoperable, per Action 23. Thus, the ITS is slightly more restrictive, but has the san;e functional ; requirements as CTS. Since the Operability of these functions is maintained in the ITS, then the relocation of the details in CTS Table ! 3.2-A is acceptable. DOC R.10 has been revised accordingly and a new DOC (M.8) has been written for the change in Completion Times , (attached). The revised CTS mark-up pages will be submitted in the next Revision of the ITS (Rev. C). l r i t i l I
DAEC ITS 3.3.6.1 PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION 3.3.6.1 DOC JFD CHANGE / DIFFERENCE COMMENT- STATUS 4 L3 CTS Table 3.2-A applies Action 23 to the Reactor Provide additional discussion and Water Level-Low isolation signal for the RHR Shutdown justification including the protection ! j Cooling System. Action 23 requires closing the provided by manual actions. Revise the affected system isolation valves within one hour and DOC to be consistent with the proposed , declaring the affected system inoperable. ITS 3.3.6.1, TS Bases. Required Actions J.1 and J.2, require immediately initiating action to restore the channels to Operable ! status or immediately isolating the RHR-SDC System. The DOC states RHR-SDC System isolation is not required if Action is proceeding on a continuing basis to restore the inoperable channel (s) to Operable status. l The Bases state that actions must continue until the channel is restored or the system is isolated. Justification is based on the available manual isolation of the RHR-SDC. This justification for change of l Required Action does not discuss manualisolation with loss of vessellevelindication and provides a basis that is different from proposed Action J Bases. DAEC Response: The protection provided by manual actions to isolate RHR-SDC includes mitigation of a low energy pipe break in RHR SDC system piping to prevent RPV draindown while in a shutdown condition. DOC L3 has been revised to be more consistent with the ; Bases. (Not? that due to other changes, Action J is now Action I for ITS 3.3.6.1). 1
DAEC ITS 3.3.6.1 PRIMARY CONTAINMENT ISOLATIGN INSTRUMENTATION 3.3.6.1 DOC JFD CHANGE / DIFFERENCE COMMENT STATUS 5 L.6 The ITS proposes to delete the reactor low, low, low Provide additional discusion and
- level Group 7 isolation function. This function isolates justifi::ation showing that valves required the RBCCW which is a closed system. Other reactor to be operable by TS are not requireu by .
i Iow, low, low water level isolation functions are the safety analysis assumptions to have ! retained. The justification for the proposed changes their automatic iso'ation functions replace a TS requirement with a commitment that has operable. : no regulatory consequences. GDC-57 isolation valves are included in TS 3.6.1.3. DAEC Response: Tho Group 7 systems whose isolation functions are being deleted comply with GDC 57 requirements by utilizing remote manual closure capability. Therefore, the automatic isolation function is not required to meet the GDC 57 requirements. The DBA analysis assumes that within approximately 60 seconds of the accident, isolation of the primary contaiment is complete and leakage is terminated, except for the maximum allowable leakage rate. The primary containment isolation total response time of 60 seconds includes signal delay, diesel generator startup (for loss of offsite power), and PCIV stroice times. Isolation valves on process lines that communicate directly with the reactor vessel are required to reach the fully closed position in various times less than 60 seconds in order i to limit vessel inventory loss to prevent level from dropping below the top of active fuel (UFSAR, Section 7.3.1.1.1.7). The systems , included in Group 7 do not communicate directly with the reactor vessel nor the reactor coolant pressure boundary. The automatic ! isolation functions of these valves are not required to be operable to support the safety analysis assumptions. 6 M6 P25 Change are proposed to add Actions A.2 and Condition Provide additional d.:cussion and K to pre act the primary containment from inadvertent justificatior' for the proposed changes to spraying :n1 to ensure the availability of suppression explain the plant unique design which pool cooling when required. These changes are new to requires the addition of Condition k. i the CTS and to the ITS, therefore, the changes require Evaluate the generic applicability of the
- approval by technical staff. In addition, the proposed proposed changes. -
act i ons allow indefinite operation in the inhibit' mode if a single channel is inoperable. The DOC does not Note: DOC L11 is based, in part, on the justify indefinite operation with the SPC inhibited. acceptance of DOC M.6 justification. ; I i I l
f DAEC ITS 3.3.6.1 PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION
.JFD CHANGE / DIFFERENCE COMMENT STATUS 3.3.6.1 DOC DAEC Response: As discussed in JFD P.25, this Function is continued in the CTS (see CTS mark-up pages 90 and 92 of 117) and is added to the ITS. Because the drywell sprey function has been screened out of the ITS, CTS Action 30 had to be modified to ensure that l the proper Actions would be taken in the ITS (new Required Action A.2 and Condition K). There are several methods available to the I operators to inhibit the spray Function. Depending on the method chosen, Suppression Pool Cooling may or may not be affected. If the method chosen to inhibit appression Pool sprays also causes Suppression Pool Cooling to be inoperable (i.e., by virtue of failing to meet SR 3.6.2.3.1), then the appropriate Required Action from 3.6.2.3 would be entered (i.e., Conditions C or D) in addition to Suppressioq Pool Spray per LCO 3.6.2.4. Therefore, indefinite operation with SPC inhibited is not allowed by 3.3.6.1 Required Actions A.2 and Condition K. Note also that Containment Spray can ba inhibited without affecting SPC, as explained on Bases pg. B.3.3-178. Thus, these changer se necessary to properly convert the CTS to the ITS format.
7 L.10 CTS Table 3.2-A Note (a) contains a 6 hour Allowed Provide additional discussion and Outage Time (AOT) for testing for the isolation justification providing summary Function of RWCU Differential Flow - High. The AOT information of historical test times for is extended to 12 hours in ITS 3.3.6.1 justification is completing the stated SR and indicate based on availability of temperature monitorir$g to the degree to which testing resulted in isolate the RWCU System during the testing interval adverse impacts on reactor operations. and the 6 hour AOT is not adequate to allow for a Channel Calibration of this Function without requiring extra resources and personnel. This change extends the CTS 6 hour Allowed Outage Time (AOT) to 12 hours. DAEC Response: Per our discussions with the Staff in our conference call on January 14,1998, we have re-reviewed the topical reports upon which the AOT allowances are based and concluded that our design is the same as the "model" plant. Consequently, we have agreed to withdraw the extra AOT allowance and adopt the standard 6 hour AOT. DOC L10 and JFD P.43 have been revised accordingly (attached). In addition, the Bases are proposed to be modified consistent with the changes being made to the Bases of ITS 3.3.5.1 and 3.3.5.2 (Ref. Response to Questions 3.3.5.1-1 and 3.3.5.2-1, respectively) for similar channels with series components. The revised ITS and Bases changes will be submitted with the next ITS submittal. ____-. = = . . _ _ . . ..
w n DAEC ITS 3.3.6.1 P9tMARY CONTA!NMENT ISOLATION INSTRUMENTATION DOC JFD CHANGE / DIFFERENCE COMMENT STATUS 3.3.6.1 8 L.11 CTS Table 3.2-B, Action 30, with more than one Provide additional discussion and af fected Containment Cooling System isolation Channel justification to support the application of of Containment Pressure - High inoperable, requires Tcpical Report 24 hour AOT for the declaring the associated system inoperable containment cooling function. immediately. ITS 3.3.6.1, Required Action A.2, allows 24 hours before any action is required. The STS 24 hour AOT is based on a staff approved topical report. DAEC Response: The Required Action provided for Function 7.a is in addition to STS. Required Action A.2 requires that within 24 hours the containment sprays be inhibited. If a Function 7.a channelis placed in trip per Required Action A.1, containment integrity codd be l threatened due to exceeding the containment negative design pressure limit. Inhibiting the containment sprays from spraying both the drywell and the suppression chamber removes this threat. The 24 hour Completion Time is consistent with the time allowed to place the j channel in trip, which itself is cons 4 tent with the NUREG. 9 L.14 CTS Table 3.2-A applies Action 22 to the Main Steam Correct DOC L14 to correct ti e request Line Pressure - Low Isoft.aon Function. Action 22 for a 12 hour SR extension. requires the plant in r 3ast Startup within 6 hours. ITS 3.3.6.1, Required Action E.1, allows 8 hours for achieving Mode 2 under the same circumstances. The Completion Time to reach Mode 2 allows for a controlled plant shutdown. The DAEC determined, ' based on reviews of recent plant controlled shutdowns, that 6 hours is not sufficient to reach Mode 2 from 100% RTP. This change extends the Completion Time from 6 hours to 8 hours. DAEC Response: DOC L.14 has been revised to refer to this change as a 2 hour extension versus a 12 hour extension.
i DAEC ITS 3.3.6.1 PRIMARY CONTAIMMENT ISOLATION INSTRUMENTATION , t 3.3.6.1 DOC JFD CHANGE / DIFFERENCE COMMENT STATUS 10 L.15 STS 3.3.6.1 Actions are modified in ITS 3.3.6.1 Delete this proposed change. RPS SR Actions by a Note delaying entry into the Conditions Notes are based on epproved topical , and Required Actions for two hours, reflecting plant reports. Provide a revised topical report ! operating practice of not entering Required Actions for for staff review and approval. Conditions caused by performing Surveillance Requ;rements. This operating practice is not part of CTS 3/4.2. This position was communicated to the NRC staff in correspondence regarding the DAEC GL 89-10 Motor-Operated Valve (MOV) Program (J. Franz (IES) to W. Russell (NRC), " Generic Letter 59-10 Program," NG-94-4017, November 30,1994). CTS Completion Time is extended 2 hours by this change DAEC Responsen Per our Response to the Staff's RAI on this Note (Ref. NG-97-1597) and our meeting with the Staff on September 9, 1997, this change (L.15) will be withdrawn. The associated DOC (L15), No Significant Hazards Cor. sideration (NSHC) and JFD (P.63) have been revised (attached). i f l j !
i ) DAEC ITS 3.3.6.1 PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION F 4 3.3.6.1 DOC JFD CHANGE / DIFFERENCE COMMENT STATUS 11 L.AV This change revises CTS Tuble 3.2-A Trip Level Acceptance of these changes for ITS is OOS Settings in ITS Table 3.3.6.1-1 instrumentation to outside the scope of TBS review and are reflect Allowable Values rather than setpoints fcund in contingent upon NRC approval of NEDC-the plant procedures. These Allowable Values are 31336 and its applicability to DAEC estab ished by DAEC Instrument Setpoint Methodology Instrument Setpoint Methodology which is based on the General Electric (GE) Instrument program. Setpoint Methodology; NEDC-31336, General Electric Instrumentation Setpoint Methodology, The CTS Limiting Safety System Settings Allowable Vaiue for Reactor Vessel Low Water Level, CTS 2.1.b, Nuclear System Low Pressure, CTS 2.1.F, Reactor Low Water Level, CTS 2.1.1, Loss of Main Condenser Vacuum, CTS 2.1.J and Reactor Vessel Dome Pressure, CTS 2.2.E, are the same as the CTS Table 3.2-A setooints. The ITS Allowable Value are changed in the non-conNrvative direction, thus extending the CTS Limiting Safety System Setting beyond the plant licensed value. This is a misapplication of NEDC-31336. DAEC Response: The subject of setpoint control has been addressed in a seperate DAEC response to a Request for Additional Information (RAI); letter J. Franz (lES) to USNRC, NG-97-1010, dated June 10,1997. It is our understanding that the Staff's review cf the DAEC's conversion to the Allowable Values (AVs) in the ITS is complete and there are no additior.at questions. i t
DAEC ITS 3.3.6.1 PRIMAi4Y CONTAINMENT ISOLATION INSTRUMENTATION CHANGE / DIFFERENCE COMMENT STATUS 3.3.6.1 DOC JFD 12 L.lC The Frequency of performing the Channel Calibration This extension of Surveillance Test surveillance of CTS 4.2.A.1 and 4.2.3.1 and CTS Interval is outside the TSB scope of OOS Tables 4.2-A and 4.2-B is extended in ITS SRs review. 3.3.6.1.7 and 3.3.6.1.8 to facilitate a change to the plant operating cycle from 18 month to 24 months. Acceptance of this chanDe is contingent Historicial date was utilized to validate that vendor- upon NRC approval of NEDC-31336 and specified drift was conservative or utilized directly its applicabi*ity to DAEC Instrument using the second moment about zero (SMAZ) method Setpoint Methodology program. described in NEDC-31336- A. ITS Table 3.3.6.1-1, extends the Surveillance Frequency for Functions 1.a, 2.a, 3.a, 3.b, 3.d, 4.a, 4.b, 4.d, 5.a, 6.b, 6.c and 7.a from the current 3 month Surveillance Frequency to a 24 month Surveillance Frequency; and, for ITS Table 3.3.6.1-1, Functions 1.d, 3.e, 3.f, 3.g, 3.h, 3.1, 4.e, 4.f, 4.g, 4.h, 4.I, 5.b, 5.c and 5.f, from the current 12 month Surveillance Frequency to a ' i month Surveillance Frequency. In additic 'he current 3 month Surveillance Frequency for :S Table 3.3.6.1-1 Functim 5.e, is extended to a 12 month Surveillance Frequency. DAEC Response: Based upon our meeting with the NRC Staft on September 10,1997, we understand that the technical resources have been applied to review our conversion from an 18 month to 24 month operating cycle in parallel with our ITS cenversion. Consequently, this item is considered to be back within scope for the purpose of our Final Safety Evaluation on the ITS conversion. l l l J
DAEC ITS 3.3.6.1 FRIMARY CONTAINMENT ISOLATION !NSTRUMENTATION CHANGE / DIFFERENCE COMMENT STATUS 3.3.6.1 DOC JFD _ L.CY The Frequency of performing the Channel Calibration Acceptance of these changes for ITS is 13 surveillance of CTS 4.2.A.1,4.2.D.1, Table 4.2-A and outside the scope of TBS review and are OOS Table 4.2-D,4.1.A.1, and Table 4.2-A is extended in contingent upon NRC approval of NEDC-ITS SRs 3.3.6.1.8 from 18 months to 24 months. 31336 and its applicability to DAEC Historical as-found and as-left data was utilized to Instrument Setpoint Methodology validate that assumptions of va!ues for vendor- program. specified drift were conservative. Where these assumptions were not validated, historical drift was utilized directly using the second moment about zero (SMAZ) method described in NEDC-3133Q. DAEC Response: Based upon our meeting with the NRC 'itaff on September 10,1997, we understand that the technical resources have been applied to review our conversion from an 18 month to 24 month operating cycle in parallel with our ITS conversion. Consequently, this item is considered to be back within scope for the purpose of our Final Safety Evaluation on the ITS conversion. L.CY The Frequency of performing the Logic System Acceptance of these changes for ITS are 14
-2 Functional Tests r. quired by CTS 4.2.A.2, CTS outside the scope of TBS review and are OOS 4.2.8.2, and CTS 4.2.D.2 are extended in ITS SRs contingent upon staff extending the STI 3.3.6.1.9 to facilitate a change to the plant operating to 24 months.
cycle from 18 months to 24 months. The extension of the Surveillance Test Interval is based on a ten year review of surveillance test failures and review of the database for 10CFR50.65 (Maintenance Rule). DAEC Response: Based upon our meeting with the NRC Staff on September 10,1997, we understand that the technical resources have been applied to review our conversion from an 18 month to 24 month cperating cycle in parallel with our ITS conversion. Consequently, this item is considered to be back within scope for the purpose of our Final Safety Evaluation on the ITS conversion.
m - DAEC ITS 3.3.6.1 PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION I STATUS 3.3.6.1 DOC. JFG CHANGE / DIFFERENCE COMMENT I 15 L.9 CTS Table 3.2-A requires Operability of the isolation Function of Offgas Vent Stack- High Radiation during venting or purging of primary containment at any time when primary containment integrity is required. CTS Table 4.2-A requires Surveillance Requirements (SRs) for the Offgas Vent Stack - High Radiation Function performed in Modes 1,2,3 and when handling irradiated fuel in the secondary containment and during Core Alterations and Opera *:ons with a Potential for Draining the Reactor Vessel (OPDRVs). CTS Table 4.2-A requires SRs performed for Modes and conditions outside the Modes of Applicability in CTS Table 3.2-A. The Modes 1, 2,3 and when handling irradiated fuel in the secondary containment and during Core Alterations and OPDRVs requirement for this Function in Table 4.2- , A is replaced in ITS Table 3.3.6.1-1, with a requiremerit for the SRs being current during venting or purging of primary containment when primary containment integrity is required. This change is justified based on the Offgas Vent Stack - High Radiation Function only performing a primary containment isolation of the vent and purge paths. This justification is weak. Other isolation functions are surveilled and required Operable in Modes when they may be used, not when they are actually in use.
DAEC ITS 3.3.6.1 PRIMARY CONTAINMENT ISOLATION lie $TRUMENTATION i 3.3.6.1 DOC ! JFD CHANGE / DIFFERENCE COMMENT St'ATUS
- m-DAEC Response: Per the NSHC for DOC L.9, the Offgas Vent Stack-high radiation function is only assumed to provide an isolation signal to the primary vent and purge valves and is not assumed to isolate secondary Containment or start the Standby Gas Treatment System.
The isolation is initiated to limit the release of fission products should a LOCA occur, while the primary containment is undergoing vent or purge operations. At other times, these valves will be closed per LCO 3.6.1.3, therefore, the function is not required to oe operable. Based on discussions with the NRC Staff on January 14,1998, DOC L9 has been revised to provide this additiona!information (attached). l l 16 L.8 P57 CTS Table 3.2-A and STS Table 3.3.6.1-1 includes the Provide a safety analysis basis for l Manual Initiation Functions for RCIC and HPCI. These deleting this requirement. . Functions are deleted in ITS Table 3.3.6.1-1. Their removalis based on a lack of specific UFSAR safety I analysis that takes credit for these Functions. DAEC Response: Per our discussions with the Staff in our conference call on January 27,1998, this change has been characterized es i "beyoad scope" for the ITS conversion. Thus, in order to expedite the NRC's review and issuance of the SER. we have agreed to i withdraw this change from the conversion and re-submit it at a later date as an individual change. DOC L8 and JFDs P.26, P.57 and P.65 have been revised accordingly (attached). The revised ITS and Bases changes will be submitted in the next revision of the ITS. [ t 17 The bases for T3.3.6.1-1 function 2.e, Main Steam Provide a JFD discussion fo this change la tunnel ternperature state that 2 channels per to the STS. Explain the trip system l steam line are required to be operable for a total of 16 configuration for this function. channels. The table requires 4 channels per trip system in place of the "B" provided in S1S. l L i
l DAEC ITS 3.3.6.1 PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION I 3.3.6.1 DOC JFD CHANGE / DIFFERENCE COMMENT STATUS DAEC Response: The reference to Function 2.e in this question seems to be in error. Function 1.e is Main Steam Line Tunnel Temperature - High. The ITS Bases for Function 1.e states sixteen channels.... are available and later defines a channel as consisting of an RTD and its contacts that input into its associated temperature switch. DAEC has four Main Steamlines, with 4 sensors (RTDs) arranged along each steamline. The sixteen channels (sensors) make up 2 trip systems, cach comprised of 8 channels. ITS Table 3.3.6.1-1 appropriately requires 4 channels (out of 8 available) per trio system to be Operable. This is consistent with CTS Table 3.2-A (See DOC R.4 regarding footnote (o) to CTS Table 3.2-A.) No JFD is necessary a; the STS " brackets
- the number of channels, indicating that the plant-specific value should be inserted.
18 RS, Relocated information is not justified. Provide edditional discussion for the DOC R6 which justifies the proposed change to CTS. 4 DAEC Response: See Relocated items Matrix. DOC R.5 has been revised to reflect that portions of the change have been recategorized (see attached revised DOC R.5 and new DOC's A.9 and M.9). 19 P42 Table 3.3.6.1-1 Note (c) is proposed as a replacement Revise the Table using Note (c) as a of Modes 1,2,3 for Offgas Vent Sack Radiation modifier of Modes 1,2,3. Revise Monitor. Required Action L2. Revise Table Proposed Required Action L.2 should be changed to 3.3.6.1-1 to include an Allowable Value. reference the use of " continuous" alternate monitoring methods. i Table 3.3.6.1-1 references the ODCM in place of Allowable Value for radiation monitor. DAEC Response: ITS Table 3.3.6.1-1 Note (c) is identic'l to CTS Table 3.2-A Note (m). However, based on our conference call with the Staff on February 18,1998, Table 3.3.6.1-1 will be revised to include Modes 1, 2, and 3 modified by Footnote (c). ITS Table 3.3.6.1-1 ' note (b) for Function 2.c is ' 3ntical to CTS Table 3.2-A Note (k). No requirements have been changed by these proposed revisions in nomenclature; DAEC propo es to maintain the CLB for these two specifications. Required Action L2 has been previously revised to i "continueus" (See Rev. C package). The revised CTS mark-up, ITS cnd Bases changes to add the Applicability for Modes 1,2 and 3 to l Table 3.3.6.1-1, along with the corresponding DOC (new DOC A.10) and JFD changes are enclosed with the Rev. E package. i
x - . DAEC ITS 3.3.6.1 PRIMARY CONTAINMENT ISOLATION INSTRUMENTATION 3.3.6.1 DOC JFD CHANGE / DIFFERENCE COMMENT STATUS 20 P43 Deterministic criteria are used to extend CTS SR Revise the SR 3.3.6.1 requirements to ellowed outage times to 12 hours from 6 hours for adopt the topical report AOT allowances. RWCU differential flow high. In the STS the SR AOT is based on staff approved topico! reoort. DAEC Response: See Response to Question 3.3.6.1-7. P62 Revised HPCI Turbine Exhaust function allowable Acceptance of these changes for ITS l 21 I OOS values. outside the scope of TSB review and ar' contingent upon NRC approval of NEDC l 31336 and its applicability to DAEC instrument Setpoint Methodccogy L program. DAEC Response: See Response to Question 3.3.6.1-11. The subject of setpoint controi has been addressed in a separate DAEC response to a Request for Additional Information (RAI); letter J. Franz (lES) to USNRC, NG-97-1010, dated June 10,1997. It is our understanding that the Staff's review of the DAEC's conversion to Allowable Values (Avs) in the ITS is complete and thcre are no additional questions. 22 ITS containment cooling system isolation on t gh Provide a number of channels per trip containment pressure proposes four channels per trip system which is consistent with the system. CTS is four channels per trip function. design. Discuss any CTS differences with a DOC. DAEC Response: For Function 7.a, the four pressure switches (channels) provide input to both relay logics via the channel output relays and theE contact configuration simlar to the standard ECCS logic. As a result, there is actuelly only one " trip system" for this Function in the practical sense. Therefore, ITS Table 3.3.6.1-1 is not a proposed change to CTS Table 3.2-8 or the CLB. No DOC is required. However, as a result of our conference call with the Staff on January 14,1998, the Bases for this Function will be enhanced to further elaborate on this commonality of logic between the output trip systems. The revised Bases page will be submitted with the next revision of the ITS.
DAEC ITS 3.3.8.2 REACTOR PROTECTION SYSTEM (RPS) ELECTRIC POWER MONITORING September 16,1997 DOC JFD CHANGE / DIFFERENCE COMMENT STATUS 3.3.8.2 1 L.CY The Frequency of performing the Channel Calibration The extension of the CTS Surveillance } survei!iance of CTS 4.1.B.2 for the RPS Electric Power. Test interval is outside the TSB scope of OOS Monitoring System is extended by ITS SR 3.3.8.2.2 from review. 18 months to 24 months. The justification for this l Su,vei!!ance Interval extension is based, in part, on Revise the justification for this surveiffance instmment Channel Che.cks. However, CTS 4.1.B.2 does extension with a justification that is not not require Channel Checks. based on instrument Channel Checks. DAEC Response: DOC LCY for ITS 3.3.8.2 has been revised to eliminate the discussion of Channel Checks (attached). 2 A.2 CTS 3.1.B for the Reactor Protection System - Electricai Revise the submittal, as appropriate, to include Mode 3 and Mode 4, when a Protection Assemblies (RPS-EPAs) does not contain a specific Applicability statement. The proposed ITS control rod is withdrawn. Applicability specified in ITS 3.3.8.2 IS consistent with the applicability of the ITS RPS Functions of ITS 3.3.1.1, Modes 1 and 2, and Mode 5 when any control rod is withdrawn from a core call containing one or more fuel assemblies. However, that Applicability does not support requirements given in special operations TS. DAEC Response: The RPS-EPAs are solely a support system and as such, are on!v required to be Operable whenever their " supported" system (RPS in this case) is rec; aired to be Operable. As discussed in JFD P.46, the only time a control rod is allowed to be withdrawn in Modes 3 or 4 and hence, the corresponding requirement for RPS ;o be Operable in these Modes, is under the corresponding "Special Operation" LCOs (i.e., LCO 3.10.3 and 3.10.4, respectively). Therefore, the requirement for the RPS-EPAs to be Operat,le has been " moved' to these Special Operations LCOs as well. This format is consistent with the Writer's Guide and the STS for the "Special Operations" LCOs to be " stand alone" requirements. Because no technical requirements have been changed, this is a presentation preference, which is considered to be l Administrative in nature. Based on discussions with the NRC Staff on February 9,1998, ITS 3.3.8.2 will be revised to include requirements for Mode 3 and Mode 4. The revised JFD P.46 and revir,ed Specification and Bases are included in Revision E to the ITS. 1
DAEC ITS 3.3.8.2 REACTOR PROTECTION SYSTEM (RPS) ELECTRIC POWER MONITORING September 16,1997 3.3.8.2 DOC JFD CHANGE / DIFFERENCE COMMENT STATUS 3 None I either CTS 3/4.B.1 nor ITS 3.3.8.1 have time delay Resolve the discrepancy between ITS requirements associated with the RPS-EPAs. ITS 3.3.8.2 3.3.8.2 and the associated Bases. If there Bases, Background, discusses "after a short time delay (if is no time assumed delay in the applicable)." However, the SRs of ITS 3.3.8.2 do not overvoltage, undervoltage, or , have any rt;quirements for time delays associated with the underfrequency trip devices, the overvoltage, undervoltage, or underfrequency trip RPS- discussion in t% ITS 3.3.8.2 Bases, EPAs. Using the wording "after a short time delny (if Background, sbauld be revised to exclude applicable)" in ITS 3.3.8.2 Bases, Background, is not discussion of a possible time delay. appropriate in describing the RPS-EPAs. l DAEC Response: The DAEC design does include time delays. The reiocatiors of the specification for the time delay to the UFSAR was the specific subject of DAEC Amendment 185. The discussion in the Bases of ITS 3.3.8.2 accurately reflects the current DAEC design and licensing basis. The "if applicable" statement is added as the over voltage trip does not iriclude a time delay. 4 None CTS 3.1.B.1, with a Electrical Protection Assembly (EPA) Provide justification for this administrative for an in-service MG set or attemate power supply chcnge that changes from a specific CTS inoperat " ws 72 hours to either restore the allowance to an unspecified ITS allowance inoperabis ; A or remove the associated inservice power to restore the inoperable EPA to leave the supply from service. ITS 3.3.8.2, Action A, for the same condition. condition, cllows 72 hours to remove the associated inservice power supply from service. There is no discucsion or justification conceming the CTS 3.1.B.1 allowance of 72 hours to restore the inoperable EPA that is not incorporated in ITS 3.3.8.2, Action A. DAEC Response: The format of the STS allows satisfying an LCO as a means of exiting a Condition and Required Action. In this case,if the inoperable EPA is restored within the given Completion Time, then LCO 3.3.8.2 is satisfied, and in accordance with LCO 3.0.2, completion of the Actions is not necessary. This is consister't with the CTS. The reformatting is justif by DOC A.1 to ITS 3.3.8.1.
.. . .. . ~
DAEC ITS 3.3.8.2 REACTOR PROTECTION SYSTEM (RPS) ELECTRIC POWER MONITORING September 16,1997 3.3.8.2 DOC .JFD CHANGE / DIFFERENCE COMMENT STATUS , 5 M.1 CTS 3.1.B.1 and 3.1.B.2, with inoperable EPAs, do not Revise the submittal ITS 3.3.8.2, Actions C cmtain actions that require exiting the applicability of the and D to make conforming changes to the EPAs. ITS 3.3.8.2, Action C, is added for Modes 1 or 2 to proposed ITS to accommodate the revised , requ;te a controlled shutdown to Mode 3 in 12 hours if applicability. . , Actions A or B are not met. ITS 3.3.8.2, Action D, is added to address Mode 5 with any control rod withdrawn ! from a core cell containing one or more fuel assemblies. < DAEC Response: See Response to 3.3.8.2-2. ; 6 none CTS 4.1.B.2 specifies setpoint " limits" for the following: Provide justification for this change that Overvoltage s 132-Vac changes the setpoint " limits" to Allowable Undervoltage 2108-Vac Values. Underfrequency 2 57 Hertz ! ITS SR 3.3.8.2.2 specifies the same limits as Allowable Values: Overvoltage s 132-Vac - Undervoltage 2108-Vac Underfrequency 2 57 ' rtz There is no justifice . for changing the setpoint " limits" ! to Allowable Value an administrative change that changes the nomenclature. DAEC Response: These AVs are derived from IEEE-STD-323-1974. There has been no change in ourinterpretat._ i of these values. The subject of setpoint control has been addressed in a separate DAEC Response to a Request for Additional Information (RAI); letter J. Franz (IES) l to USNRC, NG-97-1010 dated June 10,1997.
DAEC ITS 3.3.8.2 REACTOR PROTECTION SYSTEM (RPS) ELECTRIC POWER MONITORING September 16,1997 3.3.8.2 DOC JFD CHANGE / DIFFERENCE COMMENT STATUS 7 P46 The STS 3.3.8.2 Applicability includes Mode 3, and in Revise the submittal, as appropriate, to Mode 4 when a control rod is withdrawn. The ITS 3.3.8.2 include Mode 3 and Mode 4,when a Applicability does not include Modes 3 and - The control rod is withdrawn justification for this STS deviation states that ITS 3.10.3 and 3.10.4 require ITS 3.3.8.2 and the RPS-EPAs ' Operable in Modes 3 and 4. ITS 3.3.8.2 does not have any appropuate Actions (such as exiting the Applicability) if Actions for restoring inoperable RPS-EPAs are not completed within the specified Completion Time when the RPS EPAs are required in Modes 3 and 4. Therefore ITS 3.3.8.2 is not adequate in Modes 3 and 4, to support ITS 3.10.3 and 3.10.4. ; DAEC Response: See Response to Question 3.3.8.2-2, above. 8 P46 The STS 3.3.8.2 Applicability includes Mode 3. The ITS Revise the submittal, as appropriate, to 3.3.8.2 Applicability does not include Mode 3. The include Mode 3 and Mode 4, when a justification for this STS deviation states the purpose of control rod is withdrawn the ITS 3.3.8.2 instrumentation is to ensure the power produced by the RPS MG sets (and alternate source) is of a quality acceptable to the RPS. The RPS-EPAs do not cause a scram, they protect the RPS components from potentially damaging voltage and frequency dips, trarisients, and excursions. The justification states the Applicability for ITS 3.3.8.2 is consistent with the ! Apolicability of ITS 3.3.1.1. However, to fulfil the current - licensing basis per the SER associated with CTS Amendment 79, ITS 3.3.8.2 must be Applicable whenever RPS components are powered, not when the RPS is l required. _ _ _ _ - - _ - . - _ - _ _ - _ _ __---- -_------J
DAEC ITS 3.3.8.2 REACTOR PROTECTION SYSTEM (RPS) ELECTRIC POWER MONITORING September 16,1997 3.3.8.2 DOC JFD CHANGE / DIFFERENCE COMMENT STATUS DAEC Response: See Response to Question 3.3.8.2-2 above. t 9 P46 STS SR 3.3.8.2.1, Channel Functional Test, per the note, Make conforming changes to the picposed only requires performance prior to entering Mode 2 or 3 ITS to accommodate the revised from Mode 4, when in Mode 4 for 2 24 hours. ITS SR applicability. l 3.3.8.2.1, per the note, only proposes performance prior to entering Mode 2 from Mode 3 or 4, when in Mode 4 for 2 24 hours." DAEC Response: See Response to Question 3.3.8.2-2. I L (
DAEC STS 3.6.2.4 RESIDUAL HEAT REMOVAL (RHR) SUPPRESSION POOL SPRAY ITEM DOC / CTS /STS DESCRIPTION OF ISSUE DATE DATE COMMENTS NO. JFD LCO OPENED CLOSE D S3.6.2.4-1 P.17 STS 3.6.2.4 CTS 3/4.5.B " Containment 7/8/97 include CTS 3/4.5.B Bases and Spray Cooling Capability" in ITS 3.6. Provide P.8 Associated specifies the suppression pool additional discussions Bases and drywell spray MODES of and justifications for the RHR System OPERABILITY any changes made to requirements. STS 3.6.2.4 the CTS /STS. specifies the OPERABILITY requirement for the RHR Suppression Pool Spray. ITS 3.6 does not include STS 3.6.2.4 based on the premise that it does not meet the Criterion specified in 10 CFR 50.36(c)(2)(ii). The staff has determined and stated in the Bases of STS 83.6.2.4 that the RHR Suppression Pool Spray System does meet Criterion 3 of 10 CFR 50.36(c)(2)(ii). Since this system was in the CTS and the staff determination is that it meets Criterion 3, this specification should be included in 1::e ITS. However, STS 3.6.2.4 of NUREG-1433 may not be the appropriate TS in DAEC case, *
~
STS 3.6.1.7 "RHR Containment Spray System" of NUREG-1434 (BWR-6) may be , the more appropriate TS to b use. 1
DAEC STS 3.6.2.4 RESIDUAL HEAT REMOVAL (RHR) SUPPRESSION POOL SPRAY
! TEM DOC / CTS /STS DESCRIPTION OF ISSUE DATE DATE COMMENTS NO. JFD LCO OPENED CLOSE D
DAEC RESPONSE: NUREG 1433 was developed based on a lead plant in the BWR/4 line, Hatch Unit 2. Many of the specifications, parts of specifications, and descriptions of these specifications in the Bases, do not represent the design or specific accident ana'ysis assumptions used at the DAEC. Each plant choosing to convert to the improved Technical Specifications (ITS) must apply the four criteria in 10 CFR 50,36 (c) (2) (ii) to their Current Technical Specification (CTS) LCOs in order to determine the composition of the plant specific ITS, not the generic application of the screening criteria to the STS. The application of these criteria to the CTS LCOs is contained in the " Split Report" which was submitted to the staff in the ITS conversion package (volume 1). The DAEC plant specific accident analysis has been evalcated and this discussion is contained in the Split Report. The Split Report states in part, "...in the analysis of the boundmg event of the containment analysis and the suppression pool pressurization doe to bypass leakage, the drywell spray mode of RHR was , not utilized for mitigation of the event." and "...the use of suppression pool sprays was not a:sumed in the analysis of the maximum containment bypass leakage, and is not relied upon to mitigate the event." The Split Report for each plant that converts to the ITS must be reviewed by the Staff in order to make a determination of which LCOs are to be included in a particular plant's ITS. Therefore, since none of the Criteria are met for inclusion in the DAEC ITS, neither the drywell sprays nor the suppression pool s,nrays are required to be included. Notwithstanding the above, based upon extensive dialogue with the Staff, as finalized in our conference call of February 2,1998, the DAEC has agreed to re-categorize this change as "beyond scope of the cc... version." This is being done solely to expedite the Staff's SER for the ITS conversion. The Staff did not raise any specific technicalissues with the relocation of the Suppression Pool Spray System from the CTS: they just did not have the technical resources available to complete their review on the ITS schedule. Consequently this item is planned to be re-docketed as a " stand-alone" change after the conversion is completed, when the Staff will have the resources availab!c +o finish their review. In the interim, the ITS has been modified to include an LCO for the Suppression Pool Spray System that is based upon the CTS requirements, the NUREG LCO and Bases were modified accordingly (attached) and corresponding changes to the CTS mark-up, DOCS and JFDs have also been enclosed. 2
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