ML20135F997

Forwards Comments on Written Exam Administered on 970505 Which Tested Six SRO Candidates Knowledge in Appropriate Areas

ML20135F997
Person / Time
Site:	Pilgrim
Issue date:	05/16/1997
From:	Olivier L BOSTON EDISON CO.
To:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
References
BECO-2.97-054, BECO-2.97-54, NUDOCS 9705230229
Download: ML20135F997 (26)

Text

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I 10CFR50.55 O

Boston EsSoors Pilgrim Nuclear Power Station Rocky Hill Road Plymouth. Massachusetts 02360 L J. Olivier.

Vice President Nuclear operat6ons and Station Director I

l May 16,1997 BECo Ltr. 2.97-054 U.S. Nuclear Regulatory Commission Region 1 475 Allendale Road King of Prussia, PA 19406 Docket No. 50-293 License No. DPR-35 l

Pilorim's 1997 NRC Written Examination Comments The written examination administered on May 5,1997, was considered to be an in-depth examination, which fairly tested the six (6) SRO candidate's knowledge in the appropriate areas. After thorough analysis of the content of the examination, it is clear that the use of misleading information, use of the double negative context, and the asking of subjects not important to public health and safetywere avoided.

However, specific requests on several written exam questions are submitted for your consideration in. Enclosure 2 contains the reference documentation associated with each of the requests.

Your consideration of these rBquests is greatly appreciated.

e L. J. Olivier

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oc: Mr. Don Florek Region 1 475 Allendale Road

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King of Prussia, PA 19406 Mr. Alan Wang, Project Manager Project Directorate I-3 Division of Reactor Projects - 1/11 Mail Stop: 1482 U. S. Nuclear Regulatory Commission 1 White Flint North 11555 Rockville Pike Rockville, MD 20852 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555 Senior Resident inspector Pilgrim Nuclear Power Station l

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ENCLOSURE 1 I

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ENCLOSURE 1 1.

Question # 32 While operating at 100% power, it is determined that the Main Steam Line High Flow switchos on the "B" Main Steam Line will NOT trip under a high flow condition.

Which ONE of the following is the MINIMUM REQUIRED action?

a.

Direct l&C personnel to manually trip the inoperable switches.

b.

Direct l&C personnel to manually insert a half Group i isolation on the "B" Group 1 Channel.

c.

Initiate an orderly shutdown and be in Cold Shutdown Condition within a MAXIMUM of 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> after the instrument failure.

d.

Initiate an orderly shutdown and have Main Steam Lines isolated within a MAXIMUM of 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> after the instrument failure.

ANSWER:

d.

DISCUSSION-The stem of this question states,"... it is determined that the Main Steam Line High Flow switches on the "B" Main Steam Line will NOT trip under a high flow condition..."

There are two trip systems associated with Group i PCIS, designated "A" and "B". Trip System "A" has eight inputs from MSL High Flow switches comprising two instrument channels, and Trip System "B" has eight inputs from MSL High Flow switches comprising two instrument channels; each steam line is equipped with four switches each, one for each instrument channel (Enclosure 2, Attachment 1, page 1).

The stem of the question states that all flow switches on the "B" Main Steam Line are inoperable. Since this is the case, there are less than two operable instrument channels for both PCIS logic trip systems. (See Enclosure 2, Attachment 1, Page 2)

Since there are less than the minimum operable instrument channels for both trip systems,, page 3 states, "If the minimum number of operable instrument channels cannot be met for both trip systems, place at least one trip system (with the most inoperable channels) in the tripped condition within one hour or initiate the appropriate action required by Table 3.2.A listed below for the affected trip function."

l Table 3.2.A requires action "B", which states, " Initiate an orderly load reduction and have Main l

Steam Lines isolated within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />".

i Since there is no grace period (of one hour) for the two trip system inoperability (vice the one trip system inoperability), there is no obvious correct response.

Page 1 of 10

REQUEST (Question # 321:

i Since the correct response is not offered as a choice in the responses, we request that this question be deleted from the examination.

REFERENCE:

PNPS Technical Specifications, Table 3.2.A and associated notes (Enclosure 2, ).

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Page 2 of 10

2.

Question # 76 The fo' lowing conditions exist-A steam leak occurs just upstream of the Main Turbine Stop Valves with both MSIV's in the "A" main steam line failing to close.

A reactor scram is successful in inserting all rods fully.

Both Main Stack Process Radiation Monitors have been reading 2.5+E4 for the last 25 minutes.

Off-site release rate projections are 2 R/ hour Whole Body at the site boundary.

Select the correct action and its reason.

Under these conditions, the preferred method of depressurizing tha RPV is using; L

a.

SRVs because of the scrubbing potential of the torus water.

l b.

SRVs because the heat removal capability is greater than the Main Turbine Bypass I

Valves.

c.

Main Turbine Bypass Valves because the hotwell is the preferred heat sink.

I d.

Main Turbine Bypass Valves because the heat removal capability is greater than the SRVs.

ANSWER:

b.

DISCUSSION:

Because both answer "a" and "b" select the SRVs as the correct mechanism of depressurizing, l

the question then becomes discriminatory as to the basis for doing so. Appendix B of the Emergency Procedure Guidelines states that Contingency #2, Emergency RPV Depressurization m'ay be required to-Minimize radioactivity release from the RPV to tne primary containment and secondary containment, or to areas extemal to the primary containment and secondary containment.

l Additionally, Appendix B states that the purpose of the Radioactivity Release guideline is to limit radioactivity release into areas outside the primary and secondary containments.

Since distracter "a' implies that SRV's are used because they discharge to the primary containment, "a" can be construed as the correct answer. That is, given the situation provided, the fact that the SRVs discharge to the containment via the torus is more significant than the fact that the SRV's heat removal capability is greater than the bypass valves.

Since Appendix B also provides generic guidance that SRV's are used because of their heat removal capability, "b" is also correct.

Page 3 of 10

L BEQUEST: (Question # 76)

Because both answers "a" and "b" are correct per the EPGs, we request that answers "a" and "b" both be accepted as correct, and the question be retained in the examination.

REFERENCE:

1.

Emergency Procedure Guidelines Appendix B, Section 11, Contingency #2 (OEI Document 8390-4B, (Enclosure 2, Attachment 2]).

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Page 4 of 10

3.

Question # 28 While operating at 100% power, a control rod is determined to be uncoupled. Attempts to couple the rod have been unsuccessful.

Which ONE of the following states the MINIMUM REQUIRED actions.

s.

Vetify the control rod can be moved with drive pressure and maintain the control rod at the target position.

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b.

Fully insert the control rod and hydraulically disarm the CRD.

c.

Fully insert the control rod and electrically disarm the directional control valves.

d.

Fully insert the control rod, electrically disarm the directional control valves and then declare the rod inoperable.

ANSWER:

c.

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DISCUSSION:

The only differentiation between distracter "d" and the correct answer "c" is whether the rod is declared inoperable.

If a control rod was uncoupled, it would be declared inoperable by Technical Specifications when the inoperability was discovered. The control rod would then be inserted and electrically disarmed to ensure control rod movement was precluded.

Taking this action does not eliminate the fact that the control rod was inoperable but does allow relief from the requirements of the associated Technical Specification actions for an uncoupled controf rod. The control rod that was uncoupled would still be administratively controlled as an inoperable control rod, even though the action statement of Technical Specification 3.3.F does not have to be applied. At PNPS, if an action has to be taken on the part of Technical Specifications, the equipment inoperability is traced through the application of an " Active LCO"in the LCO log.

From a Tech Spec cpnsideration only, the rod is not inoperable. However from an l

administrative and practical standpoint, the rod is indeed inoperable, and the Active LCO l

Is maintained to control the status of the rod. Therefore, if the candidate approached the l

question from this perspective, distracter "d" can also be considered as an acceptable answer.

While Procedure 2.2.87, 5.2.1[3] does state that a rod fully inserted and electrically disarmed is not inoperable, it references Tech Spec 3.3.A.2 that concems rods that cannot be moved with drive pressure. This statement does not apply to the conditions identified in the question.

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Page 5 of 10 l

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REQUEST: (Question # 28)

We request that distracter "d" also be accepted as correct.

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REFERENCE:

1 1.

PNPS 1.3.34.2 (See Enclosure 2, Attachment # 3) 3.0(1] " Active LCO" Definition 4.0 " Discussion" 2.

Operations Department Manager (Tom Trepanier, (508) 830-8364) l l

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Question # 50 in the event that torus water level cannot be maintained above 95 inches, HPCI is secured in order to prevent a.

exceeding the Primary Containment Pressure Limit.

b.

exceeding the Pressure Suppression Pressure.

c.

exceeding the Heat Capacity Temperature Limit.

d.

isolating HPCI on high exhaust pressure.

ANSWEFit:

a.

DISCUSSION:

The operators at PNPS are provided a " supplemental"' approved handout for the study of the EOP procedures (Enclosure 2, Attachment 4). In this handout, the basis for the 95 inches torus level securing of HPCI is not stressed as the PCPL The fact the exhaust will become uncovered is stressed, and HPCI will then directly pressurize the containment. The wording for the PCPL statement is "may exceed the PCPL", and not "the basis for the uncovery is the PCPL". When this question is considered, the fact that the primary containment would pressurize is a valid line of thought. From this direction, scrutinization of the choices through the use of the supplied EOPs would lead a candidate to choose the most limiting curve between the PCPL and the PSP. This would of course be the PSP curve. Based on this line of reasoning, response "b"is considered also to be a valid response.

REQUEST: (Question # 50)

We request that distracter "b" also be considered as correct.

REFERENCE:

EOP-03 Supplemental Training Materials / Flow Charts (Enclosure 2, Attachment 4)

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S.

Question # 29 With the plant at power, it is determined that the MO-1001-37 (B loop Torus Spray) and MO-1400-25A (A Loop Core Spray Inboard injection) valves have failed their operability test. Both valves are currently closed.

The maximum time allowed before the plant must be in COLD SHUTDOWN is:

a.

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (1 day) b.

96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> (4 days) c.

168 hours0.00194 days <br />0.0467 hours <br />2.777778e-4 weeks <br />6.3924e-5 months <br /> (7 days) d.

192 hours0.00222 days <br />0.0533 hours <br />3.174603e-4 weeks <br />7.3056e-5 months <br /> (8 days)

ANSWER:

b.

DISCUSSION:

PNPS 2.2.125, " Containment isolation System" lists the valves that are considered to be primary containment isolation valves. An identical listing is contained within the FSAR.

Included in this listing are both the MO-1400-25A and the MO-1001-37B (see Enclosurg 2, Attachment 5). As containment isolation va!ms, the administrative requirements require at least one valve in the line to be deactivated in the isolated position, unless the valve receives any signals other than the isolation signal. Wheher the valve receives any other signals (other than the isolation signal) determines whether the valve has to be deactivated electrically or otherwise administratively controlled. If the requirements of this procedure are not met (and the question does not provide this information), an orderly shutdown shall be initiated and the reactor shall be in Cold Shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

This question was designed to test the applicants' ability to determine:

1) the impact of an Inoperable 37B valve on "LPCl* operability;

2) the impact of an ipoperable 37B valve on the Containment Cooling Loop's Operability

and,

3) the overall effect of 1 and 2 when coupled with an inoperable Core Spray system.

At least one applicant, (during a followup interview), interpreted this question as a test of his ability to recognize that:

1) Both valves are PCIS valves

2) That at a minimum, the 25A would need to be deactivated since it receives an Auto Open signal and,

3) Determine the corrective actions for failed PCIS valves.

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Since the questions asks for the maximum time allowed before the plant must be in COLD SHUTDOWN, if a candidate were to assume that the question is testing his Page 8 of 10

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l knowledge of PCIS, then it is reIsonibl3 th;t tha candidate would chose "c" cs the l

correct response, given that no other actions are taken.

REQUEST: (Question # 29)

Due to the two different ways that this question can be interpreted, we request that both "a" and "b" be accepted as correct.

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REFERENCE:

i PNPS Procedure 2.2.125 (Enclosure 2, Attachment 5) 1 1

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i 6.

Question # 27 When valving in a CRD hydraulic control accumulator, the 305-102 (Withdraw Riser-Isolation Valve) and the 305-112 (Scram Discharge Riser Isolation Valve) are required to be open prior to opening the 305-101 (Insert Riser isolation Valve). This prevents:

a.

a single rod scram when opening the 305-101 valve.

b.

excessive scram time of that rod in the event of a reactor scram.

t c.

damage to the accumulator in the event of a reactor scram.

d.

damage to the drive mechanism in the event of a reactor scram.

ANSWER: d.

DISCUSSION:

While it is stated in PNPS 2.2.87 that valve misoperation during the isolation or restoration of a HCU can cause " severe damage to the mechanism", the isolation of the 102 (by itself) can also delay control rod insertion following a scram signal. As seen in Enclosurg 2, Attachment 6, with the 102 valve shut, the exhaust path from the mechanism is isolated. Since the question does not state the position of the associated rod for the HCU being restored, the candidate could reasonably assume that the rod is in a position other than fully inserted. If the exhaust path is isolated, any scram signal will not permit the mechanism to scram at " normal" rates, if the control rod inserts at all.

REQUEST: (Question # 27)

Due to the fact that response "b" contain the phrase " excessive scram time of the rod in the event of a; reactor scram", we request that response "b" be also accepted as a correct answer.

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REFERENCE:

Figure 4 from PNPS Training Material (Enclosure 2, Attachment 6)

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Page 10 of 10

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ENCLOSURE 2 i

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RP y 120V RPS A 261-2L Fb C

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Figure 1h Rev.1 7 sop 619th

p PNPS TABLE 3.2.A q

INSTRUMENTATION THAT INITIATES PRIMARY CONTAINMENT ISOLATION O

1 Operable Instrument Channels Per Trio System (1)

• ^

Minimum Available

-' Instrument Trfr Level Setting Action (2) m 2(7) 2 Reactor icw Water Level 211.7" indicated level (3)

A and D g

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Reactor High Pressure

$76 psig D

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2 Reactor Low-Iow Water Level at or above - 46.3 in.

A sm&

indicated level (4)

Ag 2

2 Reactor High Water Level 545.3" indicated level (5)

B 2(7) 2 High Drywell Pressure

$2.22 psig A

Cm 2

2 Low Pressure Main Steam Line 2810 psig (8)

B 2(6) 2 High Flow Main Steam Line

$136% of rated steam flow B

d

=

2 2

Main Steam Line Tunnel Q

Exhaust Duct High Temperature

$170*F B

Z 2

2 Turbine Basement Exhaust Duct High Temperature

$150'F B

N 1

1 Reactor Cleanup System v

High Flow.

$300% of rated flow C

2 2

Reactor Cleanup System High Temperature 5150 F C

Revision 180 3/4.2-7 34,-42,-86 -147,-159,-151,-154, 162 Amendment No.

3

ATTACHMENT 1 (QUESTION 32)

NOTES FdR TABLE 3.2.A l.

Whenever Primary Containment integrity is required by Section 3.7. there sh l

be two opetable or tripped trip systems for each function. An instrument t

channel nuty be placed in an inoperable statur for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for required surveillance without placing the trip system in the tripped condition provid at least one OPERABLE channel in the same trip system is monitoring that parameter;,or, where only one channel exists per trip system, the other tri system shall be operable.

P 2.

Ar_ti.oD If the minimum number of operable instrument channels cannot be met for one of the trip systems of a trip function, the appropriate conditions listed below shall be followed:

If placing the inoperable channel (s) in the tripped condition would not cause an isolation, the incperable channel (s) and/or that trip system sha be placed in the tripped dundition within one hour (twelve hours for Reactor Iow Water Level and High Drywell Pressure) or initiate the action required by Table 3.2.A for the affected trip functions.

.If placing the inoperable channel (s) in the tripped condition would cause an isolation, the inoperable channel (s) shall be restored to operable status within two hours (six hours for Reactor Low Water Level and High Drywell Pressure) or initiate the Action required by Table 3.2.A for the affected trip function.

If the minimum number of operable instrument channels cannot be met for both trip systems, place at least one trip system (with the most inoperabic channel in the tripped condition within one hour or initiate t!$ appropriate Action required by, Table 3.2.A listed below for the affectet ; rip function.

A.

Initiate an orderly shutdown and have the reactor in Cold Shutdown Condition in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

B.

Initiate an orderly load reduction and have Main Steam Lines isolated witliin eight hours.

C.

Isolate R,eactor Water Cleanup System.

D.

Isolate Shutdown Cooling.

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l Revision 177 i

Amendment No. 86, 105t ll8 -119 -147 -154 3/4.2-8 t

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AFIAGMMI5NT 2 [ QUESTION 761 a

CEI Docum:nh 8390-43 Em3rg0ncy Pr c; dura GuidOlin30 Appendix 3 3

SECTION 11 CONTINGENCY 42 - EMERGENCY RPV DEPRESSURIEATION OVERVIEW The actions specified in contingency 42 rapidly depressurize the RPV.

The steps of this contingency may be required tot Establish or maintain adequate core cooling.

o Terminate or minimize the discharge of reactor coolant o

from unisolable primary system breaks.

Reduce the energy within the RPV before reaching plant o

conditions for which the pressure suppression system may not be able to safely accommodate an SRV opening or a loss of coolant accident.

f Minimize radioactivity release from the RPV to the o

primary, containment and secondary containment, or to, areas extern,al to the primary containment and secondary containment.

A simplified flow chart of the operator actions specified in Contingency 42 is illustrated in Figure B-ll.l.

B-ll-1 Revision 4

CEI Document 8390-4D E20rg3ncy Prec3 dura Guid311nSG Appendix B i

SECTION 9 RADIOACTIVITY RELEASE CONTROL GUIDELINE PflRPOSE l

...-x The purpose of this guideline is to limit radioactivity release into areas outside the primary and secondary containments.

n.......

i DISCUSSION:

p The Radioactivity Release Control Guideline isolates primary system discharges and controls RPV pressure through sequentially executed steps as required to minimize the offsite release of radioactivity during emergency response conditions.

These steps provide the interface between individual events specifically addressed by the site Emergency Plan and the symptomatic control of RPV, primary c6ntainment, and secondary c:ontainment parameters.

A simplified flowchart of th2 operator,. actions for radioactive release control is $11ustrated in Figure B-9.1.

ATTACHMENT 2 (QUEST #76) l l

3-9-1 Revision 4

O-RO-03-04.og Rev.1 i

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IG-12 PRESENTATION METHODS / MEDIA 1

1) Other methods of pressure reduction must be used (MTBVs, Steam line drains, HPCl/RCIC steam lines).

8.

Flowpath Step P-7. Open ALL SRVs.

ON

a. The operator is directed to open all SRVs to effectively and quickly Usec1 h e depressurize the RPV.

g, g

1) S5Vs are the preferred method of depressurizing the RPV at this point because the removal capability (40% power)is greater than the MTBVs, and the RPV will be depressurized sooner than if only the MTBVs were used.

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2) Previous Pressure Control Flowpath steps have the operator maximize RPV depressurization using the MTBVp if the condenseris available and RPV Depressurization is anticipated.

9.

Flowpath Step P-8. Are 3 or 4 SRVs Open?

(EO-2)

a. If at least the Minimum Number of SRVs REQUjRED for Emergency Depressurization (3) are open, then the RPV will quickly depressurize.

b.

If less than 3 SRVs are open, then the RPV may not depressurize quickly (depending on decay heat, etc.). The operator is then directed to steps which augment the SRV relief capability, to aid in l

depressurizing the RPV.

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ATTACHMENT 2 (QUEST #76) l

u 10 PURPOSE AND SCOPE This Procedure provides a method of tracking the entry and exit from Technical Specifications Limiting Conditions for Operation (LCO).

2.0 REFERENCES

2.1 DEVELOPMENTAL

[1]

DR 1907, Various Administrative Documentation Discrepancies by Operations

[2]

F&MR 90-265

[3]

PNPS 1.2.2, " Administrative Ops Requirements"

[4)

PNPS 1.3 34, " Conduct of Operations"

[5]

PNPS Technical Specifications

[6]

QA Audit #89-49 2.2 IMPLEMENTING

[1]

PNPS 8.C.34, " Operations Technical Specifications Requirements forInoperable Systems / Components" 3.0 DEFINITION $

r

[1]

Active LCO - An LCO category which is assigned when the inoperable component or system is required by the Technical Specifications or PNPS 1.3.34 (SEP equipment) for the current plant condition.

e

[2]

Trackino LCO - An LCO category which is assigned when either an inoperable system / component is not required to be operable under current plant conditions but would be required if the plant mode changed QR a system / component inoperability has the potential for causing entry into an LCO if plant conditions (equipment / instrument operabliity) change prior to retuming the subject system / component to service OR a condition exists that in the opinion of the NWE, with concurrence of the ODM, warrants tracking.

[3]

Outaos LCO - An LCO category which is assigned for an inoperable

. system / component, specifically for a refueling outage. Only those LCOs which meet the definition of a Tracking LCO may be assigned as an Outage LCO. All Outage LCOs must be cancelled or transferred to either a Tracking LCO or an Active LCO prior to startuo from a Refueling Outage.

[4]

LCO Loo - The binder used to organize and maintain the Attachments used in this Procedure.

1.3.34.2 Rev. 4 ATTACHMENT 3 (QUEST #28)

4.0 DISCUSSION The removal from service of Technical Specifications-required equipment may cause the entry into an LCO immediately or may cause the potential for entering an LCO if plant conditions change prior to returning the equipment to service. Anytime a piece of equipment is removed l

from service a review shall be performed to determine whether these conditions exist. This Procedure will then be used to write an LCO to track the retum to service of the equipment v:rsus actions required by Technical Specifications due to the loss of the equipment. This Procedure provides an administrative aid to the NWE, the NOS, and the SCRE in ensuring cdherence to Technical Specifications.

5.0 PRECAUTIONS

[1]

This Procedure shall not be construed to be a substitute for any current reporting method such as Problem Reports.

6,0 PROCEDURE i

6.1 LCO INITIATION

[1]

Upon entry into an LCO, the NWE or designee [ Shift Control Room Engineer (SCRE)]

shall complete an LCO form (Attachment 1 blocks 1 through 14), except in situations when:

(a)

Routine activities are performed and equipment is immediately placed back in service upon, completion. Examples are: changing chart paper, changing filters, and sampling.

[2]

The LCO should be classified as ACTIVE, TRACKING, or OUTAGE based on the l

Definitions contained in Section 3.0 of this Procedure.

[3]

The LCO should be placed in the ACTIVE, TRACKING, or OUTAGE section of the l

Control Room LCO book.

[4]

The LCO number should be recorded in the ACTIVE, TRACKING, or OUTAGE index, l

maintaining the index in the format of Attachment 2.

[5]

The LCO number should be logged in the NOS Log.

[6]

The Reactor Operator should be verbally notified of entry into the LCO.

[7]

The Regulatory Affairs Department shall be notified of entry into an LCO that requires a l

special report to the NRC when the flag day is reached. (QA Audit G9-49]

l 1.3.34.2 Rev. 4 ATTACHMENT 3 (QUEST #28)

iF DURING THE EXECUTION OF THIS LEG, ALTERNATE RPV DEPRESSURIZATION IS ANTICIPATED, EOP-01 IS EXECUTED CONCURRENTLY. BY EXECUTING EOP-01:

• THE REACTOR WILL BE SCRAMMED

= RPV PRESSURE CONTROL WILL BE IMPLEMENTED THIS STEP DIRECTS THE OPERAMR TO MAINTAIN TORUS LEVEL AS HIGH AS POSSIBLE IN THE PRESCRIBED BAND OF 90* - 132*. IF THE OPERATOR EXCEEDS 132" TORUS LEVEL THE "HIGH* TORUS LEVEL LEG WOULD BE ENTERED.

w IF TORUS WATER LEVEL DROPS TO 90* OR THE OPERATOR fe men I we -

DECIDES THAT TORUS LEVEL CANNOT BE MAINTAINED, EOP-01 IS

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t ENTERED CONCURRENTLY.

4 f,,

• A TORUS LEVEL OF 90 INCHES CORRESPONDS TO THE LEVEL I

WHERE DRYWELL TO TORUS (LOCA) DOWNCOMERS BECOME UNCOVERED. WITHOUT DOWNCOMER SUBMERGENCE. THE PRESSURE SUPPRESSION FUNCTION OF THE TORUS FOLLOWING A G

_*A LOCA CANNOT BE ASSURED.

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THE OPERATOR IS DI 'ECTED TO MAIN TAIN TORUS WATER

=

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LEVEL ABOVE 95 INCHES. THIS STEP IS PROVIDED SO VAR!OUS ca = =.

= =

PIPES / TAPS DO NOT BECOME UNCOVERED As A RESULTOF

- go m.

CONTINUED TORUS LEVEL DECREASE.

ll-

+

l m '*c' SINCE LOW TORUS WATER LEVEL CAN RESULT IN ALMATE RPV N"TYYY CONTAINMENT PRESSURIZATION / FAILURE VMEN HPCI EXHAUST IS UNCOVERED, HPCI IS SECURED REGARDLESS OF ADEQUATE CORE COOLING.

1 u

N AS STATED EARLIER, EOP-01 IS ENTERED SO THE WHEN TORUS LEVEL REACHES 95* OR WHEN IT IS DETER!A, :P 4

REACTO9 WILL BE SCRAMMED AND RPV THAT A DROP TO 95 INCHES IS INEVITABLE, THE OPERATOR IS PRESSUdE CONTROL WILL BE IMPLEMENTED DIRECTED TO SECURE HPCI. HPCI IS SECURED TO PREVENT PRIMARY CONTAINMENT PRESSURIZATION AS THE RESULT OF HPCI EXHAUST FLOW. IF HN.I IS NOT SECURED, THE PRIMARY CONTAINMENT PRESSURE LilJIT (PCPL) MAY BE EXCEEDED. THIS COULD RESULT IN CONTAINMEN~ FAILURE.

BY REQUIRING RPV DEPRESSURIZATION, THE ENERGY THAT RCIC IS NOT SECURED AT THIS P~)lNT BECAUSE:

IS IN THE RPV IS DISCHARGED TO THE TORUS WATER

. RCIC STEAM FLOW RATE IS EQUIVALENT TO DECAY HEAT BEFORE ANY FURTHER LOSS / DEGRADATION OFTHE STEAM FLOW RATE, AND THE CONTAINMENT IS DESIGNED FOR PRESSURE SUPPRESSION FUNCTION OCCURS, AND WELL DECAY HEAT FLOW RATE BEFORE

• RCIC WILLTRIP ON HIGH EXHAUST PRESSURE BEFORE HPCI THE SRV TAILPIPE DISCHARGE PORTS ARE UNCOVERED.

(46psig. VICE 150psig.)

EOP-03, TORUS LEVEL CONTROL (LOW) - SHEET 2 82opto41r ATTACHMENT 4 (QUEST #50)

l BOSTON EDISON RTYPE H6.02

+

i ATTACHMENT 5 (QUESTION 29)

PILGRIM NUCLEAR POWER STATION Procedure No. 2.2.125 CONTAINMENT ISOLATION SYSTEM REOUIRED REVIEWS REVIEWERS AND APPROVERS A!

k

'1.2 f - W Think Procedure ~ Write Date N sras a,'i-7/.,s/9s Act n$c i Reviewer oate Review

- Ik 9-2 6 -T f f 't (

SAFETY REVIEW REQUIRED ProceduY.0wner i Date ORCREVIEWREQUIR5b g/

l QAD Manager Date

/} k V'ee.

9/Ar/sr r

ORCCpirman Date l4 "790 b $$ itb9C Repssi nager te

\\O\\Q.96 Effective Date:

l l

020039 2.2.125 Rev. 16

5;0 ERECAUTIONS AND LIMITATIONS 5.1 PRECAUTIONS

[1]

Prior to opening an isolation valve, place the con' trol switch to "CLOSE" to reset the isolation signal.

[2]

Open the outboard main steam isolation valves prior to opening the inboard isolation valve to allow trapped condensation to drain.

[3]

Do not attempt to open main steam line isolation valves with a pressure differential across the valve greater than 200 psig.

[4]

Once an isolation is automatically initiated, the valve continues to close even if the condition that initiated the closure has been restored to normal. The Operator must operate the isolation reset in the Control Room to reopen the isolation valve that automatically c.losed. The Operator cannot reset the isolation until the condition cr.using the isolation is cleared and the control switches have been placed in the "CLOSE" position.

[5]

If the reactor pressure is allowed to exceed 576 psig with the REACTOR MODE switch in the " SHUTDOWN", " REFUEL", or "STARTUP" position and with the Main Steam Isolation Valves closed, a reactor Scram will result.

5.2 LIMITATIONS f 5.2.1 Limiting Conditions for Operation - Technical Specifications Section 3.7. A '

[1]

3.7. A.2.a.4 - All automatic primary containment isolation valves and all f

instrursent line flow check valves shall be operable except as specified in Technical Specifications Section 3.7.A.2.b.

[2]

3.7. A.2.b - In the event any automatic containment isolation valve becomes inoperable, at least one containment isolation valve in each line having an inoperable valve shall be deactivated in the isolated condition.

1101E If the valve to be deactivated receives any signals other than its isolation signal, it must be physically deactivated.

If the valve receives only its isolation signal, it may be secured using administrative controls; i.e., Red-tagged in the isolated position.

(This requirement may be satisfied by deactivating the inoperable valve r

in the isolated condition. Deactivation means to electrically or pneumatically disarm or otherwise secure the valve.)

g [3]

If the above cannot be met, an orderly shutdown shall be initiated and the reactor shall be in Cold Shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (in accordance with 10CFR50.36.c).

w 2.2.125 Rev. 16 Page 8 of 35 ATTACHMENT 5 (QUEST #29)

i r

EXHAUST WATER HEADER f

J f

COOUNG WATER HEADER

)

DRNE WATER HEADER f

105 103 104

, P1 T

FILTER 134 137 [

138[

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~

..,D ks

, P2 3

c.................,__.......

g

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P3 e

4 2

I

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1 g +.. _8 g :

T g

c:

T 4

FILTER 135 FILTER 136 t

g r,

CONTROL 5\\/

10 %

mD DRNE REACTOR FROM

=

==-

MANUAL M

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CONTROL SYSTEM Q2 s

p4 s

TO RE 'CTOR d

101 PROTECTION SYSTEM 4

N ee

~~

,,,,,,.............'s gg 99 i

m 4

77 i

a <

e......................___...e s

e LOOP 114 6

{K" SEAL

+- 8 8--=*-3 40 Eg i r N

2 9

'Ilt J

L N

1 1P P5 X

EXHAUST..

( j ( s_.

P 112 jg j

e y

T M

1 P6 N 2 CHARGING SYSTEM SCRAM VALVE PILOT AIR HEADER f

J J

f CHARGING HEADER FOR ACCUMULATORS f

)

)

f SCRAM OtSCHARGE HE AnER TO SCRAM DISCHARGE VOLUME f

)

)

CRD HYDRAULIC CONTROL UNIT PIPING DIAGRAM FIGURE 4 r

• " ~

ATTACHMENT 6 (, QUEST #27',l