Text

Draft - Section a SRO Operating
	ML010540382
Person / Time
Site:	Nine Mile Point
Issue date:	02/17/2000
From:	Mueller J; Niagara Mohawk Power Corp
To:	Conte R; Division of Reactor Safety I
References
	-RFPFR, 05000410/99-301 05000410/99-301
	Download: ML010540382 (214)
	v • d • e

Facility: Nine Mile Point # 2 Date of Examination: 12/06/99 Examination Level (circle one): SRO Operating Test Number: Cat A Test 1 Administrative Topic/Subject Describe method of evaluation:

Description 1. ONE Administrative JPM, OR

2. TWO Administrative Questions ONLY).

A. I Plant Parameter JPM: (New) Water Chemistry Operating Limits Determination (SRO Verification K/A 2.1.33, 2.1.34 Question: 1. Given watchstanding history, medical data and training data, determine requirements to stand watches. (Active license requirements).

Shift Turnover minmum Question: 2. Given the number of shift personnel, determine if manning reqiurements are being met. K/A 2.1.1, 2.1.3, 2.1.4, 2.1.5 path from the A.2 Piping and Question: 1. Using the PIDs, trace the Fire Protection Water flow RPV using RHS Train A.

Instrument motor driven fire water pump 2FPW-P2, to the Where necessary, add EOP Drawings 2RHS*MOV24A is available for injection.

equipment to be used. K/A 2.1.24 PRA (IPE: Fire Water - RHR Crosstie)

Testable Question: 2. Using a PID drawing, describe how the motor operated will respond to a LOCA signal. K/A Check Bypass Valve RHS*MOV67B 2.1.24 277' Question 1. Review the attached Survey 68 for Turbine Building A.3 Radiation Work Condensate Demin Valve Aisle and identify the radiological hazard(s).

Permits K/A 2.3.10 and identify Question 2. Review a Radiation work Permit (22, Revision 313),

clothing requirements sign in requirements for Auxiliary Operators, protective sent into an area with a general area and actions to be taken if an AO has to be radiation level of 20 mrem/hr for four (4) hours? K/A 2.3.10 scenario.

A.4 Emergency JPM: (New) Emergency Plan classification of each SRO candidates after each scenario). K/A 2.4.29, Classification (Submitted with and to be administered 2.4.41 11--/

NIAGARA MOHAWK POWER CORPORATION OPERATOR JOB PERFORMANCE MEASURE Revision: 0

Title:

Water Chemistry Operating Limits Determination (SRO ONLY)

Task Number: 341-022-03-03-2 Approvals:

I-/ /-/9- 9V Date eneral Superv r DatSupevisor Operations Tr ing (Designee) Operations Designee)

Configuration Control 'Date Performer: (SRO)

I TrI I---- -- M-ua-o-aull.,./ -tI - -_1 _._ .-

Evaluation Method: Perform X Simulate Evaluation Location: _Plant Simulator Expected Completion Time: 8 minutes Time Critical Task: NO Alternate Path Task: NO Start Time: Stop Time: Completion Time:_

JPM Overall Rating: Pass Fail grade of unsat or NOTE: A JPM overall rating of fail shall be given if any critical step is graded as fail. Any individual competency area unsat requires a comment.

Comments:

Evaluator Signature: Date:

SRO Cat A Test 1, A. I I October 1999

Recommended Start Location: (Completion time based on the start location)

Plant Control Room

Simulator Set-up:

N/A Directions to the Instructor/Evaluator:

Prior to performance of this JPM, obtain SSS / CSO general permission to open equipment cabinets and inspection covers. If opening the equipment cabinet or inspection cover will affect Tech. Spec. Operability, operational status, or the effects are unknown, obtain specific SSS / CSO permission.

Directions to Operators:

Read Before Every JPM Performance:

For the performance of this JPM, I will function as the SSS, CSO, and Auxiliary Operators. Prior to providing direction to perform this task, I will provide you with the initial conditions and answer any questions. During task performance, I will identify the steps to be simulated, or discuss and provide cues as necessary.

Read Before Each Evaluated JPM Performance:

This evaluated JPM is a measure of your ability to perform this task independently. The Control Room Supervisor has determined that a verifier is not available and that additional / concurrent verification will not be provided; therefore it should not be requested.

Read Before Each Training JPM Performance:

During this Training JPM, applicable methods of verification are expected to be used. Therefore, either another individual or I will act as the additional / concurrent verifier.

Notes to Instructor / Evaluator:

1. Critical steps are identified as Pass/Fail. All steps are sequenced critical unless denoted by a

2. During Evaluated JPM:

Self-verification shall be demonstrated.

3. During Training JPM:

Self-verification shall be demonstrated.

No other verification shall be demonstrated.

References:

1. GAP-CHE-01, Rev 02, BWR Water Chemistry Operating Limits

2. T.S. 3.4.4

3. T.S. Table 3.4.4-1

4. NUREG K/A 2.1.33 (4.0)

K/A 2.1.34 (2.9)

Tools and Equipment:

1. None.

Task Standard:

Determine that the Action Level 2 guidelines of GAP-CHE-01, Enclosure 2, for reactor water conductivity are exceeded. Determines a unit shutdown to COLD SHUTDOWN is required if the parameter is NOT below the limit within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from the time of occurrence.

SRO Cat A Test I, A. 1 2 October 1999

(I.... ( (

Initial Conditions:

1. The unit is at 50% power. There are no equipment inoperabilities.

0 reactor coolant system conductivity is 1.2 umho/cm @25 C.

"(Operator's name), Chemistry has called the Control Room and informed you that Evaluate plant chemistry and take any necessary actions based on your evaluation."

- t . ,-

a. - - i- I f . I rnmmentso v I PerformanceSteps II .1standara .I-Proper communications used for repeat back Sat/Unsat

1. Provide repeat back of initiating cue.

EvaluatorAcknowledge repeat back (GAP-OPS-O1) providing correction if necessary RECORD START TIME GAP-CHE-0 1 Enclosure 2 referenced. Sat/Unsat

2. Obtain a copy of the reference procedure and/or Tech Specs and review/utilize the correct section of Tech Spec 3.4.4 and Table 3.4.4-1 the procedure/Tech Specs. referenced.

Determine action level 2 is exceeded (>1.0) Pass/Fail

3. If an action level of Enclosure 2 is exceeded, then take the actions as applicable. GAP-CHE-0I Section 3.2.2, Action Level 2 value exceeded, referenced.

Notify the Chemistry Supervisor. Sat/Unsat

.3. Notify the Chemistry Supervisor and the SSS of the parameter that has exceeded Action Level 2 limits. Notify the SSS.

Cue: As the Chemistry Supervisor, Note: Simulated unless in the simulator.

acknowledge the report.

Cue: As the SSS, acknowledge the report.

SRO Cat A Test 1, A. 1 3 October 1999

C (

(

lI Grade : Comments I

rd ::

Tech Table 3.4.4-1 referenced. Sat/Unsat

.4. If the parameter exceeds a Tech Spec limit, then take the Tech Spec actions. Determines conductivity limit is exceeded.

Cue: If asked, the last reported Determines if conductivity is not within conductivity 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ago was limits in 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , then the unit must be in at 0.8 umho/cm @25 0C. least HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months (78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months from entry into Cue: If asked, this is the first time this the Tech Spec actions).

year that the Tech Spec 3.4.4 limits are NOT met. Note: The requirement is to be in STARTUP within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , however, since there are no provisions to proceed to startup the correct action is to be in MODE 3 within the same allotted time to meet the requirement.

.5. If the parameter is a fuel warranty parameter, then immediately notify fuels and management.

Determines NO fuel warranty limit is exceeded.

Sat/Unsat I

Determines NO cond. demin. outlet limit is Sat/Unsat

.6. If individual cond. Demin. outlet conductivity is above the limit, then exceeded.

remove the demin. from service.

Determines NO condensate demineralizer Sat/Unsat

.7. If condensate demineralizer inlet conductivity is above the limit, inlet limit is exceeded.

then isolate the affected waterbox.

SRO Cat A Test 1, A. 1 4 October 1999

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-7 I i-'..

I o-X tzrc I I PerforlnanceSteps a.

,r 1I:If:

tanaara i

I I i . rra

..- - --- I Determines that a shutdown must be initiated Pass/Fail

8. If the parameter is NOT below the Action Level 2 limit within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , when 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months expires.

initiate an orderly shutdown to place the unit in COLD SHUTDOWN. Determines the plant must be placed in COLD SHUTDOWN as rapidly as operating Cue: If asked, parameter will NOT be conditions permit.

restored below limit for 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

Note: The candidate may take the Cue: If asked, operation at lower conservative action and start a shutdown power will NOT reduce exposure before 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months expires.

of components to the parameter.

Recognizes a root cause is required after Sat/Unsat

9. After the unit is shutdown, identify the cause, correcti ve actions, and shutdown.

receive SORC approval prior to restart. Recognize SORC approval is required for restart.

End of JPM if the TERMINATING CUE: Determines a unit shutdown to COLD SHUTDOWN is required parameter is NOT below the limit within 24 hours from the time of occurrence.

RECORD STOP TIME_

SRO Cat A Test 1, A. 1 5 October 1999

REACTOR COOLANT SYSTEM 3/4.4.4 CHEMISTRY LIMITING CONDITIONS FOR OPERATION 3.4.4 The chemistry of the reactor coolant system (RCS)shall be maintained within the limits specified in Table 3.4.4-1.

APPLICABILITY: At all times.

ACTION:

a. In OPERATIONAL CONDITION 1:

1. With the conductivity, chloride concentration, or pH exceeding the limit specified in Table 3.4.4-1 for less than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months during one continuous time interval and, for conductivity and chloride concen-tration for less than 336 hours0.00389 days 0.0933 hours 5.555556e-4 weeks 1.27848e-4 months per year, but with the conductivity less than 10 pmho/cm at 250C and with the chloride concentration less than 0.5 ppm, this need not be reported to the Commission and the provisions of Specification 3.0.4 are not applicable.

2. With the conductivity, chloride concentration, or pH exceeding the limit specified in Table 3.4.4-1 for more than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months during one continuous time interval or with the conductivity and chloride concentration exceeding the limit specified in Table 3.4.4-1 for more than 336 hours0.00389 days 0.0933 hours 5.555556e-4 weeks 1.27848e-4 months per year, be in at least STARTUP within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

0

3. With the conductivity exceeding 10 pmho/cm at 25 C or chloride concentration exceeding 0.5 ppm, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

b. In OPERATIONAL CONDITIONS 2 and 3 with the conductivity, chloride concentration, or pH exceeding the limit specified'in Table 3.4.4-1 for -

more than 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months during one continuous time interval, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

c. At all other times:

1. With the:

a) Conductivity or pH exceeding the limit specified in Table 3.4.4-1, restore the conductivity and pH to within the limit within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , or b) Chloride concentration exceeding the limit specified in Table 3.4.4-1, restore the chloride concentration to within the limit within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , or NINE MILE POINT - UNIT 2 3/4 4-17

REACTOR COOLANT SYSTEM CHEMISTRY LIMITING CONDITIONS FOR OPERATION 3.4.4 (Continued)

ACTION:

c.1.b) (Continued) perform an engineering evaluation to determine the effects of the out-of-limit condition on the structural integrity of the reactor coolant system. Determine that the structural integrity of the reactor coolant system remains acceptable for continued operation before proceeding to OPERATIONAL CONDITION 3.

2. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.4.4 The reactor coolant shall be determined to be within the specified chemistry limit by:

a. Measurement before pressurizing the reactor during each startup, if not performed within the previous 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

b. Analyzing a sample of the reactor coolant for:

1. Chlorides at least once per:

a) 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , and b) 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months whenever conductivity is greater-than the limit in -

Table 3.4.4-1.

2. Conductivity at least once per 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

3. pH at least once per:

a) 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , and b) 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months whenever conductivity is greater than the limit in Table 3.4.4-1.

c. Continuously recording the conductivity of the reactor coolant, or, when the continuous recording conductivity monitor is inoperable, for up to 31 days, obtaining an in-line conductivity measurement at least once per:

1. 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months in OPERATIONAL CONDITIONS 1, 2, and 3, and

2. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months at all other times.

NINE MILE POINT - UNIT 2 3/4 4-18

REACTOR COOLANT SYSTEM CHEMISTRY SURVEILLANCE REQUIREMENTS 4.4.4 (Continued)

d. Performing a CHANNEL CHECK of the continuous conductivity monitor with an in-line flow cell at least once per:

1. 7 days, and

2. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months whenever conductivity is greater than the limit in Table 3.4.4-1.

NINE MILE POINT - UNIT 2 3/4 41-19

TABLE 3.4.4-1 REACTOR COOLANT SYSTEM CHEMISTRY LIMITS CONDUCTIVITY OPERATIONAL CONDITION CHLORIDES (pmho/cm @25 0 C) 1 <0.2 ppm <1.0 5.6 < pH < 8.6 2 and 3 <0.1 ppm <2.0 5.6 < pH < 8.6 At all other times <0.5 ppm <10. 0 5.3 < pH < 8.6 NINE MILE POINT - UNIT 2 3/4 4- 20

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION GENERATION ADMINISTRATIVE PROCEDURE GAP-CHE-O1 REVISION 02 BWR WATER CHEMISTRY OPERATING LIMITS TECHNICAL SPECIFICATION REQUIRED Approved by: *aMa W- EU /D/a Date z

R. G. Smith Plant Manager -

Approved by:

N. C. Paleologos Plant Manager - Unit 2 Date Effective Date: 10/15/98

TABLE OF CONTENTS PAGE SECTION PURPOSE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1.0 1

2.0 PRIMARY RESPONSIBILITIES 1

3.0 PROCEDURE . . . . . . . . . . . . . . . . . . . . . . . . . . . .

DEFINITIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

4.0 REFERENCES

AND COMMITMENTS . . . . . . . . .. . . . . . . . . . 5 5.0 RECORDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 6.0 7.0 ENCLOSURES . . . . . . . . . . . . . . . . .. . . . . . . . .. 6 7

ENCLOSURE 1: WATER CHEMISTRY GUIDELINES - UNIT 1.

10 ENCLOSURE 2: WATER CHEMISTRY GUIDELINES - UNIT 2.

Page i GAP-CHE-O1 Rev 02

1.0 PURPOSE To establish water chemistry operating limit action levels and corresponding corrective actions for Nine Mile Point Units 1 and 2.

1.1 Applicability This procedure applies to Nine Mile Point Unit 1 and Unit 2 BWR water chemistry during all modes of operation.

2.0 PRIMARY RESPONSIBILITIES 2.1 Nuclear Generation is responsible for identifying when water chemistry action levels are reached and taking the required corrective actions to return the out-of-spec parameters to within acceptable operating limits.

2.2 Chemistry Manager is responsible for the control and maintenance of this procedure, and ensuring that required sampling and analyses are performed to monitor BWR water chemistry parameters.

3.0 PROCEDURE 3.1 The Chemistry Department shall monitor and report water chemistry parameters to ensure that they are tracked to identify long-term trends and determine when an action level as presented in Enclosure I "Water Chemistry Guidelines - Unit 1" or Enclosure 2 "Water Chemistry Guidelines - Unit 2" is being approached, has been reached, or exceeded.

3.2 IF an action level defined in Enclosure 1 OR Enclosure 2 is exceeded take the following actions as applicable:

NOTE: 1. In all cases Tech Spec actions take precedence

2. When the parameter is a fuel warranty parameter Action levels represent fuel warranty continuous, maximum, and extreme limits.

3. Event timeclock begins at time of discovery 3.2.1 IF an Action Level 1 value is exceeded, THEN perform the following:

a. Notify the Chemistry Supervisor and SSS of the parameter which has exceeded Action Level 1 limits.

b. IF the parameter exceeds a Tech Spec limit, THEN take actions in accordance with the applicable Tech Spec section.

c. IF the parameter is a fuel warranty parameter, THEN notify Fuels and Analysis by the end of the next working day.

Page 1 GAP-CHE-01 Rev 02

3.2.1 (Cont)

d. IF Feedwater Total Copper and /or Iron weekly integrated results exceed Action Level 1, THEN analyze additional sample(s) within 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months . IF the result shows that the parameter has not been reduced to below the action value level, THEN continue with section 3.2.1.e.

e. Chemistry management perform an assessment to determine corrective actions required to reduce the parameter below the Action Level 1 value within 96 operating hours. The assessment will include but not limited to the following actions:

1. IF the parameter is a fuel warranty parameter, time outside Action Level 1 limit should not exceed 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for a single incident, and shall not exceed 336 hours0.00389 days 0.0933 hours 5.555556e-4 weeks 1.27848e-4 months (14 days) in any 12 month period.

NOTE: Action Level 1 represents the fuel warranty continuous limit.

2. For Unit 2, when both reactor water conductivity is > 0.3 Iumho/cm AND feedwater soluble copper is > 0.3 ppb, the unit should be derated to 85 % Core Thermal Power. IF reduction below either value is not achieved within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

Derating the unit is only applicable during the first 2900 MWD/ST cycle exposure.

3. IF an individual condensate demineralizer conductivity exceeds action level 1, THEN remove the demineralizer from service within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

4. IF Dissolved Oxygen has exceeded Action Level 1 during Reactor Condition II at Unit 1 or Modes 2 OR 3 at Unit 2, THEN the Dissolved Oxygen must be less than 300 ppb before reactor water temperature is increased above 2850 F (140° C)

f. IF the parameter is not a fuel warranty parameter and cannot be reduced below Action Level 1 within 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months , OR a fuel warranty parameter cannot be reduced below Action Level 1 within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , THEN Chemistry should coordinate a review and prepare a schedule for implementing corrective actions including review by appropriate levels of management. The schedule of corrective actions should be submitted to the Plant Manager for review and approval.

Page 2 GAP-CHE-01 Rev 02

3.2.2 IF an Action Level 2 value is exceeded, THEN perform the following:

a. Notify the Chemistry Supervisor and SSS of the parameter which has exceeded Action Level 2 limits.

b. IF the parameter exceeds a Tech Spec limit, THEN take actions in accordance with the applicable Tech Spec section.

c. IF the parameter is a fuel warranty parameter, THEN immediately notify Fuels and Analysis.

d. Chemistry management perform an assessment to determine corrective actions required to reduce the parameter below the Action Level 2 value within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The assessment will include but not limited to the following actions:

1. IF the parameter is a fuel warranty parameter, THEN time outside the Action Level 2 limit shall not exceed 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months (2 days) in any 12 month period.

NOTE: Action Level 2 represents the fuel warranty maximum limit.

2. IF an individual condensate demineralizer outlet conductivity exceeds action level 2, THEN remove the demineralizer with the high alarm from service.

3. IF the parameter is the Unit 2 Condensate Demineralizer Inlet Conductivity, THEN determine which waterbox is leaking. Isolate and repair within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

4. IF the parameter has not been reduced below the Action Level 2 value within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from time of occurrence, THEN an orderly shutdown shall be initiated and the plant shall be brought to cold shutdown as rapidly as operating conditions permit, except as follows:

a. When more restrictive action is required by Technical Specifications for reactor water conductivity, chloride, sulfate (Unit 1 only) or pH,

b. IF the parameter will be below the Action Level 2 value within the time period required to achieve an orderly shutdown, power operation can be maintained, or

c. IF continued operation, perhaps at reduced power, results in minimized exposure of components to elevated parameter concentrations.

5. Request an engineering evaluation if continued operation is maintained to minimize the exposure of components to elevated parameter concentrations as stated in 3.2.2.d.4.c above.

Page 3 GAP-CHE-O1 Rev 02

3.2.2.d (Cont)

6. IF Unit 1 Feedwater Total Metals has exceeded action level 2 during Reactor Condition III at Unit 1 or Mode 1 at Unit 2, resample and analyze for Total Metals after reaching steady state power for at least 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

e. IF the unit is shutdown as a result of exceeding an Action Level 2 value; THEN the cause of the incident shall be identified and corrective actions completed AND reviewed by SORC prior to restart.

3.2.3 IF an Action Level 3 value is exceeded perform the following:

a. Notify the Chemistry Supervisor and SSS of the parameter which has exceeded Action Level 3 limits.

b. IF the parameter exceeds a Tech Spec limit, THEN take actions in accordance with the applicable Tech Spec section.

c. IF the parameter is a fuel warranty parameter, THEN immediately notify Fuels and Analysis.

NOTE: Action Level 3 represents the fuel warranty extreme limit.

d. The SSS shall initiate an orderly shutdown with reduction of coolant temperature to < 200'F as rapidly as other plant constraints permit, except as follows:

1. IF Feedwater Metals have exceeded Action Level 3, THEN the effectiveness of immediate action(s) should be verified by analysis of a subsequent sample at steady state power prior to recommending shutdown as appropriate.

2. IF the parameter will be below the Action Level 2 value within the time period required to achieve an orderly shutdown, THEN power operation can be maintained.

3. IF it is more prudent, maintain power operation if such an effort results in minimized exposure of components to elevated parameter concentrations (eg. Resin intrusion).

a. Request an Engineering evaluation if continued operation is maintained to minimize exposure of components to elevated parameter concentrations.

4. IF FW and CDE Dissolved Oxygen are below the Action level 3 low limit OR above the Action level 3 high limit, operation may continue provided immediate action is taken to increase or decrease oxygen to within limits.

e. IF the unit is shutdown as a result of exceeding an Action level 3 value; THEN the cause of the incident shall be identified, corrective actions completed and reviewed by SORC prior to restart.

Page 4 GAP-CHE-O1 Rev 02

4.0 DEFINITIONS represents 4.1 Action Level 1 - The Action Level 1 value of a parameter that long-the level above which data or engineering judgment indicates an term system reliability may be threatened, thereby warranting improvement of operating practices.

represents 4.2 Action Level 2 - The Action Level 2 value of a parameter that the level above which data or engineering judgment indicates term, significant degradation of the system may occur in the short thereby warranting a prompt correction of the abnormal condition.

represents 4.3 Action Level 3 - The Action Level 3 value of a parameter that it is the level above which data or engineering judgment indicate inadvisable to continue to operate the plant.

4.4 Siemens/centimeter (S/cm) - Siemens/centimeter is the unit of measure of electrical conductivity. S/cm is numerically equivalent to mho/cm.

4.5 REACTOR CONDITION 1: Reactor water bulk temperature <200 degrees F.

degrees F AND 4.6 REACTOR CONDITION 2: Reactor water bulk temperature >=200 reactor thermal power <=10%.

4.7 REACTOR CONDITION 3: Reactor thermal power >10%.

5.0 REFERENCES

AND COMMITMENTS 5.1 Licensee Documentation 5.1.1 Unit 1 Technical Specifications

a. Section 3/4.2.3 Coolant Chemistry 5.1.2 Unit 2 Technical Specifications

a. Section 3/4.4.4 Reactor Coolant System, Chemistry 5.1.3 Unit 2 Final Safety Analysis Report

a. Section 5.2.3.2.2 BWR Chemistry of Reactor Coolant

b. Section 5.4.8 Reactor Water Cleanup System

c. Section 10.4.6 Condensate Demineralizer System

d. Section 10.4.7 Condensate and Feedwater System

e. Section 10.4. 11 Oxygen Feedwater Injection System 5.2 Standards. Regulations, and Codes 5.2.1 Regulatory Guide 1.56, Rev 1 July 1978, "Maintenance of Water Purity In Boiling Water Reactors" "BWR 5.2.2 Electric Power Research Institute (EPRI) TR-103515 Rev 1, Water Chemistry Guidelines" Page 5 GAP-CHE-01 Rev 02

5.3 Policies. Programs. and Procedures 5.3.1 NDD-CHE, Chemistry 5.3.2 NDD-RMG, Records Management 5.4 Supplemental References 5.4.1 Unit 1 GE Fuel Warranty Contra ct 5.4.2 Unit 2 GE Fuel Warranty Contra ct 5.5 Commitments Sequence Commitment Number Number Descriptio n 1 503897 NRC Commit ment to EPRI TR-103515-R1 Table 4.4 Control Parameters, except for ECP and Zinc (Unit 1) 2 504098 Revise N1- CSP-D100 to incorporate Technical Specificatlion Amendment #163 6.0 RECORDS REVIEW AND DISPOSITION 6.1 The following records generated by this procedure shall be maintained by Records Management for the Permanent Plant File in accordance with NIP-RMG-01, Records Management:

None 6.2 The following records generated by this procedure are not required for retention in the Permanent Plant File:

None 7.0 ENCLOSURES Enclosure 1: Water Chemistry Guidelines - Unit 1 Enclosure 2: Water Chemistry Guidelines - Unit 2 LAST PAGE Page 6 GAP-CHE-01 Rev 02

ENCLOSURE 1: WATER CHEMISTRY GUIDELINES - UNIT 1 Specifications, NOTES: 1. This enclosure has three sections; Technical needs to Fuel Warranty, and EPRI Guidelines. Each section be evaluated for applicability.

Conditions are

2. Water chemistry limits at specific Reactor MODE SWITCH based on BULK REACTOR WATER TEMPERATURE AND NOT POSITION I. TECHNICAL SPECIFICATIONS of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , OR a NOTE: Action level 2 limits may be exceeded for a maximum hour and reactor coolant temperature be shutdown shall be initiated within one reduced to < 200 ° F within 10 hours.

0 REACTOR CONDITION 2: Reactor water bulk temperature > 200 F AND reactor thermal power < 10 %

Control Parameter Action Levels 1 2 3 Reactor Water > 1.0 > 5.0 Conductivity (uS/cm) at 25 OC

> 100 > 200 Chloride (ppb)

'~~

> 100 > 200 Sulfate (ppb)

REACTOR CONDITION 3: Reactor th ermal power > 10%

Control Parameter Action Levels 1 2 3 Reactor Water Conductivity (uS/cm) at 25 OC >0.19 > 1.0 >5.0 Chloride (ppb) >5 > 20 > 100

>5 > 20 > 100 Sulfate (ppb)

Page 7 GAP-CHE-Ol Rev 02

ENCLOSURE 1 (Cont)

II. FUEL WARRANTY REQUIREMENTS REACTOR CONDITION 1: Reactor water bulk temperature < 200OF System and Control Parameter Action Levels 1 2 3 Reactor Water pH at 250 C (Low) <5.3 <4.9 <4.6 (applied only when reactor water

> 1.OuS/cm) (High) >8.6 >9.3 >9.6 REACTOR CONDITION 2: Reactor water bulk temperature > 200OF AND reactor thermal power <10%

System and Control Parameter Action Levels 1 2 3 Reactor Water pH at 250 C (Low) <5.6 <4.9 <4.6 (applied only when reactor water

> 1.OuS/cm) (High) >8.6 >9.3 >9.6 REACTOR CONDITION 3: Reactor thermal power > 10%

System and Control Parameter Action Levels 1 2 3 Reactor Water pH at 250 C (Low) < 5.6 < 4.9 < 4.6 (applied only when reactor water

> 1.OuS/cm) (High) > 8.6 >9.3 > 9.6 Condensate 0 Effluent (CDE) conductivity at 25 C >0.065 >0.1 >0.2 Effluent (CDE) dissolved Oxygen Low < 20 <10 <5 High > 50 >200 >550 Feedwater Dissolved Oxygen Low <20 <10 <5 High >50 >200 >550 Total Copper (ppb) >2.0 >4.0 Iron (ppb) Insoluble >10 >20 >40 Soluble >1.0 >2.0 >4.0 Total metals (ppb) >15 >30 >60 Fe,Cu,N1,Zn (soluble & insoluble)

Page 8 GAP-CHE-O1 Rev 02

ENCLOSURE 1 (Cont)

III. EPRI BWR WATER CHEMISTRY GUIDELINE REACTOR CONDITION 1: Reactor water bulk temperature < 200'F System and Control Parameter Action Levels 1 2 3 Reactor Water Conductivity (uS/cm) at 25 0 C >2.0 --

Chloride (ppb) >100 --

Sulfate (ppb) >100 --

REACTOR CONDITION 2: Reactor water bulk temperature >200'F AND reactor thermal power <10%

System and Control Parameter Action Levels Reactor Water 1 2 3 Dissolved oxygen (ppb) >300 when reactor water temperature > 284 degrees Fe140 0 C)

Condensate Influent (CDI) conductivity at 250 C >10 Effluent (CDE) conductivity at 25 0 C >0.15 -

(after establishing condenser vacuum with steam air ejectors)

Feedwater Conductivity at 251C >0.15 Dissolved oxygen > 200 (after establishing condenser vacuum with steam air ejectors)

Suspended corrosion products (ppb) >100 REACTOR CONDITION 3: Reactor thermal power > 10%

System and Control Parameter Action Levels 1 2 3 Control Rod Drive Conductivity at 25 0C >0.15 --

Dissolved oxygen (ppb) >200 --

Feedwater (EPRI Guidelines for weekly integrated value)

Total copper (ppb) >0.5 --

Iron (ppb) Insoluble >5 Condensate Influent (CDI) conductivity at 251C >0.10 -- >10 Page 9 GAP-CHE-O1 Rev 02

ENCLOSURE 2: WATER CHEMISTRY GUIDELINES - UNIT 2 Operating Condition/Parameter 1

Action Level 2 3 I Prior to Startup I. Cold Shutdown (Mode 4,5)

a. Reactor Water and Fuel Storage Pool Conductivity (uS/cm) @ 251C > 2.0* >5.0* >10.o("^ < 1.0 Chloride (ppb) > 100- >200- > 0Soo') * <100 Sulfate (ppb) >100 - <100 0

pH at 25 C (Low <5.3-(1) <4.91 <4.6' (High) >8.6'(1) >9.3' >9.6-II. Startup/Hot Standby (Mode 2,3)

a. Reactor Water Conductivity ({S/cm) @ 25 0 C >1.0 >5.0 <1.0

>2.0"')

Chloride (ppb) >100(1

> > 200 <20 Sulfate (ppb) - >100 > 200 <20 Dissolved Oxygen (ppb) >300 pH @ 25 0 C (Low <5.6 ' <4.9- <4.6-(High) >8.6-" >9.3- >9.6-

b. Feedwater/Condensate Feedwater and CDE Conductivity ((uS/cm) @ 250C >0.15 - *_

Feedwater Suspended Corrosion Products (ppb) > 100 Condensate (CDI0 Conductivity (uS/cm)

Feedwater Dissolved Oxygen (ppb)

@ 251C >0.10-

>200"

.. '4 >0.5" J >1.o-..Q4

- <200^

IlI.Power Operation (Mode 1) (> 10% Power)

a. Reactor Water 0

Conductivity (,uS/cm) @ 25 C >0.30 >1.0"'1 >5.0 Chloride (ppb) >5 >20 > 100 Sulfate (ppb) >5 >20 > 100 0

pH at 25 C (Low <5.6' <4.9' <4.6' (High > 8.6"- >9.36

b. Feedwater/Condensate Feedwater and CDE Conductivity (uS/cm) @ 25 0 C >0.065' >0.1 ^ >0.2-Individual Condensate Demineralizer Outlet conductivity >0.2^^^^ >0.5^^^

(uS/cm) @ 251C Condensate (CDI) Conductivity/(vS/cm) @ 251C >0.10 >0.5^ - >1.0^. (2)

Feedwater Total Metals (ppb) Fe,Cu,NiZn Sol and Inso >15^ >30^ >60e Feedwater Total Iron (ppb) (Insol) >510 >20^ >40^

(Sol >1.0' >2.0^ >4.0' Feedwater Total Copper (ppb) >0.503). >2.01 >4.0-Feedwater and CDE Dissolved Oxygen (ppb) (Low <20 <10* <5-(High >50' >200, >550'

c. Control Rod Drive Water Conductivity (uSlcm) @ 25WC >0.15 Dissolved Oxygen(ppb) >200

d. Reactor Water and Feedwater****

Reactor Water Conductivity (pS/cm) @ 251C AND >0.3 Feedwater Soluble Copper (ppb) >0.3 (1) Technical Specification Actions are controlling.

Fuel Warranty Limits (2) Limit of 10vS/cm applies with no chemical addition After establishing condenser vacuum with steam air ejec' to circulating water system. ^^^ SER 89-069 and SER 90-142 (3) EPRI Guidelines weekly integrated value. **^^ RG 1.56 (4) Limit applies during Chemical Additions Page 10 GAP-CHE-01 Rev 02

Nine Mile Point 2 Category "A" - Examination Outline Cross Reference Operating Test Number Cat "A" Test: 1 Examination Level SRO Administrative Topic A.1 Subject

Description:

Shift Turnover Question Number: 1

[Question:--t -,---XlAAXi i - i - ;X Use today's date.

Assume you are 42 years old when answering this question.

Evaluate the following information and determine what requirements must be met before you fill a SSS position on January 1, 2000.

You filled a shift SSS position this year until September 1, when you were assigned to Operations Support until the end of the year. Since the assignment, you have stood the following 12-hour watches as SSS:

September: Three (3) 12-hour watches October: Three (3) 12-hour watches November: NO watches December: NO watches and none scheduled

. Medical exam and respiratory physical is completed on 11/30/98.

Documented in accordance with station procedures on 11/30/98.

SCBA and Scott full-face qualification including a fit-test for each is completed on 6/6/99. Documented in accordance with station procedures on 6/10/99.

With the exception of completing the remediation for a requal cyclic written exam failure last Friday, you have completed all training and passed all other evaluations.

Anser:

Must complete the training remediation, then stand at least two (2) 12-hour watches as the CRS or SSS by 12/31199.

Technical Reference(s): i:

S-ODP-TQS-0101, Rev 01 Section 3.10, 4.2, 4.4

Nine Mile Point 2 CateIo P"A" Examination Outlin ross Refrce O erating Test Number Cat "A" Test: 1 Examination Level RO Administrative Topic A.1I Subject Descri tion: Shift Turnover Question Number: 1 IKIA:#: : Importance: I 2.1.3 3.4 I Comments:

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION OPERATIONS ADMINISTRATIVE PROCEDURE S-ODP-TOS-0101 REVISION 01 ADMINISTRATIVE CONTROLS FOR MAINTAINING ACTIVE LICENSE STATUS AT NINE MILE POINT Approved by:

D. F.Topley Date Approved by:

D. P. Bosnic at/165 Dke' Effective Date: 08/24/98

3.9 Inactive License Holders Inactive license holders shall be certified by the Plant Manager to have met the conditions of 1QCFR55.53(f) by a License Reactivation Form (Attachment 3 or 4). These requirements include:

3.9.1 That the qualifications AND status of the licensee are current as specified in sub-section 3.10 AND 3.9.2 A minimum of 40 hours4.62963e-4 days 0.0111 hours 6.613757e-5 weeks 1.522e-5 months of shift functions under the direction of an operator OR senior operator, as appropriate AND in the position to which the operator will be assigned is completed.

The 40 hours4.62963e-4 days 0.0111 hours 6.613757e-5 weeks 1.522e-5 months must have included a complete tour of the plant AND review of all required shift turnover procedures. The 40 hours4.62963e-4 days 0.0111 hours 6.613757e-5 weeks 1.522e-5 months shall be in the same calendar quarter.

OR 3.9.3 For SRO limited to fuel handling one shift shall have been completed.

3.10 Additional Requirements on an Active License Holder For Licensed Operators to fill a Technical Specification required on-shift position, the following minimum requirements shall be complied with in addition to the requirements of subsection 3.9:

Meet requalification training requirements per NTP-TQS-102, Licensed Operator Requalification Training.

Be currently trained on use of (SCBA) Scott Air Paks, (annual requirement).

Have a current (SCBA) Scott Air Pak fit test on file, (biennial requirement).

Have a current Scott Full Face fit test on file, (biennial requirement which applies to Unit 1 only).

Have a current form NRC-396 on file (NRC Medical examination)

(biennial requirement).

Have a current respiratory physical examination on file, (biennial requirement if less than 45 years of age, otherwise annual).

Have corrective lenses available for use in (SCBA) Scott Air Paks.

Logged in SSS Log.

Page 4 S-ODP-TQS-0101 Rev 01

3.12 Corrective Lens License Restriction NOTE: Only the face piece spectacles designed for use in (SCBA) Scott Air Paks OR contact lenses meet the requirement for corrective lenses.

3.12.1 Licensed Operators with the corrective lens restriction are required to have corrective lenses available for use in (SCBA)

Scott Air Paks.

3.12.2 PRIOR to resuming license duties, Licensed Operators that have obtained corrective lenses for the first time shall be examined by the Site Medical Department to determine if a corrective lens restriction is required.

3.12.3 IF at any time a licensed operator receives a corrective lens restriction, the requirements listed above in step 3.12.1 shall be satisfied PRIOR to resuming license duties.

4.0 DEFINITIONS 4.1 ApDroved WatchstandinQ Positions at Nine Mile Point

SSS

ASSS

CSO OR ATCRO

Control Room NAOE

Refuel SRO 4.2 Calendar Quarter For purpose of this procedure Calendar Quarters will be as follows:

1st Quarter January 1 to March 31

2nd Quarter April 1 to June 30

3rd Quarter July 1 to September 30

4th Quarter October 1 to December 31 4.3 Actively PerforminQ the Function of a Licensed Operator Individual has a position on a shift crew that requires the individual to be licensed, as defined in the facility's Technical Specifications, and that the individual carries out, and is responsible for the duties covered in that position, including log keeping and shift turnover responsibilities.

Page 7 S-ODP-TQS-0101 Rev 01

4.4 10CFR55.53 Conditions of Licenses To maintain active -status, the licensee shall actively perform the functions of an operator or senior operator on a minimum of seven 8-hour or five 12-hour shifts per calendar quarter.

4.5 NMPC InterDretation of 10CFR55.53(e) 4.5.1 It is NMPC policy that to maintain license proficiency, watchstander station requirements for performing the duties of Station Shift Supervisor (SSS), Assistant Station Shift Supervisor (ASSS), Chief Shift Operator (CSO) OR At The Controls Reactor Operator (ATCRO), Nuclear Auxiliary Operation E (NAOE) and Refuel SRO are as follows:

LICENSE PROFICIENCY WATCH STANDER STATION REQUIREMENT STATION SHIFT SUPERVISOR (SSS) SRO ASSISTANT STATION SHIFT SUPERVISOR (ASSS) SRO CHIEF SHIFT OPERATOR (CSO) OR AT THE RO CONTROLS REACTOR OPERATOR (ATCRO)

NUCLEAR AUXILIARY OPERATOR E (NAOE) RO REFUEL SRO LSRO (min req.)

NOTE: When additional watchstanders are required to satisfy the minimum shift crew composition per Technical Specification requirements, the only three cases where more than two senior operators and two operators can be taken credit for are as follows:

a. During a reactor startup, credit for time performing the duties of a licensed operator may be taken by one additional Chief Shift Operator or Nuclear Auxiliary Operator - E (RO) when assigned to the Control Room.

b. During refuel floor activities where the Senior Reactor Operator and reactor operator(s) may take credit for time performing fuel movement activities.

c. During assignments for training or reactivation of license on shift under the direction of an active license holder.

4.5.2 It is NMPC's policy in the shutdown condition that two licensed senior operators and two Licensed Operators are required to maintain safe operation of the Units. This may be reduced on a case-by-case basis with Management concurrence.

Page 8 S-ODP-TQS-0101 Rev 01

Nine Mile Point 2 Category "A" - Examination Outline Cross Reference Operating Test Number Cat "A" Test: 1 Examination Level SRO Administrative Topic A.1 Subject

Description:

Shift Turnover Question Number: 2 Question: -

The plant is operating at 60% power. You have just taken turnover and assumed the night shift watch as the SSS. Total night shift compliment following turnover is:

Position Current Staffing SSS 1 ASSS 1 Licensed Operator 2 Non-Licensed Operator 3 STA 1 RP Technician 2 Chemistry Technician I Site Fire Brigade 5 At the shift brief, one of the Reactor Operators faints and is not able to fulfill the function of the reactor operator. What actions are required?

Answer:

Immediately initiate action to fill the vacant RO position within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

Techn'i'cal

References:

GAP-OPS-01, Rev 11 T.S. 6.2.2, T.S. Table 6.2.2-1 KIA #, K IMP ncrtaici:'

2.1.1, 2.1.3, 3.8, 3.4, 2.1.4, 2.1.5 3.4, 3.4 Comments:

Facility: Nine Mile Point # 2 Date of Examination: 12/06/99 Examination Level (circle one): SRO Operating Test Number: Cat A Test I Administrative Topic/Subject Describe method of evaluation:

Description 1. ONE Administrative JPM, OR

2. TWO Administrative Questions A. I Plant Parameter JPM: (New) Water Chemistry Operating Limits Determination (SRO ONLY).

Verification K/A 2.1.33, 2.1.34 Question: 1. Given watchstanding history, medical data and training data, Shift Turnover determine requirements to stand watches. (Active license requirements).

Question: 2. Given the number of shift personnel, determine if minmum manning reqiurements are being met. K/A 2.1.1, 2.1.3, 2.1.4, 2.1.5 A.2 Piping and Question: 1. Using the PIDs, trace the Fire Protection Water flow path from the Instrument motor driven fire water pump 2FPW-P2, to the RPV using RHS Train A.

Drawings 2RHS*MOV24A is available for injection. Where necessary, add EOP equipment to be used. K/A 2.1.24 PRA (IPE: Fire Water - RHR Crosstie)

Question: 2. Using a PID drawing, describe how the motor operated Testable Check Bypass Valve RHS*MOV67B will respond to a LOCA signal. K/A 2.1.24 Question 1. Review the attached Survey 68 for Turbine Building 277' A.3 Radiation Work Condensate Demin Valve Aisle and identify the radiological hazard(s).

Permits K/A 2.3.10 Question 2. Review a Radiation work Permit (22, Revision 313), and identify sign in requirements for Auxiliary Operators, protective clothing requirements and actions to be taken if an AO has to be sent into an area with a general area radiation level of 20 mremfhr for four (4) hours? K/A 2.3.10 A.4 Emergency JPM: (New) Emergency Plan classification of each SRO candidates scenario Classification (to be administered after each scenario). K/A 2.4.29, 2.4.41 t

I

6.0 ADMINISTRATIVE CONTROLS 6.1 RESPONSIBILITY and shall delegate in 6.1.1 The Plant Manager shall be responsible for overall unit operation absence.

writing the succession to this responsibility during the Plant Manager's absence from the control 6.1.2 The Station Shift Supervisor - Nuclear (or during the Supervisor's command function. A room room, a designated individual) shall be responsible for the control shall be reissued to all Chief Nuclear Officer management directive to this effect, signed by the station personnel annually.

6.2 ORGANIZATION 6.2.1 Onsite and Offsite Organization operation and corporate An onsite and an offsite organization shall be established for unit shall include the positions for activities affecting management. The onsite and offsite organization the safety of the nuclear power plant.

and defined from

a. Lines of authority, responsibility and communication shall be established including all operating the highest management levels through intermediate levels to and and updated, as organization positions. Those relationships shall be documented of departmental appropriate, in the form of organization charts, functional descriptions positions or in

-responsibilities and relationships, and job descriptions for key personnel documented in the equivalent forms of documentation. The organization charts shall be of departmental responsibil-Final Safety Analysis Report, and the functional descriptions in.

documented ities and relationships and job descriptions for key personnel positions are procedures.

plant nuclear safety

b. The Chief Nuclear Officer shall have corporate responsibility for overall of the staff in and shall take any measures needed to assure acceptable performance that continued operating, maintaining, and providing technical support in the plant so nuclear safety is assured.

shall have control

c. The Plant Manager shall have responsibility for overall unit operation and of the plant.

over those resources necessary for safe operation and maintenance functions

d. The persons responsible for the training, health physics and quality assurance to responsible may report to an appropriate manager onsite, but shall have direct access of training, corporate management at a level where action appropriate to the mitigation health physics and quality assurance concerns can be accomplished.

UNIT STAFF 6.2.2 The unit organization shall be subject to the following:

shown in Table

a. Each on-duty shift shall be composed of at least the minimum shift crew 6.2.2-1; NINE MILE POINT - UNIT 2 6-1 Amendment No. $, i, ii, 83

6.0 ADMINISTRATIVE CONTROLS ORGANIZATION UNIT STAFF 6.2.2 (Continued) fuel is in shall be in the control room when Licensed Operator 3, at least one the unit.

b. At least one Licensed CONDITIONS 1, 2, or In OPERATIONAL of the reactor.

or Licensed Operator shall be at the controls Senior Operator : n t~hp shall be on site when Tuel

c. A Radiation Protection Technician*

reactor.

room during Operators shall be present in the control from

d. At least two Licensed scheduled reactor shutdown, and during recovery reactor startup, reactor trips.

shall be required in the control roomisduring

e. A Licensed Senior Operator the emergency plan the 1, 2, and 3 and whenSupervisor OPERATIONAL CONDITIONS - Nuclear, This may be the Station Shift or other individuals within a

activated. Supervisor - Nuclear Assistant Station Shiftlicense. When the emergency plan is activated Advisor valid senior operator 1, 2, or 3 and a dedicated Shift Technical - Nuclear I OPERATIONAL CONDITIONS the Assistant Station Shift Supervisor -

is not on-shift, then Advisor and the Station Shift Supervisor Licensed becomes the Shift Technical to the control room until an additional Nuclear is restricted Senior Operator arrives.

and Fire Brigade composition may be less Technician 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , in

The Radiation Protection for a period of time not to exceed taken than the minimum requirements absence, provided immediate action is shift any order to accommodate unexpected positions. This provision does not permit crewman to fill the required unmanned upon shift change due to an oncoming crew position to be being late or absent.

Amendment No. a,34 2 6-la NINE MILE POINT - UNIT

6.0 ADMINISTRATIVE CONTROLS ORGANIZATI ON UNIT STAFF 6.2.2 (Continued)

Fuel Handling shall be

f. A Licensed Senior Operator or Licensed Senior Operator Limited to site boundary. All core responsible for all movement of new and irradiated fuel within the or Licensed Senior alterations shall be directly supervised by a Licensed Senior Operator during this Operator Limited to Fuel Handling who has no other concurrent responsibilities by a member of the operation. All fuel moves within the core shall be directly monitored reactor analyst group.

times. The Fire Brigade

9. A Fire Brigade* of five members shall be maintained on site at all of the minimum shift shall not include the Shift Supervisor and the two other members required for other crew necessary for safe shutdown of the unit and any personnel essential functions during a fire emergency.

limit the working hours

h. Administrative procedures shall be developed and implemented to Senior Operators, of unit staff who perform safety-related functions; e.g., Licensed personnel.

licensed operators, health physicists, auxiliary operators, and key maintenance use of overtime. The

i. Adequate shift coverage shall be maintained without routine heavy hour day, nominal 40-hour objective shall be to have operating personnel work an 8 to 12 problems require week while the unit is operating. However, in the event that unforeseen of shutdown for substantial amounts of overtime to be used, or during extended periods basis the refueling, major maintenance, or major unit modifications, on a temporary following guidelines shall be followed:

straight,

1. An individual should not be permitted to work more than 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months excluding shift turnover time.

any 24-hour

2. An individual should not be permitted to work more than 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months in 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months in period, nor more than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months in any 48-hour period, nor more than any 7-day period, all excluding shift turnover time.

including-shift

3. A break of at least 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months should be allowed between work periods, turnover time.

may be less than

The radiation protection qualified individual and Fire Brigade composition hours, in order to the minimum requirements for a period of time not to exceed 2 taken to fill the required accommodate unexpected absence, provided immediate action is positions.

NINE MILE POINT - UNIT 2 6-2 Amendment No. A, II,

6.0 ADMINISTRATIVE CONTROLS ORGANIZATION UNIT STAFF 6.2.2.i (Continued)

4. Except during extended shutdown periods, the use of overtime should be considered on an individual basis and not for the entire staff on a shift.

Any deviation from the above guidelines shall be authorized by the Plant Manager, or higher levels of management, in accordance with established procedures and with documentation of the basis for granting the deviation. Controls shall be included in the procedures so that individual overtime shall be reviewed monthly by the Vice President Nuclear Generation or a designee to assure that excessive hours have not been assigned.

Routine deviation from the above guidelines is not authorized.

The General Supervisor Operations, Supervisor Operations, Station Shift Supervisor Nuclear and Assistant Station Shift Supervisor Nuclear shall hold senior reactor operator licenses.

6.2.3 INDEPENDENT SAFETY ENGINEERING GROUP FUNCTION unit 6.2.3.1 The Independent Safety Engineering Group (ISEG) shall function to examine other operating characteristics, NRC issuances, industry advisories, Licensee Event Reports, and design, sources of unit design and operating experience information, including units of similar which may indicate areas for improving unit safety. The ISEG shall make detailed recommendations for revised procedures, equipment modifications, maintenance activities, operations activities, or other means of improving unit safety to the Vice President - Nuclear Safety Assessment and Support.

COMPOSITION 6.2.3.2 The ISEG shall be composed of at least five, dedicated, full-time engineers located on of site. Each shall have a bachelor's degree in engineering or related science and at least 2 years professional level experience in his/her field, at least 1 year of which experience shall be in the nuclear field.

RESPONSIBILITIES and the 6.2.3.3 The principal function of the ISEG is to examine plant operating characteristics various NRC and industry licensing and service advisories, and to recommend areas for improving including plant operations or safety. The ISEG will perform independent review of plant activities, to the maintenance, modifications, operational concerns, and analysis and make recommendations Vice President - Nuclear Safety Assessment and Support.

NINE MILE POINT - UNIT 2 6-3 Amendment No. i, ii, i/.

TABLE 6.2.2-1 MINIMUM SHIFT CREW COMPOSITION(a)(b)

OPERATIONAL CONDITIONS 1, 2, 3, POSITION 12 3 4, 5 4, 5 Station Shift Supervisor(d) 1 1 1(e) 1(c)

Assistant Station Shift Supervisor(g) 1 1 None 1(c)

Operator 2, 3(h) 2 1 2(c) 3(c)(h)

Unlicensed(f) 2 2 1 3(c)

Shift Technical Advisor(g) 1 1 None 1(c)

TABLE NOTATIONS (a) At any one time, more licensed or unlicensed operating people could be present for maintenance, repairs, refuel outages, etc.

(b) The shift crew composition may be one less than the minimum requirements of Table 6.2.2-1 for a period of time not to exceed 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months in order to accommodate unexpected absence of on-duty shift crew members, provided immediate action is taken to restore the shift crew composition to within the minimum requirements of Table 6.2.2-1. This provision does not permit any shift crew position to be unmanned upon shift change because an oncom-ing shift crewman scheduled to come on duty is late or absent.

(c) For operation longer than 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months without process computer.

(d) Any time the Shift Supervisor is absent from the control room while the unit is in OPERATIONAL CONDITION 1, 2, or 3, the Assistant Station Shift Supervisor when not in the STA function, or another individual with a valid Senior Operator license shall be designated to assume the control room command function. During any absence of the Shift Supervisor from the control room while the unit is in OPERATIONAL CONDITION 4 or 5, an indi-vidual with a valid Senior Operator license or Operator license shall be designated to assume the control room command function.

to (e) An additional Senior Reactor Operator or Senior Reactor Operator Limited Fuel Handling who has no other concurrent responsibilities shall supervise all core alterations.

(f) Those operating personnel not holding an Operator or Senior Operator license.

(g) The Assistant Station Shift Supervisor shall hold a Senior Operator's license and, if qualified, may perform the Shift Technical Advisor func-tion when the Site Emergency Plan is activated in OPERATIONAL CONDITIONS 1, 2, or 3, if a dedicated Shift Technical Advisor is not available.

(h) OPERATIONAL CONDITION 2 only.

6-6 Amendment No. 34 X14, NINE MILE POINT - UNIT 2

3.1.14 (Cont)

h. Ensures supervised personnel receive training in appropriate radiological protection practices, procedures, and ALARA principles.

i. Promotes safe working conditions and practices by ensuring supervised personnel receive required instructions concerning industrial safety.

j. Ensures strict adherence to company and station security provisions and procedures.

k. Promotes good housekeeping by periodically inspecting areas assigned to the Radwaste Operations Section.

3.2 Operating Shift Complement 3.2.1 The General Supervisor Operations (or designee) shall ensure minimum operating shift complements are established and maintained as follows:

OPERATION NORMAL HOT COLD W/O PROCESS POSITION OPERATION STARTUP SHUTDOWN SHUTDOWN REFUELING COMPUTER (C)

Station Shift 1 1 1 1 1 (b) 1 Supervisor (f)

Assistant Station 1 1 1 None None 1 Shift Supervisor (a)(f)

Licensed Operator (f) 2 3 2 1 1 2 (LU) 3 (U2) Cd)

Nonlicensed Operator 2 2 1 (U) 1 1 3 f) 2 CU2) 2 (U2)(g) 2 (U2)(g)

Shift Technical 1 1 1 None None 1 Advisor (a)(f)

Radiation Protection 1 1 1 1 1 1 Technician (e)

Chemistry Technician 1 1 None None 1 1 Site Fire Brigade 5 5 5 5 5 5

a. The ASSS may assume the responsibilities of the STA provided that:

1. The individual holds a BS degree in Physical Science or Engineering, or holds a PE license.

2. The individual is qualified as an STA.

Page 15 GAP-OPS-O1 Rev 11

3.2 (Cont)

b. An additional Senior Reactor Operator or Senior Reactor Operator Limited to Fuel Handling who has no other concurrent responsibilities shall supervise all core alterations.

c. For operation longer than 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months without process computer.

d. At Unit 2, a minimum of 3 licensed operators shall be on shift during startup without the Process Computer, otherwise the minimum requirement is 2.

e. A Radiation Protection Technician shall be onsite when fuel is in the reactor.

f. The on-duty SSS, ASSS, STA, Licensed Operator(s), and Nonlicensed Operator(s) shall remain within the protected area except as provided in Step 3.2.3.

g. At Unit 2, a minimum of 2 Nonlicensed operators are required when the process computer is out of service for less than or equal to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

3.2.2 At any one time, more licensed or unlicensed operating people could be present for maintenance, repairs, refuel outages, etc.

3.2.3 The shift crew composition may be one less that the minimum requirements of Step 3.2.1 for a period of time not to exceed 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months in order to accommodate unexpected absence of on-duty shift crew members.

a. Immediate action shall be taken to restore the shift crew composition to within the minimum requirements of Step 3.2.1.

b. This provision does not permit any shift crew position to be unmanned upon shift change because an oncoming shift crewman scheduled to come on duty is late or absent.

3.2.4 Shift personnel expecting to be late or unable to report for work at the scheduled time shall, at the earliest opportunity, inform the SSS or the ASSS of the situation.

3.2.5 The SSS or ASSS shall make the necessary arrangements for obtaining replacements or holding over on-shift personnel as required to comply with minimum staffing requirements.

3.2.6 The Station Shift Supervisor (SSS) or Assistant Station Shift Supervisor (ASSS) shall have the authority to call in off-duty personnel from any department, as necessary, to supplement or replace personnel.

Page 16 GAP-OPS-01 Rev 11

Cte oination U Cross Reference Operating Test Number Cat "A" Test: 1 Examination Level SRO Administrative Topic A.3 Subject

Description:

Radiation Work Permits Question Number: 2 IQuesti'on: -::- .iy:.0g' ia:-it g Ii:0-i 0it0Rf;- ' - i Review the attached Radiation Work Permit (22, Revision 313) and identify the following:

a. Sign in requirements for Auxiliary Operators

b. What protective clothing is required?

c. What actions must be taken if an AO has to be sent into an area with a general area radiation level of 20 mrem/hr for four (4) hours?

Anser:-

a. Auxiliary Operators should sign in at the beginning and end of their shift.

b. Worker Type 1 is No protective clothing required.

c. AO is expected to receive 80 mrem (20 x 4). Radiation Protection must be notified and approval obtained to exceed 50 mrem/day.

Technical Refereinrie s:

S-RAP-RPP-0202, Attachment 1 GAP-RPP-07, Sect. 3.5 D0AD#: .I 0I~m por ' S Anc l2.3.10 12.9 C m nt s: Ie --".I-. ?H I-

. ,.;,.i

Tuesday, June 29,1999

.9 exeiXl DVrLea APPROVED FOR WORK Radiation Work Permit: 22 revision: 313 OPERATIONS DEPARTMENT (STANDING RWP)

Perform Rounds/MarkupsNalve Lineups/Minor High Radiation Area Survey Data:

dprn/1 00Tcn2, <0.3 Maximum Walk Through to Work Area <100 mRemlhr, <40,000 DAC Maximum Work Area <100 mRem/hr, <40,000 dpm/100cm2, <0.3 DAC As Posted and/or per RP Briefing TASK: I revision: 73 Normal Rounds/MarkupslObservations and Inspections Dose Alarm: 50 mRem Dose Rate Alarm: 100 mRem/hr Protective Clothing Requirements: WorkerType 1 TLD, Electronic Dosimeter Instructions:

1) Exposure guide = 50 mRem/day. RP Approval required to exceed the daily guide.

2) Personnel shall sign in/out on this RWP for each RCA entry.Shift personnel requiring frequent, routine or immediate access may sign in/out once per shift

3) Keep RP informed of work activities in progress.

4) Access the RCA at ACB 261' or as approved by RP.

5) Protective clothing requirements as posted or required by RP.

6) No entry above arms reach or access to unsurveyed permanently installed platforms without RP approval.

7) As approved by RP for High Radiation Area entries.

8) Stay time limited to 1 minute in areas > 1000 mRem/hr, unless specifically approved otherwise by RP.

No entry into the following unless specifically approved approved by RP: Very High Radiation Areas, High Radiation Areas, Neutron Radiation Areas, Airborne Radiation Areas, Contaminated Areas > 40,000 dpm/100cm2.

aid will complywithe RWP Scanning or Bung IgWP id Task number signify th* I have real, understand

ATTACHMENT 1 (Cont)

Code Minimum Clothing Guide A Worker type 1 B . 400 - 1,000 dpm/100 cmz Worker type 2(see Notes 4,5 and 6) 1,000-25,000 dpm/100 cm2 Worker type 2(See Notes 4,5 and 6) 25,000 dpm/100 cm2, C applies C Worker type 3 (see Note 1)

D Worker type 3 40,000 - 100,000 dpm/lOOcm2 determine need to prescribe E requirements E Worker type 4 (see Note 2)

F Plastic wet suit(see Notes 2 and 3) PLUS Worker type 3 Assistance should be available for undressing G Worker type 3 PLUS Air-line bubble suit or equivalent Assistance should be available for undressing Worker Tvpe 1: No Protective Clothing required.

Worker Tyoe 2: Cotton liners, Rubber gloves, Cotton booties, Rubber shoe covers.

Worker Type 3: Cotton liners, Rubber gloves, Cotton booties, Rubber shoe covers, Cotton coveralls, Cotton cap, Cotton hood.

Worker Tvye 4: Cotton liners, Rubber gloves(2 pair), Cotton booties(2 pair), Rubber shoe covers, Cotton coveral7s(2 Pair), Cotton cap. Cotton hood.

Worker Type 5: As defined by Radiation Protection Personnel Page 11 S-RAP-RPP-0202 Rev 04

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION GENERATION ADMINISTRATIVE PROCEDURE GAP-RPP-07 REVISION 05 INTERNAL AND EXTERNAL DOSIMETRY PROGRAM TECHNICAL SPECIFICATION REQUIREDl\

Approved by: .

Date R. G. Smith Plant Manager*,7-4nit 1 Approved by:

Plant Manager - Unit 2 Date N. C. Paleologos THIS IS A FULL REVISION 12 /31/1998 Effective Date: __ _ _ _ _ _ _ _ _ _ _ _ _ _

3.3.5 (Cont)

b. The Radiation Protection Computer System (RPCS) will serve as the database/tracking system for determining compliance with all occupational dose limits

c. RP Supervision shall perform an assessment of the doses accrued by individuals who exceed their administrative dose limit 3.4 Normal Use and Placement of DosimetrY 3.4.1 Whole Body dosimetry shall be placed on the body in a manner such that its measurement represents uniform exposure of the or whole body, including the extremities, unless the extremities other Whole Body areas are specifically monitored as per S-RPIP-5.1 3.4.2 Normal use and placement of dosimetry on the body of monitored individuals is as follows:

a. Should be attached to a lanyard.

b. Worn on the outermost (personal) garment.

c. Worn on the front torso, on or above the beltline and below the neck.

d. Rad Protection will determine the need for other requirements, as per S-RPIP-5.1.

3.4.3 Workers should verify Electronic Dosimeters are activated prior to RCA entry and should periodically check their SRDs while in the RCA 3.5 Problems or Questions with Dosimetry 3.5.1 Workers shall immediately report to Rad Protection when a problem with dosimetry is suspected 3.5.2 Workers who have lost or damaged dosimetry shall, immediately upon discovery, contact Rad Protection who will provide instructions as per S-RPIP-5.1 3.5.3 Workers whose SRD alarms or reads offscale (where applicable) shall immediately leave the area and contact Rad Protection 3.5.4 Rad Protection shall determine the need for an evaluation of exposure received as per S-RPIP-5.25 Page 8 GAP-RPP-07 Rev 05

3.5.5 Personnel visiting other Nuclear Sites where occupational radiation exposure is expected to be received, shall contact Radiation Protection, and have their dosimetry dispositioned as per S-RAP-RPP-0704 3.6 Internal and External Dose Determination 3.6.1 External Dose Determination

a. TLDs shall be prepared and returned to the TLD Processor for external dose determination, and dose results received by Dosimetry, as per S-RAP-RPP-0704

b. TLD results LESS THAN 10 mRem shall be recorded in personnel exposures files as '0' mRem

c. Skin dose assessments resulting from contamination of the skin shall be made as per S-RPIP-5.5

d. The external exposure received by the embryo/fetus of a declared pregnant woman shall be equal to the Deep Dose Equivalent (DDE) of the declared pregnant woman.

e. Neutron dose estimates shall be made by Rad Protection as per S-RPIP-5.3.

3.6.2 Internal Dose Determination

a. In-Vivo Bioassay (ie Whole Body Counting) of individuals shall be performed as per S-RPIP-5.12 or S-RTP-122, where applicable

b. In-Vitro Bioassay (eg Urine) sample collection shall be performed as per S-RPIP-5.7

c. Bioassay results shall be evaluated, as necessary, as per S-RPIP-5.7

d. Internal dose results LESS THAN 10 mRem shall be recorded in personnel exposures files as '0' mRem, or other similar assignments (eg NC for not calculated)

e. Embryo/fetus internal exposures shall be determined using the guidance provided by Reg. Guide 8.36 (7/92), unless otherwise specified by RP Supervision.

1. The dose to the maternal uterus resulting from radioactivity burdens in the declared pregnant woman, should be assumed to represent the internal exposure received by the embryo/fetus.

3.6.3 Controlled Area dose assessments shall be performed as per S-RAP-ALA-0103 Page 9 GAP-RPP-07 Rev 05

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION RADIATION PROCEDURE ADMINISTRATIVE S-RAP-RPP-0202 REVISION 04 SFLFrTTIN.N DONNING.

AND REMOVAL OF PROTECTIVE CLOTHING Approved by:

V. L. Schuman Manager Radiation on - Unit Date 4 2v-99 Approved by:

D. W. Barcomb Manager Radia ion Protection - Unit 2 Date Effective Date: 04/30/1999

ATTACHMENT 1: PROTECTIVE CLOTHING GUIDE INSPECTIONS & HEAVY WORK OBSERVATIONS ACTIVITY

_I T

DRYWLK WETWORK DRYWORK WETWRK

(dpm/lOOcm 2 ) *(dpm/lOOcm 2) *(dpm/lOOcm 2 ) *(dpm/lOOcm2)

<400 <400 <400 <400 A A A A 400 - 40,000 400 - 40,000 400 - 100,000 400 - 400,000 C(B) D F

>40,000 >40,000 >100,000 >400,000 IDl F E G

Removable surface contamination Page 10 S-RAP-RPP-0202 Rev 04

ATTACHMENT 1 (Cont)

Code Minimum ClothinQ Guide A Worker type 1 B . 400 - 1,000 dpm/100 cm' Worker type 2(see Notes 4,5 and 6)

1,000-25,000 dpm/100 cm2 Worker type 2(See Notes 4,5 and 6)

25,000 dpm/100 cm2 C applies C Worker type 3 (see Note 1)

D Worker type 3 40,000 - 100,000 dpm/lOOcm 2 determine need to prescribe E requirements E Worker type 4 (see Note 2)

F Plastic wet suit(see Notes 2 and 3) PLUS Worker type 3 Assistance should be available for undressing G Worker type 3 PLUS Air-line bubble suit or equivalent Assistance should be available for undressing Worker Type 1:No Protective Clothing required.

Worker Type 2: Cotton liners, Rubber gloves, Cotton booties, Rubber shoe covers.

Worker Type 3:Cotton liners, Rubber gloves, Cotton booties, Rubber shoe covers, Cotton coveralls, Cotton cap, Cotton hood.

Worker Type 4: Cotton liners, Rubber gloves(2 pair), Cotton booties(2 pair), Rubber shoe covers, Cotton coveral7s(2 Pair), Cotton cap. Cotton hood.

Worker TY-e 5: As defined by Radiation Protection Personnel Page 11 S-RAP-RPP-0202 Rev 04

ATTACHMENT 1 (Cont)

NOTES: 1. Cap should cover hair. A hood should be worn over the respirator straps unless water is overhead. If so, a plastic hood should be required.

2. Personnel should be required to wear some form of facial skin protection such as face shields in highly contaminated areas or when working in tight, confined spaces (e.g. between exposed turbine blades).

3. If work is to continue after removing plastic clothing, the protective cloth clothing should be changed to prevent migration of contaminants.

4. Lab coats may be specified as part of minimum clothing requirements to preclude personal clothing contaminations from inadvertent contact with surroundings.

5. Type of gloves should be consistent with expected contamination state (e.g. rubber for wet environment, rubber or cloth for dry environment).

6. If the activity involves repeated handling or rubbing against objects (e.g., cable pulls, overhead work, crawling or climbing, etc.), consider the use of scrub suits, or alternatives (Tyveks).

Page 12 S-RAP-RPP-0202 Rev 04

Nine Mile Point 2,'

Catego "A" - Examination Outline Cross Refeene Operating Test Number Cat "A" Test: 1 Examination Level SRO Administrative Topic A.2 Subject

Description:

P&lDs Question Number: 2 Question:

The plant is operating at power, when a LOCA signal is received.

Using RESIDUAL HEAT REMOVAL PRINT PID-31A-13, describe how the motor operated Testable Check Bypass Valve RHS*MOV67B is lined up during power operations and how the valve will respond to the LOCA signal.

Valve is closed and will remain closed.

Per Note 9, The power supplies to the motor operator are opened to preclude spurious actuation during a control room fire.

l,Techhnical Referie6 s: 's PID-31A-13, Note 9 l:KHA.#: . lImportane:1 <.

l2.1.24 3.1

)00** IW I 'M i' Y,, , , :.F. .. ':

/ !

Nin MlePoint 2:"'

Cat gory "A" E' ination OutlineCross Re ee Operating Test Number Cat "A" Test: 1 Examination Level SRO Administrative Topic A.2 Subject

Description:

Piping and Instrument Drawings Question Number: 1 Question:

Using the PlDs, trace the Fire Protection Water flow path from the motor driven fire pump, 2FPW-P2, to the RPV using RHS Train A. 2RHS*MOV24A is available for injection. Where necessary, add EOP equipment to be used.

Answer:

PID 43A, J-7 2FPW-P2, motor driven fire pump PID 43A, L3, L-4 exit to PID 43B, K-3 PID 43B, K-3 fire water from PID 43A PID 43B, 1-4 exit to PID 43G, J-9 PID 43G, J-9 fire water from PID 43B PID 43G, H-9 exit to PID 43F, E-9 PID 43F, E-9 fire water from PID 43G PID 43F, G-6 disconnect fire hose from FHR (fire hose reel) 93 and connect EOP fire hose to FHR 93. Connect the EOP fire hose reel to Condensate Makeup and Transfer System blind flange (PID 4B, G-8)

PID 4B, G-8 fire water from PID 43F Blind flange for connecting EOP fire hose using equipment in EOP toolbox.

PID 4B, H-8 exit to PID 31A, A-1 PID 31A, A-1 fire water from PID 4B PID 31A, C-5 fire water injection to the RPV using 2RHS*MOV24A NOTE: It is not necessary to identify the valves on PIDs which are closed or verified closed to perform this evolution. (i.e., 2RHS*MOV33A [C-2] and 2RHS*MOV38A [B-6] on PID 31C, 2RHS*MOV12A [1-6] on PID 31D, 2RHS*MOV8A [8-3] on PID 31F).

sz-'e- '1;o -r" ' I A IL 4:; LAL e is ) Z; , I O Y'

Nine Mile Point 2 0Ctgor "A' - Examination Outline ross Reference Operating Test Number Cat "A" Test: 1 Examination Level SRO Administrative Topic A.2 Subject

Description:

Piping and Instrument Drawings Question Number: 1 Technical Reference(s):

N2-EOP-06, Att. 6, Rev 05, Section 3.1 PID 43A, B, G, F PID 4B PID 31A FKIAS#t: IlImportance:

2.1.24 3.1

[Cotmments:

Nine Mile Poit 2 Cataorv "A" xamination Outline Cross Re'ferendce IO6Deratina Test Number Cat "A" Test: 1 Examination Level SRO Administrative Topic A.3 Subject

Description:

Radiation Work Permits Question Number: 1 Question:

Review the attached Survey 68 for Turbine Building 277' Condensate Demin Valve Aisle and identify the radiological hazard(s).

Answer: N N

a. Contaminated areas identified by lines with Xs on the left hand side of the room with contamination levels of (from bottom of page) 720dpm/1 OOcm 2 ,

3000dpm/1OOcm2, and 31OOdpm/1 OOcm2.

b. High radiation levels in the bottom left hand side of the Valve aisle with radiation levels of 11 5mr/hr, 130mr/hr and 120 mr/hr.

Teclinicpal Re ereince(s): M ? l S-RAP-RPP-0103, Sect. 4.0 K/A#: - - Importance:F 2.3.10 2.9 Cmments: n'N/ NN, i.

enRehr genefal area -contminaton in npriv10cmc No 1 detec:ed unless amervise noted.

rnRadlr ganefal area SU -contaminaion on component in dpmtiCCcrzn 1 0 % of ail smears >1 CCdpm/1 0acm2 n0cm - dose rate C 30cm frcm component

- dose aboundary

=-_,.7- itocaon of LAW

_ _ate

-,I onay e-e=<io enIŽ

%ia TVI- c#

were counted for a with results u

<10dprr/10Ccm2 unless athersise 'noted

%^j Z Lj~r c R IIS(1 I-Ic.. laoo I)--

> ,c ,?, C ';-e&

'LC+~

1- i=,-i* Rx power levei: Io 0 %

Surveyed by: C ALLiso r I

.z' 44 46 5 9(-

HlZE I>{L~f- is, L3 -9<ct9 -7 i i 1

< 14 #- S-n f 7 f- -:?-<11

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION RADIATION PROTECTION ADMINISTRATIVE PROCEDURE S-RAP-RPP-0103 REVISION 09 POSTING RADIOLOGICAL AREAS Approved by:

V. L. Schuman Manager Radiation Protection --Unit 1 Date Approved by:

D. W. Barcomb Manager Radiation Protection - Unit 2 Date Effective Date: 04/08/99

3.3.4 (Cont)

d. Radiation Protection should observe and assist workers with personal monitoring prior to entering the Green Area.

e. Surveying the transport cart for RCA release should be performed per station procedure with the inside of the cart being surveyed at least once per shift when in use to ensure radiological cleanliness. Personal belongings inside the cart may be transferred to and from the Green Area without being surveyed.

4.0 DEFINITIONS 4.1 Accessible Floor level up to approximately 6 feet and permanently installed platforms capable of being reached by a portion of the whole body. Does not include overhead areas that require climbing on plant structures or the use of portable ladders, scaffolding, etc.

4.2 Airborne Radioactivity Area A room, enclosure, or area in which airborne radioactive materials, composed wholly or partly of licensed material, exist in concentrations:

a. In excess of the derived air concentrations (DACS) specified in Appendix B, to §§ 20.1001 - 20.2401, or

b. To such a degree that an individual present in the area without respiratory protective equipment could exceed, during the hours an individual is present in a week, an intake of 0.6 percent of the annual limit on intake (ALI) or 12 DAC hours.

4.3 Boundary A means of limiting access by use of ropes, step-off-pads, tape, and other physical structures used to border a radiologically controlled area. The vertical planes formed by rope or other structures should define the area of control unless otherwise specified by RP Supervision.

4.4 Contaminated Area Areas accessible to personnel where surface contamination exceeds:

4.4.1 400 dpm/100 cm2 removable beta-gamma; OR 4.4.2 20 dpm/100 cm 2 removable alpha.

Page 9 S-RAP-RPP-0103 Rev 09

4.5 Deep Dose Equivalent The dose equivalent at a tissue depth of 1 cm which applies to external whole body exposure.

4.6 Hands Off Inspection Inspections conducted in radiologically controlled areas limiting physical contact with plant components and structures to that necessary to maintain individual safety (e.g., hand rails, railings).

4.7 Locked High Radiation Area An area, accessible to individuals, in which radiation levels could result in an individual receiving a dose equivalent in excess of 1000 mrem in one hour at 30 cm from the radiation source or from any surface that the radiation penetrates.

4.8 HiQh Radiation Area An area, accessible to individuals, in which radiation levels could result in an individual receiving a dose equivalent in excess of 100 mrem in one hour at 30 cm from the radiation source or from any surface that the radiation penetrates.

4.9 Hot Particle Area Work area within the RCA where hot particles have been identified.

4.10 Hot Spot A locally intense source of radiation in which whole body exposure is greater than 25 mRem/hr at 30 cm and exceeds general area radiation levels by a factor of 5.

4.11 Derived Air Concentration The concentration of a given radionuclide in air which, if breathed by the reference man for a working year of 2,000 hours0 days 0 hours 0 weeks 0 months under conditions of light work (inhalation rate 1.2 cubic meters of air per hour), results in an intake of one Annual Limit of Intake (ALI). DAC values are given in Table 1, Column 3, of appendix B to §§ 20.1001 - 20.2401.

4.12 Neutron Radiation Area Areas accessible to personnel in which there exists neutron radiation at levels such that a major portion of the body could receive a neutron dose equivalent in excess of 2 mrem in one hour.

4.13 Posted Area Room, area, component, etc., that has a sign bearing the radiation caution symbol and a warning of the radiological conditions in the room or area.

Page 10 S-RAP-RPP-0103 Rev 09

4.14 Radiation Area Areas accessible to individuals in which there exists radiation at such levels that an individual could receive a dose equivalent in excess of 5 mrem in any one hour at 30 cm from the radiation source or from any surface that the radiation penetrates.

4.15 Radioactive Material For the purposes of tagging or labeling items or containers, radioactive materials are:

4.15.1 Any item or liquid removed from a contaminated area or system until sampled or surveyed by Radiation Protection personnel or other designated qualified individual.

4.15.2 Material inside the RCA that exceeds 18000 cpm/15 cm2 (5 mRad/hr) fixed contamination or removable contamination in excess of 400 dpm/100 cm2 beta-gamma or 20 dpm/100 cm2 alpha.

4.15.3 Material (other than natural uranium or thorium) determined by Radiation Protection to exceed the applicable quantities listed in IOCFR20 Appendix C.

4.15.4 Material consisting only of natural uranium or thorium determined by Radiation Protection to exceed 10 times the applicable quantities listed in 10CFR20 Appendix C.

4.15.5 Any liquid determined to exceed the applicable concentrations listed in IOCFR20, Appendix B.

4.15.6 Material for release from the RCA determined by Radiation Protection to exceed the applicable quantities listed in 10CFR20 or as per requirements of S-RPIP-3.3.

4.16 Radioactive Material Storage Area Areas designated for storage of radioactive materials in accordance with GAP-INV-02, Control of Material Storage Areas which:

4.16.1 Contain Radioactive Material that exceeds Restricted Area Control Limits of 18000 cpm/15 cm2 fixed contamination or removable contamination of 400 dpm/100 cm2 beta-gamma or 20 dpm/100 cm2 alpha.

4.16.2 Contain Radioactive Materials in excess of 10 times (or natural uranium or thorium in excess of 100 times) the quantity of materials specified in IOCFR20, Appendix C, or 12 NYCRR, Table 7.

Page 11 S-RAP-RPP-0103 Rev 09

4.17 Radiologically Controlled Area (RCA]

Major plant areas access to which is limited for the purpose of protecting personnel from exposure to radiation and contamination.

Examples include the Reactor, Turbine, Radwaste and Offgas Buildings.

Other radiologically controlled areas may be established with protective requirements specified by RP Supervision. Examples might include Radioactive Material Storage Areas at the warehouse or elsewhere on site.

4.18 Temporarv Shielding Any material authorized by the RP Supervisor or Designee to reduce beta, gamma or neutron exposure.

4.19 Very High Radiation Area Areas accessible to personnel in which radiation levels could result in an individual(s) receiving an absorbed dose in excess of 500 rads in one hour at one meter from the source or any surface that the radiation penetrates.

Potential VHRA include, but are not limited to:

TIP Rooms

Upper Elevations of the Drywell during fuel moves

Spent Fuel Pool during diving operations 4.20 Whole Body Head, trunk (including male gonads), arms above the elbows, or legs above the knee.

4.21 Green Area A low dose clean area, normally <0.2 mRem/hr and <100 dpm/100 cm2 smearable, temporarily set up within the RCA to f7acilitate on going work.

4.22 Readv for Transport When a package/vehicle is properly packaged, labeled, marked and placarded in accordance with all applicable regulations, shipping papers are in possession of the driver or attached to the package, and the carrier has taken possession of the package/vehicle.

Page 12 S-RAP-RPP-0103 Rev 09

I , ' , I - , - I I / - S 1 . .. - - - l ' l - I- , . I 7 - ~ ' - - . . I - I . ~

Date of Examination: 12/06/99 Facility: Nine Mile Point # 2 Operating Test Number: Cat A Test 2 Examination Level (circle one): RO Administrative Topic/Subject Describe method of evaluation:

Description 1. ONE Administrative JPM, OR

2. TWO Administrative Questions I It Question 1. You are the ATC RO during a core reload.

A fuel assembly is for inadvertent A.1I Fuel Handling being lowered into the reactor vessel when the indications criticality are observed.

2.2.26, 2.2.27 What actions are required to be taken? K/A 2.4.4, 2.4.11, core offload in Question 2. The plant is in a refueling outage with a reactor service:

progress. The following equipment is removed from for maintenance

Div III 4160 VAC emergency bus is deenergized for outage work

Condensate/Feedwater system drained and tagged cavity? K/A 2.2.27 What sources are available for makeup to the reactor to the Steam Tunnel and Question 1. What actions are required to obtain access K/A 2.1.2, 2.1.13 responsibilities for maintaining security of the area?

with escorting Question 2. Identify applicable requirements associated individuals. K/A 2.1.2, 2.1.13 Question 1. Two inputs to 2CEC*PNL85 1, from Annunciator 851306, OFF-GAS have been removed service under a markup. What Temporary SYSTEM TROUBLE, K/A 2.2.13 Modifications to steps must be taken to identify this condition?

Systems requirements for the Question 2. What are the authorization and documentation between two systems?

CSO/SSS in order to install a hose (mechanical jumper)

K/A 2.2.11 the calendar year is 3800 mrem. A job Question 1. Your current exposure forWhat actions are required prior to Radiation Exposure requires that you receive 300 mrem.

Limits performing the job? K/A 2.3.4, 2.3.10 High Radiation Area?

Question 2. What actions are required to enter a Very K/A 2.3.1, 2.3.4, 2.3.10 for a fire in the protected area.

JPM: EPIP-EPP-28, Fire Fighting, CSO Actions Emergency K/A 2.4.27, 2.4.29

Nine Mile Point 2 Category "A"- Examination Outine Cross Reference Operating Test Number Cat "A" Test: 2 Examination Level RO Administrative Topic A.1 Subject

Description:

Fuel Handling Question Number: 1 Question: 'EH You are the ATC RO during a core reload. A fuel assembly is being lowered into the reactor vessel when the following indications are received:

Annunciator 603209, SRM SHORT PERIOD, alarms

All SRM count rates are rising

Reactor period is 45 seconds and stable

RMS 11 alarms and indicates a high alarm (red) on DRMS What actions are required to be taken?

Answer: :,

Announce the event and evacuate unnecessary personnel

Notify the SSS, refueling floor SRO, Radiation Protection

Isolate reactor building ventilation and start Standby Gas Treatment

Enter EPIP-EPP-21, Radiation Emergencies

Monitor DRMS and SPDS

Contact Reactor Engineering Department Nose: Injecting SLS is not required by the candidate when answering the question. SLS injection would be determined and directed by the SSS.

Note: If the cause can be quickly rectified without overexposure to personnel, then take action to halt the event. This is a decision of the SRO on the refuel bridge once notified of event and is NOT required by the candidate.

Technical Reference s): 0 .. ."

N2-SOP-39, Rev 01, Section 3.0, Section 4.1, Section 4.4 I,

Nine Mile Point 2 Category "A" - Examination Outline:Cr:ross Reference Operating Test Number Cat "A" Test: 2 Examination Level RO Administrative Topic A.1 Subject

Description:

Fuel Handling Question Number: 1

KA#; 7: : :Importance:h>6 2.4.4, 2.4.11, 4.0, 3.4, 2.2.26, 2.2.27 2.5, 2.6 Comments:

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION UNIT 2 SPECIA L OPERA TING PRO CED URE N2-SOP-39 REVISION 01 REFUEL FLOOR EVENTS lTECHNICAL SPECIFICATION REQUIRED Approved by:

D. P. Bosnic Man arations - Unit 2 Date Effective Date: 08/21/98 PERIODIC REVIEW DUE DATE AUGUST 2000

3.0 IMMEDIATE ACTIONS (CI) 3.1 IF Refueling is in progress, notify Refuel Floor SRO/LSRO of the event.

3.2 IF the cause of an Inadvertent Criticality During Refueling can be quickly rectified without risk of overexposure to personnel, take appropriate actions to halt the criticality.

3.3 IF time AND radiation levels permit, place ALL irradiated components being handled in the Reactor Cavity OR Spent Fuel Pool in a safe position as directed by Refuel Floor SRO/LSRO OR SSS.

3.4 Evacuate unnecessary personnel from the Refuel Floor AND Drywell.

Page 4 N2-SOP-39 Rev 01

4.0 SUBSEQUENT ACTIONS 4.1 General Actions WHEN time permits, make an announcement to notify station personnel of the event . . . . . . . . . . . . . . . . . . .()

Notify the following of the event:

- SSS ............ (_)

- Refuel Floor Coordinator (during Refuel Outages only) OR Supervisor - Reactor Engineering (all other times) ......... ( _ )

- Radiation Protection . . . . . . . . . . . . . . . . .()

IF Core Alterations are in progress, suspend Core Alterations . . . . . . . . . . . . . . . . . . . . . . . . ( )

N/A, Core Alterations NOT in progress.( )

Isolate the Reactor Building AND initiate the Standby Gas Treatment System ................ (. )

IF Area OR Ventilation Radiation Monitors alarm, enter EPIP-EPP-21, Radiation Emergencies, AND execute concurrently with this procedure.( _)

N/A, NO Radiation Monitors alarmed . . . . . . . . . .()

(C2) . IF applicable, activate the Emergency Plan in accordance with EPIP-EPP-18, Activation and Direction of the Emergency Plans . . . . . . . . . . . . . . . . . . . . . .()

N/A, Emergency Plan NOT activated . . . . . . . . . .()

Page 5 N2-SOP-39 Rev 01

4.4 Inadvertent Criticality During Refueling 4.4.1 IF the Reactor is still critical, perform the following:

N/A, Reactor is NOT critical . . . . . . . . . . . . . . .

a. IF there are scramable Control Rods withdrawn, manually scram the Reactor . . . . . . . . . . . . . . . . . .

. . .( )

b. IF SLS System is available AND as directed by SSS, perform the following:

N/A, SLS System NOT available OR SSS directs NOT to initiate SLS System . . . . . . . . . . . . . . .()

1. Manually initiate Standby Liquid Control System . .

. .()

2. Verify Reactor Water Cleanup System has isolated .

.()

3. IF directed by SSS, remove SFC Filter/Demins from service to minimize loss of boron . . .

.... . )

N/A, SSS directs NOT to remove SFC Filter/Demins OR SFC Filter/Demins NOT in service . . . . ( )

4. Notify Chemistry Department to prepare additional batches of sodium pentaborate . . . . . . .

NOTE: Performing the following step will reduce the volume required to be borated.

5. IF directed by SSS, dispatch personnel to install following: the N/A, SFP AND Internals Pit Gates will NOT be installed . . . . . . . . . . . . . . . . . . . . .

)

Spent Fuel Pool Gates. .( )

Internal Storage Pit Gate . . . .. . . . . . . . )

6. IF directed by SSS, shut down SFC flow to Reactor Cavity and Internals Storage Pit per N2-OP-38, F.12.0 AND F.14.0 . . . . . . . . . . . . . . . . . .

. )

N/A, SSS directs NOT to secure flow OR flow is already NOT in service . . . . . . . . . . . . )

c. Continue efforts to shutdown the Reactor . . . . . . .

. . .()

4.4.2 Monitor DRMS AND SPDS for possible Radioactive Release....()

4.4.3 Contact Reactor Engineering Department for investigation

. . .()

4.4.4 WHEN directed by SSS, exit this procedure.

Page 14 N2-SOP-39 Rev 01

Question: '-n--F- .wit 0X XA-plant is in a refueling outage with a reactor core offload in progress. The The following equipment is removed from service:

deenergized for maintenance

Div III 4160 VAC emergency bus is and tagged for outage work

. Condensate/Feedwater system drained to the reactor cavity?

What sources are available for makeup

. LPCS

. LPCI (A,B, or C) lTechnical Reference s): :- i--;

N2-SOP-39, L Section 4.2.5, Section 4.2.6

.JA#,:':--: *,.,,', I flmpo'rtaflC ;:0 42.6 -

2.2.27 I Co m ments:

'X

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION UNIT 2 SPECIAL OPERATING PROCEDURE N2-SOP-39 REVISION 01 REFUEL FLOOR EVENTS TECHNICAL SPECIFICATION REQUIRED UntC 8-))I5&

Approved by: Unit 2 Date D. P. Bosnic Mana Operations -

08/21/98 Effective Date:

PERIODIC REVIEW DUE DATE AUGUST 2000

4.2 Loss of Reactor Cavity or Spent Fuel Pool Inventory (C1) NOTE: The following step is to be performed concurrently with the rest of Subsection 4.2.

4.2.1 IF WHILE performing the following steps the Technical Supportof Center is manned, contact TSC for guidance on prevention. . . . . . .()

excessive radiation exposure . . . . . . . . . . .

N/A, TSC was NOT manned during this procedure.( )

WARNING Significant radiation levels may exist on the Refuel Floor depending on Spent Fuel Pool/Reactor Cavity level.

Extreme care must be used to prevent personnel from receiving high doses of radiation.

Dispatch personnel to identify the cause of lowering level 4.2.2 4.2.3 IF Refuel Seal Low Pressure alarm is in, restore air pressure (_)

to Refuel Seal ..........

N/A, Refuel Seal Low Pressure alarm is NOT in OR Plant is NOT in Refuel Outage . . . . . . . . . . . . . . . . . . .

)

(C2) 4.2.4 IF level is lowering rapidly due to catastrophic events, the entire Reactor Building . . . . . . . . . . . . . .

evacuate N/A, level NOT lowering due to a catastrophic event .

4.2.5 IF Reactor Cavity is flooded, maintain Reactor Cavity/Spent Fuel Pool level using available injection sources in order listed below. Defeat CSH Level 8 interlock per N2-OP-33, Subsection H.11.0 as required:

Condensate/Feedwater

HPCS with Suction from CST

HPCS with Suction from Suppression Pool LPCS or LPCI (A, B, or C) . . . . . . . . . . . . . . . . .()

Page 6 N2-SOP-39 Rev 01

(C2) 4.2.6 IF ECCS Systems are used to maintain water level, make the Injection Valve throttlable in accordance with the applicable Operating Procedure(s) as listed below:

N/A, ECCS Systems NOT used to maintain water level

RHS System N2-OP-31, Subsection H.9.0

CSL System N2-OP-32, Subsection H.1.0

CSH System Can NOT be made throttlable until directed by the EOPs . . . . . . . . . . . . (_)

NOTE: CNS is the preferred source of water to use in step 4.2.7. However, if needed, both CNS and MWS may be used simultaneously.

WARNING Significant radiation levels may exist on the Refuel Floor depending on Spent Fuel Pool/Reactor Cavity level. Extreme care must be used to prevent personnel from receiving high doses of radiation.

(C2) 4.2.7 IF directed by SSS, dispatch personnel to add water to the Reactor Cavity, Spent Fuel Pool, OR Internals Storage Pit from Service Boxes as follows:

N/A, SSS directs NOT to add water . . . . . . . . . . . . . )

a. IF Condensate Storage and Transfer System (CNS) is to be used, perform the following:

N/A, CNS System will NOT be used . . . . . . . . . . .()

1. Verify CNS is available to supply water to Refuel Floor Service Boxes . . . . . . . . . . . . . . . . . . . . .

(_)

2. Verify the following Header Isolation Valves are open:

2CNS-V181, REFUEL FLOOR SUPPLY ISOL (Rx Bldg, elev 306', about azimuth 3300, about four feet off the floor, by the Level Instrument Reference Leg Backfill Rack) . . . . . . . . . . .

2CNS-V182, REFUEL FLOOR SUPPLY ISOL (Rx Bldg, elev 289', about azimuth 560, about twenty feet off the floor, above and about two feet to the right of the door to the north stair tower) * * (_)

Page 7 N2-SOP-39 Rev 01

Nine Mile Point 2 Cateaorv "A - Examination Outline CrossReference Operating Test Number Cat "A" Test: 2 Examination Level RO Administrative Topic A.1 Subject

Description:

Security Question Number: 1 NQuestion:

During an outage, with the plant in Mode 4, you are directed to hang a Markup on feedwater valves in the Steam Tunnel.

What must you do to obtain access to the Steam Tunnel and what are your responsibilities for maintaining security of the area?

NOTE: RWP requirements are NOT required when answering this question.

If asked, if the steam tunnel area has been "de-vitalized", inform the candidate that the area has NOT been de-vitalized. (NIP-SEC-01, 3.6) zAnswer: :; -- :;^ P .; - ^-:i - <^: -X.!--

Permission to access the Steam Tunnel must be obtained from Radiation Protection prior to obtaining the key. The key is obtained from SSS (done by getting the key from the locked key cabinet and completing the sign out log).

Once an individual has the key they must maintain it in their possession and no one else is allowed to use the key.

The key may NOT leave the protected area and must be returned at the end of the shift or completion of the task whichever is sooner.

Technical Refie'rences): :

NIP-SEC-01, Section 3.6 NIP-SEC-02, Sections 3.2.3, 3.2.6, 3.2.7 GAP-OPS-01, Section 3.7.4

Nine Mile~on2<

ate gory A Eamination Ou 5 Reference Crs e e Operating Test Number Cat "A" Test: 2 Examination Level RO Administrative Topic A.1 Subject

Description:

Security Question Number: 1 I K1AP(#: :It-+<50 lrmp ortan-cie>< 1000; 12.1.2, 2.3.10 13.0, 2.9 lo mments:

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION NUCLEAR INTERFACE PROCEDURE NIP-SEC-01 REVISION 09 PROTECTED/VITAL AREA ACCESS TECHNICAL SPECIFICATION REQUIRED Approved by: 6e2(z2~ 9AeA Vice Assessment and Support 10/15/98 Effective Date:

3.5 Review of Protected/Vital Area Access Authorization 3.5.1 At least every 31 days, Badging personnel shall issue to each Site Sponsor an updated list of the personnel they have sponsored for unescorted access to the Protected Area.

3.5.2 Site Sponsors shall review the list (commonly known as the Restricted Level Report), approve it in writing, and return it to the Badging Office. If the designated Site Sponsor is absent, another Site Sponsor, who is cognizant of the sponsored personnel's need for access, may fulfill this responsibility.

a. Site Sponsors shall ensure personnel authorized access to the Protected Area still have a need for access and, if not, initiate termination of access in accordance with Section 3.13.

b. Site Sponsors shall ensure personnel authorized to enter Vital Areas still have a job-related need to access vital equipment and are authorized access only for the duration of the tasks to be performed.

c. Site sponsors may initiate changes to an individual's Vital Area access by marking the changes on the Restricted Level Report as follows:

1) To delete access, line out the "A" in the applicable restricted level column for the individual and circle the change.

2) To add access, write "A" in the applicable restricted level column for the individual and circle the change.

NOTE: Granting of access to the Central and Secondary Alarm Stations and the Unit 2 Remote Shutdown Room shall be done in accordance with Section 3.4.2.

d. Site Sponsors should return the report to the Badging Office within five business days of receipt.

3.6 Devitalization/Revitalization of Vital Areas DurinQ RefuelinQ/Maior Maintenance Periods 3.6.1 During refueling and major maintenance periods, certain vital areas may be "devitalized" i.e., suspended vital area access controls, provided:

a. A determination of the need for devitalization is made ensuring that any devitalization would not result in an increase of the likelihood of radiological sabotage.

b. Operations personnel are involved in the devitalization determination.

Page 9 NIP-SEC-01 Rev 09

3.6.1 (Cont)

c. A devitalization plan, approved by the Manager Nuclear Security and the Manager Operations, is developed to include inspection of the vital area prior to revitalization.

3.6.2 The following areas may not be devitalized for any reason:

a. Reactor Building

b. Control Room

c. CAS - Central Alarm Station

4. SAS - Secondary Alarm Station 3.7 Changing Individual(s) from One Site Sponsor to Another 3.7.1 When it becomes necessary to change individual(s) from one Site Sponsor to another, the new Site Sponsor shall forward documentation as described below to the Badging Office.

a. If no change to Vital Area access is required for the individual(s):

A memo listing the name(s) and social security number(s) of the sponsored individual(s) or a Badge Application with Sections 1 through 4 completed.

b. If changes to Vital Area access are required for the individuals:

A Badge Application (Attachment 1) with the appropriate portions of Sections 1 through 4 completed for each individual.

NOTE: If Section 3 is left blank, the individual(s) will not be given access to any vital areas.

3.7.2 Badging Personnel shall carry out the Site Sponsor transfer as requested and, as applicable, grant access to only those Vital Areas indicated by the Site Sponsor in Section 3 of the Badge Application.

3.8 Changing an Individual's Escort Status 3.8.1 To change an individual's escort status, the Site Sponsor shall complete Section 1, Section 2, line 1, and Section 4, line 1 of the Badge Application (Attachment 1).

Page 10 NIP-SEC-01 Rev 09

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION NUCLEAR INTERFACE PROCEDURE NIP-SEC-02 REVISION 08 GENERAL SECURITY REQUIREMENTS TECHNICAL SPECIFICATION REQUIRED Approved by: 7/22 C. D. Terry : bate Safety Assessment and Support Effective Date: 07/29/98

3.2.3 Personnel issued vital area keys shall retain the keys in their personal possession and shall not remove the keys from the protected area, except as permitted by Nuclear Security Branch procedures. These vital area keys shall be attached to the individual's photo ID badge and shall only be removed by Nuclear Security.

3.2.4 Individuals who have been issued a vital area key on their photo ID badge shall return the key to Nuclear Security whenever:

a. The individual's job function changes such that a vital area key is no longer required to perform job duties.

b. The individual changes departments.

3.2.5 The SSS shall control temporary issuance of vital area keys assigned to the Control Room ensuring:

a. A key sign out log for temporarily issued keys is used.

b. A separate locked cabinet is used to store the key log and unissued keys.

3.2.6 Personnel receiving a temporarily issued vital area key from the SSS shall retain the key in their possession and shall not remove the key from the protected area.

3.2.7 Personnel shall return temporarily issued vital area keys to the SSS upon completion of use or prior to completing their shift, whichever is sooner.

3.3 Deliveries into the Protected Area 3.3.1 Nuclear Security shall ensure packages and materials to be delivered into the protected area from offsite are properly identified, authorized, and searched in accordance with applicable security procedures.

3.3.2 For deliveries to Materials Management arriving during normal working hours, storekeeper authorization is required.

3.3.3 For all other deliveries, authorization shall be provided by a NMPC Nuclear Division Supervisor, who possesses unescorted access authorization and who is knowledgeable in the details of the delivery (ie., contents, arrival time, name of carrier, etc.).

3.3.4 When applicable and before permitting the delivery into the protected area, Nuclear Security shall contact Radiation Protection to ensure that appropriate surveys are performed in accordance with radiation protection requirements.

Page 5 NIP-SEC-02 Rev 08

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION GENERATION ADMINISTRATIVE PROCEDURE GAP-OPS-O1 REVISION 11 ADMINISTRATION OF OPERATIONS lTECHNICAL SPECIFICATION REQUIRED Approved by:

R. G. Smith 'Plant Manager

\ -it we - Unit -1 Date Approved by: Dat22e 2 y8 N. C. Paleologos Pl ant'anager - Unit 2 Date Effective Date: 12/31/1998

3.6.2 (Cont)

b. The SSS shall review the impact to system operation, operability requirements, and reportability, and:

1. Determine the correct configuration of the system or component.

2. Direct action, as necessary, to restore the system or component to proper configuration.

3. If required, initiate a DER in accordance with NIP-ECA-01, Deviation/Event Report.

(C16) 3.7 Key Control NOTE: SSS key control responsibilities are included in GAP-RPP-08, Control of Transient High and Locked High Radiation Areas.

3.7.1 The SSS shall maintain:

a. A list of key controlled items and areas under the authority of the Operations Branch.

b. Control of controlled keys until issue 3.7.2 The SSS or ASSS shall:

a. Grant permission for issue of a controlled key.

b. Maintain issuance of controlled keys.

3.7.3 "On-duty" personnel issued certain controlled keys for the of performance of normal and emergency duties within an area responsibility shall:

a. Maintain control of the keys; AND

b. Prevent unauthorized personnel from possessing or using controlled keys.

Page 21 GAP-OPS-01 Rev 11

3.7.4 Unit 2 Steam Tunnel The key for access to the Unit 2 Steam Tunnel (Vital Area Door R-240-6) shall be controlled by the SSS and issued in accordance with NIP-SEC-02, Security requirements.

NOTE: This key is required to enter and to exit the Steam Tunnel. This key shall remain with the individual to whom it was issued until returned to the SSS. Personnel accessing this area shall obtain Radiation Protection approval for entry prior to key issuance.

3.7.5 Emergencv Access The SSS may use or authorize use of HRA Master keys stored in the "break-to-enter" key box located in the Control Room. The box contains keys to access transient, high, locked high and very high radiation areas. The SSS shall utilize a Radiation Protection technician when using these keys, to ensure compliance with technical specifications.

3.7.6 Vital Area Key Inventory

a. The SSS shall control temporary issuance of vital area keys assigned to the Control Room, ensuring:

A key signout log is used for temporarily issued keys

The key signout log and unissued keys are stored in a separate, locked cabinet.

b. The Shift Security Supervisor, with assistance from the SSS shall conduct a daily inventory of vital area keys stored in the Control Room.

3.7.7 Loss of Control A controlled key not properly issued from its storage location or a properly issued key found unattended shall constitute a loss of key control. The following shall apply if a loss of key control occurs:

a. Vital Area Key The SSS and Nuclear Security shall be notified immediately of any loss of control of a vital area key.

b. Non-Vital Area Key The SSS shall be notified immediately of any loss of control of a non-vital area controlled key. Upon notification, the SSS shall assess the significance of the loss of control and initiate appropriate action to assure positive control of the locked component, device or door is restored or maintained.

Page 22 GAP-OPS-O1 Rev 11

NieMle Paint1'2i t "A" - Examinafton Otl Crnce Reference 0peratin Test Number Cat "A" Test: 2 Examination Level RO Administrative Topic A.1 Subject

Description:

Security Question Number: 2 Queston:

equipment You have been assigned to escort 6 contractors to set up temporary for an upcoming Outage. The job will take 5 days.

the individuals.

Identify any applicable requirements associated with escorting I

1.' a' .. ....

. -.. ;1. I.- - I I. .

--;:I

. 71:%,

I I- ,

I Answer: I Visits To The NIP-SEC-01, Attachment 3, Request To Exceed Limitations On and exceed the Protected Area must be filled out to exceed 3 consecutive days, 5:1 visitor limit.

Technical Re~fer'ence s): it <t.^3~.g0 NIP-SEC-01, Rev 09 Section 3.14.9.b, 3.14.9.c KIA #X:0 - g ilDImportance "7 l 2.1.2 3.0

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION NUCLEAR INTERFACE PROCEDURE NIP-SEC-O1 REVISION 09 PROTECTED/VITAL AREA ACCESS TECHNICAL SPECIFICATION REQUIREDl Approved by: De Vice Nuclet Assessment and Support 10/15/98 Effective Date:

3.14.6 (Cont)

c. Purpose of visit and name of individual to be visited or name of escort

d. Employment affiliation

e. Citizenship 3.14.7 Nuclear Security shall verify that proper approval per Section 3.14.2 has been obtained for the visitor's escorted access to the Protected Area.

3.14.8 Before allowing visitors initial entry to the Protected Area, Nuclear Security shall ensure visitors are issued a visitor badge and are accompanied by an authorized escort.

3.14.9 All personnel serving as visitor escorts shall:

(C3)

a. When serving as the initial escort, meet their visitor(s) at the Entrance Registration Desk in the Security Building, review a set of escort instructions, and indicate that they have done so.

b. Ensure that the visitor(s) they are escorting do not exceed the consecutive day limit on visits to the Protected Area (never more than three, unless, by using Attachment 3, approval to exceed the limit has been obtained from the Manager Nuclear Security).

C. Escort no more than the quantity of visitors determined by the planner to be appropriate (never more than five, unless, by using Attachment 3, approval to escort a greater number has been obtained from the Manager Nuclear Security).

d. While inside the Protected Area, continuously accompany and control visitors under their escort.

e. Contact Nuclear Security at once if a visitor displays suspicious or aberrant behavior.

f. Relinquish escort responsibilities only to another authorized escort who has indicated acceptance of escort duties, as listed on the escort instructions card attached to the visitor's badge.

Page 17 NIP-SEC-01 Rev 09

Nine MilePon2 ategor "A Examinato in Cross R ence Operating Test Number Cat "A" Test: 2 Examination Level RO Administrative Topic A.2 Subject

Description:

Temporary Modifications Question Number: 1 Question:

Two (2) inputs to annunciator, 851306, OFF GAS SYSTEM TROUBLE, on 2CEC*PNL851 are removed from service under a markup. What steps must be taken to identify this condition?

Answer:

Must be identified in the defeated annunciator log.

Transparent yellow sticker, with markup number (or other work document number) and the associated computer points identified on it, shall be attached to the affected annunciator window.

Technical Reference 5:

GAP-DES-03, Section 3.4.3 N2-ARP-01, Attachment, Page 1259

[K/A 9#: I'Importahnc:

2.2.13 13.6 Co mm

... " . 1. I -I,.,..

s; ' ~t--:-.

,en :.tI

-- I.

A x . . . i> .,: E. ... . .. . . . . . . .

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 0 V..

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION GENERATION ADMINISTRATIVE PROCEDURE GAP-DES-03 REVISION 08 CONATROL OF TEMPORARY MODIFICATIONS TECHNICAL SPECIFICATION REQUIRED Plai~t Manage

/// _ p/

Approved By: Date R, G. Smith II- I'm"

-?

Approved By: Date N. C. Paleologos Plantagr-Ui2 11/23/98 Effective Date:

3.3.4 (Cont)

d. Verifying required changes to applicable procedures and/or Control Room critical drawings have been implemented.

3.3.5 The CSO shall record temporary modification clearances in the CSO log and on.the temporary modification forms.

3.3.6 The SSS shall review cleared temporary modification packages to determine the operability status of affected systems or components and record temporary modification clearances in the SSS log and on the temporary modification forms.

3.3.7 The System Engineer shall notify Nuclear Training of clearance for evaluation of simulator impact.

3.3.8 The System Engineer shall ensure all documentation and training requirements of the temporary modification are complete and document in the temporary modification form.

3.3.9 The System Engineer shall return the completed Temporary (C13) Modification Package including copies of any procedure changes made due to the temporary modification, to the temporary modification files maintained by the Manager of Technical Support or designee.

3.4 Defeated Annunciators 3.4.1 When annunciator circuits or components malfunction the annunciator circuits or components may be taken out of service under a markup or holdout per GAP-OPS-02 without processing a temporary modification. In these cases, the SSS shall make an assessment regarding annunciator response procedure annotation or compensatory actions.

3.4.2 If Step 3.4.1 is not applicable to the defeated annunciator, personnel shall determine if a temporary modification is applicable.

3.4.3 Operations Branch personnel shall ensure annunciators defeated per 3.4.1 and 3.4.2 are entered in the Defeated Annunciator Log (Attachment 6) and identified by attaching a sticker to the affected annunciator window, as follows:

a. A transparent yellow sticker shall be used to indicate one or more multiple inputs have been defeated.

Page 7 GAP-DES-03 Rev 08

3.4.3 (Cont)

b. A transparent red sticker shall be used to indicate all inputs have been defeated.

c. When the last active input is defeated, the CSO shall replace the yellow sticker with a red sticker.

d. The document -number authorizing the defeated annunciator (such as temporary modification or markup), and the associated computer point(s) should be identified on the sticker, if practical.

3.5 Temporary Modification Program Review 3.5.1 The Manager Technical Support shall ensure a review of the Temporary Modification Program is performed and documented at least once per year. The review should include:

a. Identification of long-standing temporary modifications.

NOTE: A long-standing temporary modification is defined as a temporary modification implemented for a period of greater than six months.

(C3) b. Verification that temporary modification packages are current and complete for existing temporary modifications.

c. Physical verification of existing accessible temporary modification installations.

d. Forwarding the following to Records Management per NIP-RMG-01.

1. Completed Temporary Modification File Index pages

2. Cleared Temporary Modification Forms 3.5.2 The Manager Technical Support shall issue an annual report that provides dispositions for long-standing temporary modifications and identifies any DERs or other documentation initiated as a result of the review.

4.0 DEFINITIONS 4.1 Defeated Annunciator - An annunciator window having a temporarily altered circuit because of a design deficiency, malfunctioning component, or markup for pre-planned maintenance.

/

Page 8 GAP-DES-03 Rev 08

NIAGARA- MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION UNIT 2 ALARM RESPONSE PROCEDURE N2-ARP-Ol REVISION 00 CONTROL ROOM ALARM RESPONSE PROCEDURES lTECHNICAL SPECIFICATION REQUIRED Approved by:

Date?

R. G. Smith Manager atU ns - Unit 2 Date PERIODTC REVIEW, 05/05/98, NO CHANGE 6/20/96 Effective Da-te:

PERIODIC REVIEW DUE DATE MAY 2Q00

ATTACHMENT 22 (Cont) 2CEC*PNL85I SERIES 300 ALARM RESPONSE PROCEDURES Reflash:-YE- 2CEC*PNL851 851306 r

l -'-4-4 OFF GAS SYSTEM TROUBLE I I

__ =

306 Computer Point Printout Source Setowint OFGAC03 CNSR CND1A OUT H2 CONC ANN. 122117 N/A OFGAC04 CNSR CND1B OUT H2 CONC ANN. 122217 N/A OFGAC05 CNSR COMBINED OUTLET H2 ANN. 122105 N/A OFGBC02 TRAIN A SHUTDOWN ANN. 122124 N/A OFGBC03 TRAIN B SHUTDOWN ANN. 122224 N/A OFGFC07 CONDENSER IA OUTLET FLOW ANN. 122123 N/A OFGFC08 CONDENSER 1B OUTLET FLOW ANN. 122223 N/A OFGLCll CONDENSER CND1A LEVEL ANN. 122121 N/A OFGLC12 CONDENSER CND1B LEVEL ANN. 122221 N/A OFGLCI3 CONDENSER CND1A LEVEL ANN. 122115 N/A OFGLC14 CONDENSER CND1B LEVEL ANN. 122215 N/A OFGLC30 DRYER DRN RCVR TK1 LEVEL ANN. 122201 N/A OFGLC31 DRYER DRN RCVR TK1 LEVEL ANN. 122202 N/A OFGPCO6 OFFGAS SYS INLET PRESS ANN. 122102 N/A I

OFGPCO7 DRYERS DIFF PRESS ANN. 122207 N/A OFGPCO8 HEPA FILTERS DIFF PRESS ANN. 122104 N/A OFGPCO9 VAC PMP 20FG-P1A INL PR ANN. 122118 N/A 43845 Page 1259 N2-ARP-01 Rev 00

ATTACHMENT 22 (Cont) 2CEC*PNL851 SERIES 300 ALARM RESPONSE PROCEDURES 2CEC*PNL851 851306 (Cont)

Computer Point Printout Source Setpoint OFGPC10 VAC PMP 20FG-P1B INL PR ANN. 122218 N/A OFGTC20 RBNR1A INLET TEMP ANN. 122113 N/A OFGTC21 RBNR1B INLET TEMP ANN. 122213 N/A OFGTC22 RBNR1A INLET TEMP ANN. 122119 N/A OFGTC23 RBNR1B INLET TEMP ANN. 122219 N/A OFGTC24 RBNR1A OUTLET TEMP ANN. 122114 N/A OFGTC25 RBNR1B OUTLET TEMP ANN. 122214 N/A OFGTC26 CNSR CND1A OUTLET TEMP ANN. 122116 N/A OFGTC27 CNSR CND1B OUTLET TEMP ANN. 122216 N/A OFGTC28 DRYER DRYlA OUTLET TEMP ANN. 122209 N/A OFGTC29 DRYER DRY1B OUTLET TEMP ANN. 122210 N/A OFGTC30 DRYER DRY1C OUTLET TEMP ANN. 122211 N/A OFGTC34 REFRIGERATOR REF-2A MOT ANN. 122107 N/A OFGTC35 REFRIGERATOR REF-2B MOT ANN. 122109 N/A OFGTC36 REFRIGERATOR REF-2C MOT ANN. 122111 N/A OFGTC37 VAC PMP 20FG-P1A MOT ANN. 122122 N/A OFGTC38 VAC PMP 20FG-P1B MOT ANN. 122222 N/A OFGTC39 OFFGAS INLET TEMP ANN. 122101 N/A OFGZC01 OFFGAS TO STACK AOV103 ANN. 122120 N/A 42504 Page 1260 N2-ARP-v0 Rev 00

ATTACHMENT 22 (Cant) 2CEC'PNL851 $RIES 300 ALARM RESPONSE PROCEDURES 2CEC*PNL851 851306 (Cont)

Automatic Response See appropriate Alarm Response Procedure(s) (ARPs) for 20FG-IPNL122 alarm(s).

Operator Actions

1. Perform actions as specified in the appropriate ARP(s) 20FG-IPNLI22 alarm(s). for

2. IF conditions indicate a loss of Condenser vacuum, enter OF CONDENSER VACUUM. N2-SOP-09, LOSS

3. IF conditions indicate that a hydrogen explosion System, enter N2-SOP-42, OFF GAS SYSTEM HYDROGEN has occurred in the OFG EXPLOSION.

4. IF this annunciator is the result of an Offgas System perturbation involving an increase in Offgas System flow/activity, activity and refer to Tech Spec 4.11.2.7.2.b for samplingTHEN monitor Offgas requirements.

Possible Causes See appropriate ARP(s) for 20FG-IPNL122 alarm(s).

References

See appropriate ARP(s) for 20FG-IPNL122 alarm(s)

LIV~AlnDn '

Ic-bur-u7 S N2-SOP-42 S N2-OP-42 43463 Page 1261 N2-ARP-01 Rev 00

Nine Mile Point 2 Category "A" -E amination Ouline ross Reference Operating Test Number Cat "A" Test: 2 Examination Level RO Administrative Topic A.2 Subject

Description:

Temporary Modifications Question Number: 2 Question: . iX i* C.

Due to equipment malfunctions, a hose needs to be installed to supply additional makeup water to the HVH (Hot Water Heating System) expansion tank from the (MWS) Makeup Water System. The hose will remain in place until system repairs can be completed in about a week. A work order has yet to be generated.

What are the authorization and documentation requirements for the CSO/SSS in order to install the hose?

Answ er:-;---

II>

Note: The candidate should identify hose installation as a temporary modification (GAP-DES-03, 1.1.7)

The authorization and documentation requirements are:

1. SSS and CSO permission is required to implement the temporary modification.

2. SSS review, determine any operability concerns. (For SRO's only)

3. Log in CSO and SSS logs.

4. Initial appropriate blocks of Temporary Mod Form, Attachment 1, Section 2, blocks G and H.

Technical RefererX. (s): I-GAP-DES-03, Applicability 1.1.7, Mechanical Jumper and 3.2 KI A#

LCI <F mpor 'ance ; .:

12.2.11 2.5 C 0 06im ens < ' V Y' < << :

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION GENERATION ADMINISTRATIVE PROCEDURE GAP-DES-03 REVISION 08 rCNTROi OF TFMPORARY MODIFICATIONS TECHNICAL SPECIFICATION REQUIRED 0 Approved By: _ _ _ __,-_ // /

R, G. Smith Plafit Manager - n Date Approved By:

N. C. Paleologos Pianti4"Aager - Unit 2 Date 11/23/98 Effective Date:

\l/

1.0 PURPOSE To establish controls for the review, implementation, and clearance of temporary modifications at Nine Mile Point Nuclear Station.

1.1 ApDlicability This procedure applies to temporary modifications to site installations, facilities, structures, and inservice systems and components therein, as described in the Unit UFSAR. The following types of alterations, if not excluded per Section 1.2, are considered temporary modifications.

1.1.1 Lifted lead - temporarily disconnected electrical conductor that is normally connected, thus modifying the circuit design or configuration.

1.1.2 Electrical jumper - an electrical connection installed between points not ordinarily connected, thus modifying the circuit design or configuration.

1.1.3 A pulled circuit board, electronic module, or power supply that has been removed (or pulled to the point of disconnection) from its designated location disabling the intended function.

1.1.4 An alteration affecting the visual or audible alarm function of an otherwise operable annunciator circuit.

1.1.5 Temporary set point change - a change from the normally prescribed alarm or control set point.

1.1.6 Electric relay block - an electric relay prevented mechanically from changing state.

1.1.7 Mechanical jumper - a temporary connection, such as a spool piece, hose, tubing, or piping, joining two components or systems together or bypassing a component within a system, thus altering the system's design.

1.1.8 Installed or removed blank flanges - blank flanges changed from (C6) the configuration designed for normal system operation.

1.1.9 Disabled relief or safety valves - relief valves blocked to prevent operation at the intended set pressure.

1.1.10 Temporarily installed test instruments affecting the integrity or operation of a system or component.

1.1.11 Removal of test blocks for protective relaying.

1.1.12 Installed or removed filters or strainers - filters or strainers changed from the configuration designed for normal system or component operation.

Page 1 GAP-DES-03 Rev 08

3.0 PROCEDURE 3.1 Temporary Modification Initiation. Preparation. Review and Approval 3.1.1 Temporary modification originators shall request initiation of Temporary Modification Forms (Attachment 1) from appropriate System Engineers.

3.1.2 System Engineers shall coordinate temporary modification (C2) preparation and review activities, including:

a. Initiating and ensuring completion of Temporary Modification Forms in accordance with Temporary Modification Form Instructions (Attachment 2).

(C4) b. Ensuring temporary modifications are reviewed and approved (C12) in accordance with NIP-DES-01, Determination of Design Control Applicability.

c. Ensuring an Applicability Review and if necessary, a 10CFR50.59 Safety Evaluation, is developed and approved in accordance with NIP-SEV-01.

d. Arranging for required personnel training, procedure and drawing changes, as appropriate.

e. For temporary modifications that affect nuclear safety (safety related or Q), ensuring the temporary modification is reviewed by a Qualified Technical Reviewer per GAP-SRE-03.

3.1.3 The Plant Manager or the Manager Technical Support, as previously designated by the Plant Manager, shall approve temporary modifications prior to implementation.

3.2 Tem~orary Modification Implementation 3.2.1 Prior to authorizing implementation of a temporary modification, the SSS shall review the associated Applicability Review/10CFR50.59 Safety Evaluation and Work Order to ensure compliance with Technical Specifications.

3.2.2 Personnel assigned to install temporary modifications shall, per GAP-PSH-01:

a. Obtain SSS and CSO permission to implement temporary modifications.

b. Install temporary modifications in accordance with applicable work/design documents.

c. Print/Initial/Date Section 2 of the Temporary Modification Form.

Page 4 GAP-DES-03 Rev 08

3.2.3 The Installer shall ensure temporary modifications are identifiable by installing Temporary Modification Tag(s)

(Attachment 5), with the following exceptions:

a. Temporary modifications located in/above the refuel cavity/storage area are excluded from the identification requirements of this procedure.

b. Temporary modification tags shall not be used to identify defeated annunciators. (Step 3.4.3 addresses identification requirements for defeated annunciators.)

3.2.4 The independent verifier shall ensure temporary modification is installed in accordance with applicable work/design documents and:

a. Associated Temporary Modification Tags are hung.

b. Sign/date the Section 2 of the Temporary Modification Form.

c. Sign/date the Temporary Modification File Index.

3.2.5 The System Engineer shall ensure temporary modification implementation requirements have been satisfied, including:

(C8) a. Ensuring the temporary modification installation is independently verified, properly tagged and recorded in the Temporary Modification File Index (Attachment 3).

b. Verifying temporary modification functional testing, including the applicable requirements of GAP-SAT-02, is successfully completed, if applicable.

(C13) c. Verifying required changes to applicable procedures and Control Room critical drawings have been implemented and copies of applicable procedures placed in the Temporary Modification file maintained by the Manager of Technical Support or designee.

3.2.6 The SSS shall review temporary modification packages to determine the operability status of affected systems or components and record temporary modification implementations in the SSS log and on the Temporary Modification Forms.

3.2.7 The CSO shall record temporary modification implementations in the CSO log and on the Temporary Modification Forms.

3.2.8 The System Engineer shall notify training of the implementation of the temporary modification for evaluation of simulator impact.

3.2.9 The System Engineer shall ensure all documentation and training requirements of the temporary modification are complete.

Page 5 GAP-DES-03 Rev 08

3.2.10 The Temporary Modification File Index (Attachment 3) shall be maintained in the Control Room.

3.2.11 A file of active temporary modification packages shall be maintained by the Manager Technical Support, or designee.

(C10) 3.2.12 The System Engineer shall ensure any documentation/physical revision to the installed temporary modification is reviewed, and any additional required document changes (ie.procedures) or actions are completed.

3.3 Temporarv Modification Clearance 3.3.1 Authorization for temporary modification clearance shall be obtained from the:

a. Responsible System Engineer - to be documented on the Temporary Modification Form

b. SSS and CSO per GAP-PSH-01.

3.3.2 Personnel shall clear temporary modifications in accordance with applicable work/design documents and remove associated temporary modification tags.

3.3.3 The independent verifier shall ensure temporary modifications are cleared in accordance with applicable work/design documents and:

a. Associated Temporary Modification Tags are removed.

b. Sign/date Section 3 of the Temporary Modification Form.

c. Sign/date the Temporary Modification File Index.

3.3.4 The System Engineer shall ensure applicable temporary modification clearance requirements have been satisfied, including:

(C8) a. Ensuring the temporary modification clearance is independently verified, tags are removed, and clearance verification is documented in the Temporary Modification File Index (Attachment 3).

b. Verifying post-maintenance testing is successful, as applicable.

(C9) c. Notifying Engineering of the cleared temporary modification (C12) and whether the temporary modification was made permanent or removed (i.e., equipment returned to previous condition).

Engineering shall update design to restored configuration in accordance with NIP-DES-01.

Page 6 GAP-DES-03 Rev 08

Nine Mile Point 2 Category "A" - Examination Outline Cross Reference Operating Test Number Cat "A" Test: 2 Examination Level RO Administrative Topic A.3 Subject

Description:

Radiation Exposure Limits Question Number: 1 Question:

Your current exposure for the calendar year is 3800 mrem. A job requires that you receive 300 mrem. What actions are required prior to performing the job?

Answer:

SSS or ASSS must initiate a request to RP for dose limit increases above the administrative limit of 4.0 rem.

Technical Referenes):-

GAP-RPP-07, Rev 05, Section 3.2.4 S-RAP-RPP-0703, Rev 2, Section 3.1 lKIA-#:, .- Importain.ce 2.3.4, 2.3.10 2.5, 2.9 XCo inens X-i K :

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION GENERATION ADMINISTRATIVE PROCEDURE GAP-RPP-07 REVISION 05 INTERNAL AND EXTERNAL DOSIMETRY PROGRAM TECHNICAL SPECIFICATION REQUIRED Approved by:

R. G. Smith z--- r.-', --I, 0 Plant Manager;.7- lnit 1 Date DZae j SE Approved by: PlntAVMn U ,ni w (agr Date N. C. Paleologos Plant Manager - Unit 2" THIS IS A FULL REVISION 12/31/1998 Effective Date:

3.2.3 (Cont)

b. If the dose to the embryo/fetus is found to have exceeded 0.4 Rem, or is within 0.050 Rem of this dose by the time the woman declares pregnancy, the additional dose to the embryo/fetus shall be limited to 0.050 Rem for the remainder of the pregnancy

c. These established administrative limits for the embryo/fetus apply to individuals who have voluntary declared their pregnancy to the Licensee in writing, with an estimated date of conception 3.2.4 Authorization to Exceed Administration Dose Limits (C2) a. The Supervisor of an individual in need of an increase in their administrative dose limits shall:

1. Initiate requests through Radiation Protection for dose limit increases for workers under their supervision

2. Justify the dose limit increases to Rad Protection and Plant Manager

b. Rad Protection shall process the requests as per S-RAP-RPP-0703 3.3 Dosimetry Measurement and Monitoring 3.3.1 Monitoring Requirements

a. Occupationally exposed personnel expected to receive exposures GREATER THAN 10% of the administrative limits in Section 3.2 shall be:

1. individually monitored for exposure while working in the Restricted Area

2. monitored for exposure while working in the Controlled Area via area monitoring 3.3.2 External Dosimetry Measurement

a. Two types of dosimetry devices are used at Nine Mile Point:

1. A passive dosimeter, a Thermoluminescent Dosimeter (TLDs) as the primary dosimetry record device

2. An active dosimeter, a Self Reading Dosimeter (SRDs, eg.

Electronic Dosimeters or Pocket Ion Chambers) as the dose monitoring device Page 5 GAP-RPP-07 Rev 05

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION RADIATION PROTECTION ADMINISTRATIVE PROCEDURE S-RAP-RPP-0703 REVISION 02 AUTHORIZATION TO EXCEED ADMINISTRATIVE DOSE LIMITS Approved by: I-- Date S? 8, V. L. Schuman Manager Padiation f ' ction - Unit 1 Date Approved by: /1;-/17-W D. W. Barcomb Manager Radiation Protectio ,Unit 2 Date THIS IS A FULL REVISION Effective Date: 12/28/98

3.0 PROCEDURE NOTES: 1. This step is executed with the assistance of Radiation Protection when exposure limit increases are requested as per GAP-RPP-07.

2. Equivalent or computer generated forms may be used in lieu of Attachments.

3.1 Individuals Supervisor (Cl) Upon determination that an individual's administrative dose limit needs to be increased, the individual's supervisor shall:

a. Initiate an Authorization to Exceed NMPC Radiation Exposure Limits (Attachment 1), Section 1, and assess:

The work to be performed

The experience level and ability of the individual

IF another individual is qualified to perform the work

b. Review the completed Section 1 with the individual and obtain the individual's concurrence and signature.

c. Forward the form to the Unit Rad Protection Supervision for preliminary review and approval.

3.2 Rad Protection Supervision should, upon receipt of the request form:

a. Review the merits of the request.

b. Temporarily de-authorize the individual for RCA access while the request for administrative dose limit increase is processed.

c. Approve, modify, or deny the request.

d. Sign and forward to the Dosimetry Office.

3.3 Rad Protection/Dosimetry Personnel shall complete Section 2 of the request form.

3.3.1 Ensure that the individual is logged-out of the Access Control System 3.3.2 Record the most recent exposure information on the request form.

a. Enter the requested dose limit (from Section 1).

b. Determine the individuals dose totals for the CURRENT YEAR.

Official record (eg TLD) results plus estimated results for the current year.

Page 2 S-RAP-RPP-0703 Rev 02

Nine Mile Point 2L Category "A" - Examination Outline fCeross Reference Operating Test Number Cat "A" Test: 2 Examination Level RO Administrative Topic A.3 Subject

Description:

Radiation Exposure Limits Question Number: 2 Question:-

The TIP Room is posted with a sign containing the words "GRAVE DANGER".

Radiation levels are posted at 800 Rad/hr. What actions are required to enter the TIP Room?

An-swer: f0 H- Xx ifi-B Approved by RP Supervision and SSS.

Specific RWP is required.

Minimum authorized delta exposure of 300 mrem.

Appropriate monitoring established (candidate is only required to provide one means of monitoring)

Instrument continuously indicating dose

. Device tracking cumulative dose and alarming at a predetermined value

. RP Tech with a dose rate instrument, responsible for positive exposure control.

RP Tech should accompany the worker to the entryway to determine radiological conditions at the time of entry and render assistance if necessary.

T.echnical Refelrence(s): : IMx GAP-RPP-008, Rev 05 Section 3.2, 3.3, 3.4

' ':i':m ortae:. ' ,I.

2.3.1, 2.3.4 2.6, 2.5, 2.3.10 2.9

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION GENERATION ADMINISTRATIVE PROCEDURE GAP-RPP-08 REVISION 05 CONTROL OF HIGH, LOCKED HIGH. AND VERY HIGH RADIATION AREAS lTECHNICAL SPECIFICATION REQUIRED Approved By:

R. G. Smith Plant Manager - Un N Date Approved By: Da/7e N. C. Paleologos Plant ManaC - Unit 2 Date Effective Date: 12/11/98

3.1.7 Areas with the potential for being Very High Radiation Areas include: TIP Rooms, Upper elevations of the drywell during fuel moves, Spent Fuel Pool during diving operations.

3.1.8 Very High Radiation Area Fencing should extend to the overhead to preclude anyone from climbing over the fencing.

3.2 Access Requirements for High Radiation Areas 3.2.1 A Radiation Work Permit (RWP) is required for entry into High Radiation Areas (HRA).

3.2.2 Personnel accessing High Radiation Areas should have a minimum authorized delta exposure of 300 mRem. Exceptions shall be approved by RP Supervision.

3.2.3 Key control for High Radiation Area barriers shall be maintained by Radiation Protection. Issuance and return of keys shall be documented in accordance with Branch Administrative procedures.

3.2.4 Each entry (individual or group) into a High Radiation Area shall be monitored for exposure control. Monitoring methods shall include one or more of the following:

a. Instrument continuously indicating dose rates (individual shall be qualified for instrument use)

b. Device tracking accumulative dose received and alarming at a predetermined value (only allowed after Radiation Protection establishes and communicates area dose rates to personnel entering the area).

c. A RP Technician, with a dose rate instrument, who is responsible for positive exposure control of the activities and periodic radiation surveillance at specified frequencies.

3.3 Access Requirements for Locked High Radiation Areas In addition to the controls of Section 3.2:

3.3.1 Ensure the RWP specifies the maximum allowable stay time for individuals in that area and the dose rate levels in the immediate work area. Continuous direct or remote surveillance of activities within the area may be made by qualified Radiation Protection technicians in lieu of the stay time specification of the RWP.

3.3.2 Key control for Locked High Radiation Area barriers, except Unit 2 Main Steam Tunnel door R-240-6 shall be maintained by RP.

Issuance and return of keys shall be documented in accordance with RP Branch Administrative procedures.

Page 2 GAP-RPP-08 Rev 05

3.3.3 The key for access to the Unit 2 Main Steam Tunnel (Vital Area Door R-240-6) shall be controlled by the SSS and issued in accordance with NIP-SEC-02, Security Requirements. This key shall remain with the individual to whom it was issued until returned to the SSS. Personnel accessing this area shall consult Radiation Protection before entry.

3.4 Access Requirements for Very High Radiation Areas In addition to the controls of Sections 3.2, 3.3:

3.4.1 To the extent possible, entry should be forbidden unless there is a sound operational or safety reason for entering.

3.4.2 Entry into Very High Radiation Areas shall be approved by RP supervision AND the SSS.

3.4.3 A specific RWP is required for entry into Very High Radiation Area.

3.4.4 An RP Technician should accompany the person entering the Very High Radiation Area to the entryway to determine radiation conditions at the time of entry and render assistance if necessary.

3.5 Emergencv Access (C3) 3.5.1 The SSS may use or authorize use of the HRA master keys stored in the "break-to-enter" key box located in the Control Room.

The box contains keys to access high, locked high and very high radiation areas. The SSS shall utilize an RP technician to ensure compliance with Technical Specifications.

3.5.2 When notified by the SSS that HRA master keys from the "break-to-enter" box have been used, the RP branch shall initiate a Deviation Event Report.

3.6 Key Holder Responsibilities 3.6.1 Personnel issued a key for access to a High, Locked High or Very High Radiation Area shall maintain positive access control to the area. Control should include:

a. Ensuring individuals accessing area meet the applicable minimum exposure requirements for that area.

(C2) b. Notifying RP of unsatisfactory access controls.

Unsatisfactory controls may include:

1. Structures (e.g., ladders, scaffold) near the area which may allow alternate unauthorized access to area.

2. Inoperable locked barriers (cannot be maintained locked).

Page 3 GAP-RPP-08 Rev 05

NIAGARA MOHAWK POWER CORPORATION OPERATOR JOB PERFORMANCE MEASURE

Title:

EPIP-EPP-28, Fire Fighting, CSO Actions For A Fire In The Protected Area Revision: 0 Task Number:

Approvals:

'A L /0'.t Id -j-ff General Supervi r Date Operal Su ervisor Date Operations Traijg (Designee) Operations (Designee)

MSA hA StW Configuration Control Nate Performer: (SRO)

Trainer/Evaluator:-

Evaluation Method: _ Perform X Simulate Evaluation Location: _ Plant Simulator Expected Completion Time: 20 minutes Time Critical Task: NO Alternate Path Task: NO Start Time: Stop Time: Completion Time:_

JPM Overall Rating: Pass Fail NOTE: A JPM overall rating of fail shall be given if any critical step is graded as fail. Any grade of unsat or individual competency area unsat requires a comment.

Comments:

Evaluator Signature: Date:

RO Cat A Test 2, A.4 1 October 1999

Recommended Start Location: (Completion time based on the start location)

Plant Control Room or other designated area.

Simulator Set-up:

N/A Directions to the Instructor/Evaluator:

Prior to performance of this JPM, obtain SSS / CSO general permission to open equipment cabinets and inspection covers. If opening the equipment cabinet or inspection cover will affect Tech. Spec. Operability, operational status, or the effects are unknown, obtain specific SSS / CSO permission.

Directions to Operators:

Read Before Every JPM Performance:

For the performance of this JPM, I will function as the SSS, CSO, and Auxiliary Operators. Prior to providing direction to perform this task, I will provide you with the initial conditions and answer any questions. During task performance, I will identify the steps to be simulated, or discuss and provide cues as necessary.

Read Before Each Evaluated JPM Performance:

This evaluated JPM is a measure of your ability to perform this task independently. The Control Room Supervisor has determined that a verifier is not available and that additional / concurrent verification will not be provided; therefore it should not be requested.

Read Before Each Training JPM Performance:

During this Training JPM, applicable methods of verification are expected to be used. Therefore, either another individual or I will act as the additional / concurrent verifier.

Notes to Instructor / Evaluator:

1. Critical steps are identified as Pass/Fail. All steps are sequenced critical unless denoted by a

2. During Evaluated JPM:

Self-verification shall be demonstrated.

3. During Training JPM:

Self-verification shall be demonstrated.

No other verification shall be demonstrated.

References:

I. EPIP-EPP-28, Rev 05

2. N2-OP-76, Section H. 1.0

3. NUREG K/A 2.4.27 (3.0)

K/A 2.4.29 (2.6)

Tools and Equipment:

1. None Task Standard:

Performs the CSO actions of EPIP-EPP-28 including the CSO checklist for a fire in the protected area.

RO Cat A Test 2, A.4 2 October 1999

1- ( (

Initial Conditions:

1. The plant is operating at 100% power when annunciator 852503, UPS IA SYSTEM TROUBLE, is received.

the room.

2. The operator dispatched to UPSIA reports that there is heavy smoke and flames at UPSIA and that he is leaving

3. UPSIA continues to supply its loads.

actions.

4. The Control Room E operator has been directed to carry out the 2CEC-PNL849 Alarm Response Procedure (ARP)

5. Ask the operator for any questions.

Initiating cue:

"(Operator's name), perform the CSO actions for implementing the fire fighting response."

PerformanceSteps : - 1Standard Grade I Comments

1. Provide repeat back of initiating cue. Proper communications used for repeat back Sat/Unsat EvaluatorAcknowledge repeat back (GAP-OPS-01) providingcorrectionif necessary RECORD START TIME

2. Obtain a copy of the reference EPIP-EPP-28 obtained. Sat(Unsat procedure and review/utilize the correct section. Section 2.2 and CSO Checklist referenced.

3. eInitiate the CSO checklist Record name and date. Sat/Unsat (Attachment I)

Indicate Unit 2.

Cue: As SSS, direct the CSO to perform the CSO Checklist for fire fighting.

4a. *Place the GAltronics system in the Actuates the MERGE switch. Sat/Unsat merge mode.

Note: Simulated unless in the simulator.

RO Cat A Test 2, A.4 3 October 1999

(-_

(7 (

I PerformanceSte : Standard t Eli : ; : : : I . Grade : . l Comments I 4b. *Sound the Station Fire Alarm for Presses and holds fire alarm for 10 seconds. Pass/Fail 10 seconds.

Note: Simulated unless in the simulator.

4c. *Announce the Fire. Announces the following: Pass/Fail "Attention. Attention, this is not a drill. A Cue: 15 seconds after the fire alarm is fire had been detected at Unit 2. The Nine sounded or the announcement is Mile Point Fire Brigade shall report to made, acknowledge as Fire 2VBB-UPSIA, Normal Switchgear Building Brigade Leader. elevation 237 feet".

Cue: 1 minute after the fire alarm is Note: Simulated unless in the simulator.

sounded or the announcement is made, as Fire Brigade Leader confirm fire and request local fire departments be called to the site.

1. Call the Unit I CSO and confirm Unit I CSO called and announcement Sat/Unsat the announcement was heard. confirmed.

4d. eRepeat alarm. Presses and holds fire alarm for 10 seconds. Sat/Unsat Note: Simulated unless in the simulator.

RO Cat A Test 2, A.4 4 October 1999

c (:

lPer ormance Ste s i 0:07 S:f

Standard ; ;S

0ti0 Grade 0fS (i:j:4:l i::f 0X In;l

l:Comments 4e. eRepeat announcement. Announces fire. See 5c above for Sat/Unsat announcement.

Note: Simulated unless in the simulator.

4f. Remove the GAltronics from the Places merge switch to normal. Sat/Unsat merge mode.

Note: Simulated unless in the simulator.

4g. *Notify the SSS the fire is SSS notified. Pass/Fail confirmed.

Cue: Acknowledge as SSS.

5. *Turn up the volume on the radio Adjusts volume in the louder direction. Sat/Unsat base consoles.

Note: Simulated unless in the simulator.

6. eContact Oswego 911. Oswego 91 1 contacted and fire assistance Pass/Fail requested to NMP2.

Cue: role-play as 911 operator in response to NMP2 requests.

RO Cat A Test 2, A.4 5 October 1999

( (. (

Performance Steps: :!A ; t Standard i Ii : f: :: : : I :Grade I CIomments

7. *Contact Site Security Supervisor Site Security Supervisor contacted and Pass/Fail and inform him that offsite fire notified of offsite fire assistance.

assistance has been requested.

Cue: role-play as Contact Site Security Supervisor and acknowledge that offsite fire assistance has been requested to the station.

8. *If required, initiate any SOPs or Identify that N2-SOP-7 1, "Emergency Sat/Unsat EOPs. Restoration of 2VBB-UPS IA, I B, I G" may be required if UPS IA is lost.

9. *Check Process Radiation Monitors Recognizes requirement to check Process SatfUnsat to determine if there is any rise in Radiation Monitors on DRMS.

effluent activity.

Cue: The STA will monitor DRMS.

10. *If SSS implements a station Asks the SSS if a station evacuation is Sat/Unsat evacuation, then perform the duties required.

in EPIP-EPP-05.

Determines entry into EPIP-EPP-05 is NOT Cue: Inform the CSO as SSS that a required at this time.

station evacuation is not required.

RO Cat A Test 2, A.4 6 October 1999

I-: ( (.

I PerformanceSteps : ; f:-StI::andard . - :. ;0 1 17 Grade. .ZComments SSS notified. Sat/Unsat

11. *Notify the Unit I SSS the fire is confirmed.

Acknowledges that the fire is out and the Cue: Acknowledge as Unit I SSS. event may be terminated.

Cue: Following the CSO response to the fire, inform the candidate as Fire Brigade Leader that the fire is out and the event may be terminated.

12. When the fire is out and the fire .1 ,

event may be terminated:

\>

N.",

i`,'! : : ,1. P.,

1z, ,., p:i- . ;,

Actuates the MERGE switch. Sat/Unsat 12a. *Place the GAItronics system in the merge mode.

Note: Simulated unless in the simulator.

Presses and holds fire alarm for 10 seconds. Sat/Unsat 12b. *Sound the Station Alarm for 10 seconds.

Note: Simulated unless in the simulator.

Announces the following: Sat/Unsat 12c. *Announce termination of the fire event. "Attention. Attention, this is not a drill. The fire event is terminated."

RO Cat A Test 2, A.4 7 October 1999

( (.

I Comments I PerforanceSte I Standard:::: I.I ,i : d:: I I :: Grade t 12d. *Remove the GAItronics from the Places merge switch to UNIT 1&2 Sat/Unsat merge mode. ISOLATE.

End of JPM Terminating Cue: Performs the CSO actions of EPIP-EPP-28 and the CSO checklist for a fire in the protected area.

RECORD STOP TIME_

RO Cat A Test 2, A.4 8 October 1999

ATTACHMENT 1: CSO FIRE FIGHftIG CHECKLIST Name: Date:

lUnit: 10 2 0 Comolete N/A

1. Upon notification of a fire, or upon receipt of an alarm AND actuation of an automatic Fire Suppression System:

a. Place the GAltronics system in the Merge Mode ..................... 0 0

b. Sound the Station Fire Alarm for 10 seconds, and make the following announcement: ..................................... 0 0 (IF the OSC has NOT been activated)

Attention, Attention, this (is/is not) a drill. A fire has been detected at Unit (1/2). The Nine Mile Point Fire Brigade shall report to:

(state building location, elevation and type of fire, if known).

(If the OSC has been activated)

'Attention, Attention, this (is/is not) a drill. A fire has been detected at Unit (1/2) (state building location elevation and type of fire, if known). The Nine Mile Point Fire Brigade shall report to the OSC."

Repeat alarm and announcement ................................ .0 0

c. Take the GAltronics system out of the Merge Mode, unless OSC has been activated ............................................ .0 0

d. If the Fire Brigade Leader does NOT respond within 60 seconds, repeat steps la - 1c ......................................... 0 0

e. Notify the SSS if the fire is confirmed .............................

0 0

2. Turn up volume on station radio base console, including Oswego County fire frequency .................................................

0 0

3. If requested by Fire Brigade Leader, then call Oswego County 911 Center (911) and request offsite fire assistance .......................... 0 0

4. If offsite assistance is requested, then inform the Security Site Supervisor (X2404) that offsite fire assistance has been requested ...........................

0 0

5. If required, initiate any Special Operating Procedures OR Emergency Operating Procedures ............................................

0 0

6. Check Process Radiation Monitors to determine if there is any rise in effluent activity.

a. If a rise is noted, contact Radiation Protection and inform them of the rise . ... 0 0

b. If no rise is noted, continue to monitor ............................

0 0

7. If SSS implements a station evacuation, then perform duties in EPIP-EPP-05.

0 0 April 1999 Page 7 EPI P-EPP-28 Rev 05

ATTACHMENT I (Cont)

Complete N/A

8. If fire is confirmed, then ensure the unaffected Unit SSS is notified ..... . . . . . .. C

9. When notification received that the fire is out and may be terminated, then perform the following:

a. Place GAltronics system in the Merge Mode . . . . . . . . . . . . . . . . . . . . . . . .. Co

b. Sound the Station Alarm for 10 seconds, and make the following announcement: .................... ..... ...... ..... .... .. ..

'Attention, Attention, this (is/is not) a drill. The fire event is terminated." Repeat alarm and announcement .C...... . . . . . . . . . . . . . . . O

c. Take the GAltronics system out of the Merge Mode .C...... . . . . . . . . . . ..

10. Forward all completed checklists generated for a confirmed fire to the EP Department.. .... ..................................... . . ... O April1 1999 Page 8 EPIP-EPP-28 Rev 05

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION EMERGENCY PLAN IMPLEMENTING PROCEDURE EPIP-EPP-28 REVISION 05 FIRE FIGHTING TECHNICAL SPECIFICATION REQUIRED I-Approved by: AC Be a.

R. G. Smith Plant Manager - UnitAz . ate

.. R__1 Approved by: __0ZK~ at.= I1~

N. C. Paleologos Plant Manager ,- Unit 2 2.-' Date PERIODIC REVIEW, 05/19/1999, NO CHANGE 04/30/1 999 Effective Date:

PERIODIC REVIEW DUE DATE MAY 2000

LIST OF EFFECTIVE PAGES Page No. Change No. Page No. Change No. Page No. Change No.

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10 April 1999 Page i EPIP-EPP-28 Rev 05

TABLE OF CONTENTS SECTION PAGE 1.0 PURPOSE . . . . . . . . . . . . . . . . . . . . . . . . . 1 2.0 RESPONSIBILITIES . . . . . . . . . . . . .. . . . . . . I 3.0 PROCEDURE . . . . . . . . . . . . . . . . . . . . . . . . .. . 1 3.1 Fire Alarms. .. . 1 3.2 Fires within the Protected Area . . . . . . . . . . . .. . 2 3.3 Actions for Fires In Structures Outside the Protected Area 4 4.0 DEFINITIONS . . . . . . . . . . . . . . . . . . . . ... . 5

5.0 REFERENCES

AND COMMITMENTS . . . . . . . . . . . . . . . 5 6.0 RECORD REVIEW DISPOSITION . . . . . . . . . . . . . . . . 6 ATTACHMENT* 1: CSO FIRE FIGHTING CHECKLIST . . . . . . . . . . . . 7 ATTACHMENT 2: SITE SECURITY SUPERVISION FIRE FIGHTING CHECKLIST 9 ATTACHMEN1*3: RADIATION PROTECTION FIRE FIGHTING CHECKLIST . . . . 10 April 1999 Page ii EPIP-EPP-28 Rev 05

1.0 PURPOSE To provide prompt, efficient handling of any fire, regardless of size or presence of radioactivity, by the on-site Nine Mile Point Fire Brigade.

2.0 RESPONSIBILITIES 2.1 Station Shift Supervisor (SSS) has overall responsibility for the initial implementation of the Site Emergency Plan and Implementing Procedures.

2.2 Chief Shift Operator (CSO) notifies fire response personnel, coordinates the response of site personnel and makes notifications to site personnel.

2.3 Supervisor Fire Protection:

2.3.1 Ensures the Fire Brigade Leader maintains fire response control of fire fighting activities on-site.

2.3.2 Coordinates the testing and performing of inventories as required by EPMP-EPP-02, Emergency Equipment Inventories and Checklist.

2.4 Security Site Supervisor implements security related aspects of this procedure.

2.5 Radiation Protection Technician implements the radiation protection aspects of this procedure.

3.0 PROCEDURE 3.1 Fire Alarms Response 3.1.1 Upon annunciation or notification of a fire alarm, the CSO shall determine the location of the alarm source:

a. If the alarm IS associated with an automatic suppression system actuation within the protected area, initiate response in accordance with Section 3.2

b. If the alarm is NOT associated with the actuation of an automatic suppression system within the protected area, OR is outside the Protected Area, validate alarm in accordance with Step 3.1.2 April 1999 Page 1 EPIP-EPP-28 Rev 05

3.1.2 Alarms NOT associated with the actuation of an automatic suppression system within the protected area OR any system outside the protected area shall be handled as follows:

a. CSO shall notify the Fire Brigade Leader of the alarm or fire condition.

b. Fire Brigade Leader shall dispatch at least one fire brigade member to the alarm location to verify a fire condition.

c. If a fire condition which requires fire brigade response exists within the protected area, the responder(s) shall notify the CSO to activate the fire brigade per Section 3.2

d. If no condition exists which requires fire brigade response, responders shall notify the CSO of the condition resulting in fire detection operation and exit this procedure.

e. If a fire condition exists outside the protected areas continue with Step 3.3.

3.2 Fires within the Protected Area NOTE: If the OSC is activated, then all fire brigade response should be coordinated through the OSC. This may be done in person, or via telephone, gaitronics or radio.

3.2.1 SSS Actions

a. When credible evidence exists of a fire condition within the Protected Area, then direct the CSO to implement Attachment 1, "CSO Fire Fighting Checklist".

b. Determine the need to classify the event in accordance with EPIP-EPP-01/02.

c. If the event is classified as an emergency in accordance with Step 3.2.1.b, then activate the emergency plan in accordance with EPIP-EPP-18.

d. Direct a Licensed Nuclear Operator (if available) to the command post to act as a liaison with the Control Room.

e. If deemed appropriate, report to the fire scene to assess the effect of the fire on continued plant operation.

f. WHEN

1. Indication of fire has been received but it has been determined that no fire exists, OR

2. When the Fire Brigade Leader indicates that the fire has been extinguished, then direct the CSO to make an announcement terminating the fire event in accordance with Attachment 1 Step 9 of this procedure.

April 1999 Page 2 EPIP-EPP-28 Rev 05

3.2.2 Site Security Supervisor Actions

a. When notified of a fire, implement Attachment 2, "Security Supervision Fire Fighting Checklist".

3.2.3 Radiation Protection Technician Actions

a. When notified of a fire, implement Attachment 3, "Radiation Protection Fire Fighting Checklist".

3.2.4 Fire Brigade Leader Actions

a. When the Station fire alarm is sounded, then

1. Acknowledge receipt of the alarm to the CSO

2. Report to the fire scene and establish a command post from which fire fighting activities can be safely directed.

3. Provide direction to fire brigade members as appropriate.

4. Inform the CSO of actual conditions at the scene and, if appropriate, confirm the fire condition.

b. If offsite fire department assistance is needed, then

1. Request such from the CSO.

2. Provide direction to responding offsite fire department using the incident command concept.

3. Maintain overall command of the fire scene and coordinate offsite assistance with the appropriate officer in charge using the incident command concept.

c. Request the SSS (via the CSO) conduct station evacuation, if required.

d. If station evacuation is initiated, contact the Personnel Accountability Coordinator (x2662 or use security personnel at the command post) and report the names of all personnel engaged in fire fighting activities.

e. When the fire has been extinguished NOTE: Fire event may be terminated when the fire has been reported as extinguished.

1. Inform the CSO that the fire is out and state that the fire event may be terminated.

2. Establish a fire watch, if necessary.

3. Return fire fighting equipment used to service and conduct post-use inventory in accordance with EPMP-EPP-02.

April 1999 Page 3 EPIP-EPP-28 Rev 05

3.2.5 Fire Brigade Member Actions

a. Report to the appropriate fire equipment storage cabinets, unless otherwise directed.

b. Obtain protective clothing, SCBA, and fire fighting tools.

c. Report to the fire scene, or other location as directed by the Fire Brigade Leader.

d. Follow all directions provided of the Fire Brigade Leader.

3.3 Actions for Fires Outside the Protected Area 3.3.1 If a fire exists, the responding fire brigade member(s) shall extinguish the fire, if possible. If the fire cannot be readily extinguished, the Fire Brigade Leader or on-scene fire fighter should:

a. Request the CSO call for offsite Fire Department assistance, as necessary

b. Request Security to direct off-site Fire Department personnel, vehicles, and other equipment to the fire scene command post upon arrival

c. Request RP assistance if response involves an area where radioactive materials may be stored (such as Warehouse Environmental Area, Source Storage Areas, etc).

d. Upon arrival of offsite Fire Departments, provide appropriate directions using the incident command concept, and direct Fire Brigade member(s) to return to site.

e. If appropriate, incident command may be:

Kept by the Fire Brigade Leader, or

Turned over to Offsite Fire Chief 3.3.2 After the fire is extinguished, the Fire Brigade Leader or on-scene fire fighters shall:

a. Inform the CSO that the fire is out and state that the fire event may be terminated.

b. Establish a fire watch as needed.

c. Return fire fighting equipment used to service as applicable.

April 1999 Page 4 EPIP-EPP-28 Rev 05

3.3.3 The SSS should direct the CSO to make an announcement terminating the fire event in accordance with Attachment 1, Step 9 of this procedure when:

a. Indication of fire has been received, but it has been determined that no fire exists, OR

b. The fire brigade leader indicates that the fire has been extinguished.

4.0 DEFINITIONS 4.1 Confirmed Fire. A condition in which credible evidence exists that a fire is actually occurring. A fire may be considered as confirmed given ANY of the following: fire alarm/annunciator AND suppression system activation accompanied by actual flow or discharge, OR Fire Brigade/Leader report, OR SSS judgement.

4.2 Incident Command System. The system commonly used by emergency response organizations (i.e., police, fire companies, nuclear plant emergency response personnel, etc.) to efficiently and effectively mitigate emergency consequences. Facilitates cooperation of the emergency response effort by establishing a universally accepted system for communication, command 'hierarchy, response organization.

5.0 REFERENCES

AND COMMITMENTS 5.1 Technical Specifications Unit 2 Technical Specifications, Section 6.2.2 5.2 Licensee Documentation 5.2.1 Nine Mile Point Site Emergency Plan 5.2.2 Unit 1 FSAR, Chapters X, XIII 5.2.3 Unit 2 USAR, Chapters 9, 13 5.3 Standards. Regulations, and Codes 5.3.1 10CFR50, Appendix R, Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1, 1979 5.3.2 NUREG-0654-FEMA-REP-1, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, October 1980 5.4 Policies, Programs, and Procedures 5.4.1 EPIP-EPP-01, Classification of Emergency Conditions, Unit 1 5.4.2 EPIP-EPP-02, Classification of Emergency Conditions, Unit 2 April 1999 Page 5 EPIP-EPP-28 Rev 05

5.4.3 EPIP-EPP-18, Activation and Direction of Emergency Plan 5.4.4 EPIP-EPP-05, Station Evacuation 5.4.5 EPIP-EPP-20, Emergency Notifications 5.5 Commitments None 6.0 RECORDS REVIEW AND DISPOSITION 6.1 The following records generated by this procedure shall be maintained by Records Management for the Permanent Plant File in accordance with NIP-RMG-01, Records Management:

NOTE: This only applies if records are generated as the result of an actual declared emergency at the Nine Mile Point Nuclear Station.

Attachment 1, CSO Fire Fighting Checklist

Attachment 2, Security Site Supervisor Fire Fighting Checklist

Attachment 3, Radiation Protection Fire Fighting Checklist 6.2 The following records generated by this procedure are not required for retention in the Permanent Plant File:

NOTE: This only applies when records are not the result of an actual declared emergency.

Attachment 1, CSO Fire Fighting Checklist Attachment 2, Site Security Supervision Fire Fighting Checklist Attachment 3, Radiation Protection Fire Fighting Checklist LAST PAGE April 1999 Page 6 EPIP-EPP-28 Rev 05

ATTACHMENT 1: CSO FIRE FIGHTING CHECKLIST Name: Date: 1

.- I Unit: 1 l 2 l Comnlet. N/A

1. Upon notification of a fire, or upon receipt of an alarm AND actuation of an automatic Fire Suppression System:

a. Place the GAltronics system in the Merge Mode .. . ... .l. . . . . . . . . . . . . . 0

b. Sound the Station Fire Alarm for 10 seconds, and make the El following announcement: ..................................... O (IF the OSC has NOT been activated)

Attention, Attention, this (is/is not) a drill. A fire has been detected at Unit (1/2). The Nine Mile Point Fire Brigade shall report to: -

(state building location, elevation and type of fire, if known).

(If the OSC has been activated)

'Attention, Attention, this (is/is not) a drill. A fire has been detected at Unit (1/2) (state building location elevation and type of fire, if known). The Nine Mile Point Fire Brigade shall report to the OSC.'

Repeat alarm and announcement ................................ . II El

c. Take the GAltronics system out of the Merge Mode, unless OSC has been activated . ........................................... . IJ El

d. If the Fire Brigade Leader does NOT respond within 60 seconds, repeat steps la - 1 c ......... ................................ [ El0

e. Notify the SSS if the fire is confirmed ............................. C El0

2. Turn up volume on station radio base console, including Oswego County fire frequency ................................................. C El0

3. If requested by Fire Brigade Leader, then call Oswego County 911 Center (91 1) and request offsite fire assistance .E El0

4. If offsite assistance is requested, then inform the Security Site Supervisor (X2404) that offsite fire assistance has been requested .E El0

5. If required, initiate any Special Operating Procedures OR Emergency Operating Procedures .

El0

6. Check Process Radiation Monitors to determine if there is any rise in effluent activity.

a. If a rise is noted, contact Radiation Protection and inform them of the rise ... . C IEl

b. If no rise is noted, continue to monitor ............................ C El0

7. If SSS implements a station evacuation, then perform duties in EPIP-EPP-05 .. ... . C El0 Apri 1 1999 Page 7 EPIP-EPP-28 Rev 05

ATTACHMENT 1 (Cont)

Complete N/A

8. If fire is confirmed, then ensure the unaffected Unit SSS is notified .... . . . . . . . . C C

9. When notification received that the fire is out and may be terminated, then perform the following:

a. Place GAltronics system in the Merge Mode .

b. Sound the Station Alarm for 10 seconds, and make the following announcement: .

Attention, Attention, this (is/is not) a drill. The fire event is terminated. Repeat alarm and announcement . 0

c. Take the GAltronics system out of the Merge Mode ..... .............. C C

10. Forward all completed checklists generated for a confirmed fire to the EP Department. .................................................. O April 1999 Page 8 EPIP-EPP-28 Rev 05

ATTACHMENT 2: SITE SECURITY SUPERVISION FIRE FIGHTING CHECKLIST Name: Date: Unit: 10 20 Complete N/A

1. When the Station Fire Alarm is sounded, then dispatch a Security Force member to fire scene command post (or OSC as instructed) to provide crowd control and act as a communications liaison with Security or the STOC (if activated) .......... ................................. 0 O

2. Turn up the volume on the Oswego County fire radio base station .. . .0 0

3. Notify the following:

a. Supervisor Fire Protection.0 0

b. Director Emergency Preparedness.0 0

c. Manager Nuclear Communications and Public Affairs.0 0

4. When notified by the control room that offsite fire assistance has been requested, then dispatch a Security Force member to the Unit 2 entrance traffic light (with fire/ambulance emergency equipment) to direct responding emergency vehicles to the emergency vehicle staging area or the fire scene command post.0 0

5. When offsite Fire Departments arrive, then ensure dosimetry and portable radios are issued to all offsite Fire Department personnel.0 0

6. Inform the Fire Brigade Leader and the CSO upon arrival of the number of fire trucks and the on-site arrival time.0 0

7. If a station evacuation is called for, then implement actions as required by EPIP-EPP-05.0 0

8. When fire event is terminated AND the SSS has authorized departure of offsite fire department personnel, then complete the following:

a. Complete entrance registration log.0 0

b. Forward all completed checklists generated for a confirmed fire to the EP Department.0 0 April 1999 Page 9 EPIP-EPP-28 Rev 05

ATTACHMENT 3: RADIATION PROTECTION FIRE FIGHTING CHECKLIST Name: Iuate: 1Unit: 10 2 0 1 Complete N/A

1. When the Station Fire alarm is sounded, then report to the Fire Brigade Leader at the fire scene command post or OSC (as instructed) ....................... o 0

2. Perform air samples and radiological assessment of the fire scene as needed . o o

3. Contact the Radiation Protection Supervisor to provide additional personnel for radiological support as needed ...................................... El El

4. Provide assistance as requested by the Fire Brigade Leader .................. o El

5. If a station evacuation is implemented:

a. Report names of all Radiation Protection Technicians at the fire scene to the Personnel Accountability Coordinator ......................... oI El

b. Implement actions required by EPIP-EPP-05 ......................... El El

6. When the fire event is terminated, then perform the following:

a. Ensure personnel and equipment used at the fire scene is surveyed as required .................................................. o 0

b. Ensure equipment determined to be contaminated is either retained on-site OR decontaminated prior to its release ............................. El El

c. Retrieve dosimetry issued to offsite Fire Department personnel, and ensure all appropriate paperwork is completed ............................ El El

d. Check local Continuous Air Monitors (CAMs or PINGs) for 'fouling" ........ El El

e. Inform the Fire Brigade Leader and SSS when all duties are completed ....... El El

f. Forward all checklists generated as a result of a confirmed fire to the EP Department ............................................. El El April 1999 Page 10 EPIP-EPP-28 Rev 05

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION UNIT 2 OPERATING PROCEDURE N2-OP-76 REVISION 02 PLANT COMMUNICATIONS X TECHNICAL SPECIFICATION REQUIRED J Approved by:

J. T. Conway gr MSager e-io Operations 2.- 14zI9x 7- t 2 Date THIS IS A FULL REVISION PERIODIC REVIEW, 10/12/98, NO CHANGE PERIODIC REVIEW, 11/01/96 - NO CHANGE Effective Date: 11/30/94 PERIODIC REVIEW DUE DATE OCTOBER 2000

TABLE OF CONTENTS SECTION PAGE A. REFERENCES AND COMMITMENTS .... . . . .. ... . . . . . . . 1 B. SYSTEM DESCRIPTION ..... . .. . .. 1 C. OPERATING REQUIREMENTS .... . . . . . . 6 D. PRECAUTIONS AND LIMITATIONS .... . . . . . 7 E. STARTUP ..... . . . . . . . .. 7 F. NORMAL OPERATION . . . . . ... . . . . 7 1.0 Typical Application of Maintenance and Calibration (M/C)

Communications System .... . . . . . . . . . . . . . . . 7 G. SHUTDOWN ..... ........ ......... ..... . 8 H. OFF-NORMAL PROCEDURE ..... . . . . . . . . . . . . . .. 8 1.0 Site-Wide AND Emergency Announcements . .. ... . 8 2.0 Sound Powered Phone Communication On a Loss of Maintenance Calibration Subsystem Power. 9 3.0 Partial OR Complete Loss of the Page Party/Public Address Communications Subsystem:. 9 4.0 Page System D.C. Supply Power Failure. 9 5.0 Page System Fault or Loss of AC Power . . . . . . . . . . . 10 ATTACHMENT 1: ELECTRICAL LINEUP SHEET ................. 11 ATTACHMENT 2: MAIN PAGE PARTY/PUBLIC ADDRESS SYSTEM CONTROL CONSOLE . . 14 ATTACHMENT 3: BACK-UP PAGE PARTY/PUBLIC ADDRESS SYSTEM CONTROL CONSOLE .15 41699 Page ii N2-OP-76 Rev 02

A. REFERENCES AND COMMITMENTS 1.0 Technical Specifications Section 3.9.5, Communications 2.0 Licensee Documentation USAR Section 9.5.2, Appendix 13B 3.0 Policies. Programs. and Procedures N2-IPM-GAI-SA001, Semi-Annual Speaker Communication Verification Test I..

4.0 Technical Information EE 016 Series EE 74C, Lighting and Communications Plan, Main Stack and Chiller Building EE 080 Series, Communications Plan Drawings

Instructions Manual, Gaitronics E071A 5.0 Commitments Sequence Commitment Number Number Description None B. SYSTEM DESCRIPTION The plant communications system provides reliable means of voice communication between points inside the plant, and between the plant and points outside of it as required for conducting plant operations under all conditions; normal, special, and emergency.

Most plant communication equipment is powered from the uninterruptable power supplies to ensure the continuity of service of the subsystems.

The communications subsystems were designed so that the regular inspection by station procedures can be made quickly and easily.

Among the latter are the tests of the station, fire, and evacuation alarm signals performed once a week from the Main or Backup Page Party/Public Address System Control Console.

.~ - 50800 Page 1 N2-OP-76 Rev 02

B. - SYSTEM DESCRIPTION (Cont) 1.0 Interplant Communications Subsystems 1.1 The Page Party/Public Address Communications Subsystem (COP)

The Page Party/Public Address Communications Subsystem (COP) enables plant personnel to broadcast voice messages plant-wide over the loudspeakers of the system. It enables the supervisory personnel in the control room to broadcast station alarms signaling various abnormal conditions and control the mode of operation of the system. It also allows plant personnel to communicate by means of handsets between various locations in the plant, and support buildings without broadcasting over the loudspeakers.

Provision is made for this system to operate either merged with or isolated from the Page Party/Public Address system of Unit 1, or like systems in facilities that may be added to Unit 2 in the future.

A handset has six channels: one for paging, five for party line conversation, a five-point selector switch for channel selection (party), and a pushbutton for paging. Loudspeakers are intended to be clearly audible over ambient noise. In areas where there is a high level of ambient noise, the handsets of the Page Party/Public Address System and the local telephone systems are provided with acoustical phone booths. Red strobe lights are also located in various high noise level areas of the plant to alert personnel in the event of any of the station alarms being sounded.

The Main Page Party/Public Address System Control Console is the central control station of the subsystem. It is situated in the control room. From this station, supervisory personnel can make a voice announcement to all plant personnel, monitor the status of the subsystem, and initiate the station alarm signals.

There is a Backup Page Party/Public Address System Control Console in the Remote Shutdown Room (CB261), that can perform all of the functions of the Main Page Party/Public Address System Control Console, except resetting a DC Supply failure. Both of these Control Consoles have selector switches for merging with:

Nine Mile Unit 1

Paging Speakers outside the plant

The Admin Building Page 2 N2-OP-76 Rev 02

B. SYSTEM DESCRIPTION (Cont) 1.1 (Cont)

The operation of both the Desk-Top Control Console Figure 1 and the Wall Mounted Control Station Figure 2 is the same. Each control station has the capability of initiating up to five different alarm tones. The alarm tones are designed for a priority sequence with the Evacuation Alarm designated as priority one (Highest Priority), fire alarm as priority two, Station Alarm as priority three, SP-1 alarm (Spare Alarm 1) as priority four, and SP-2 alarm (Spare Alarm 2) as priority five (Lowest Priority). Only one alarm tone may be produced over the Page Line at any time.

This means an alarm tone will override any alarm tone with a lower priority. The activation of any alarm tone will automatically merge all systems' page lines. The ALARM INSTRUCT switch may be pushed if voice page instructions are required during an alarm condition. This switch will mute the alarm as long as the switch is activated and simultaneously places the control station operator on the merged page lines. The Page/Party Selector Switch does not need to be pushed when utilizing the alarm instruction switch. Releasing this switch will reactivate the alarm tone. To extinguish the alarm tone and reset the Tone Generator, push the ALARM OFF switch.

The Red System/Blue System Page Switch gives each control station the capability of selectively paging either the Red or Blue System (up for Blue, down for Red). This switch is locking and the Page/Party selector switch must be pushed to page. With the Red/Blue System Page Switch in the normal (center) position, pages from the Control Station will be heard over both systems' page lines. The five party lines are tied into the plant system and are not switched to selective systems at any time.

The Control Stations are equipped with an outdoor speaker on/off switch, a Unit 1 and 2 Isolate/Merge switch for merging Units 1 and 2, and a NMP2/ADMIN Isolation/Merge switch for merging NMP2 with the Administration Building speakers.

Both the outdoor speakers and the administration speakers will monitor both ther-Rkah andBlu& System Page, Lines if their associated switches are actuated and the Red/Blue System Page Switch is in the normal (center) position. If the Red/Blue System Page Switch is in any position other than NORM, both areas' speakers will monitor only the Red System Page Line.

The Unit 1 and 2 merge switch will automatically merge Units I and 2, turn on the NMP2/Administration Speakers and the outdoor speakers by means of the existing Central Control relay Assembly.

Page 3 N2-OP-76 Rev 02

B. SYSTEM DESCRIPTION (Cont) 1.1 (Cont)

When a Unit 1/2 merge condition no longer exists, these switches must be reset manually by pushing the Unit 1/2 switch to the Isolate position, the NMP2/ADM switch to the MERGE position and the O.D. SPKRS switch to the ON position.

The system failure acknowledge switch, all ALARM switches, the D.C. Supply Reset Switch, and the Alarm Instruct Switch will function if pushed in either direction (Up or Down).

The overall PP/PA system is divided into two areas, the Red System and the Blue System. Two Annunciator Panels monitor the Red and Blue System Page Lines by means of a decoder assembly.

The main purpose of this monitoring system is to check the integrity of the page line for fire protection purposes. It is of extreme importance that the alarm signal is heard in the event of a fire or evacuation.

The Decoder Assemblies monitor a constant 20 KHz signal which is generated onto the Red and Blue System Page Lines control cabinet. With the 20 KHz signal present, the Decoder Assemblies will supply the Annunciator Panels with a contact closure (indicating normal operation). Loss of AC Power or a Fault on the Page Line (short or open) will be detected by the Decoder Assemblies and the Annunciator Panel will lose its contact closure for the faulty station's area. A ground on both sides of the Page Line may or may not cause the alarm to operate, however, a ground will not impair the Alarm Signal, therefore the primary concern is an open or shorted condition. When a fault occurs and the contact closure normally supplied to the Annunciator Panel(s) opens, a flashing light will be activated on the front of the Annunciator Panel indicating the location of the faulty station(s). At this ti e the Red and/or Blue System failure lamps will illuminate a:. both the Main and Back-up Page Party/Public Address Control Consoles. After the system failure has been acknowledged at the Main or Back-up Page Party/Public Address Control Console, and at 2COP-ANN1A and 2COP-ANN1B, the Red and/or Blue System failure lamps on both control stations will remain illuminated and the flashing light(s) on the Annunctatr-tnel(sy wti- change to: a castarnt brilliance. These, lamps will remain illuminated until the fault is located and the system is returned to normal operation thereby giving the affected Annunciator Panel(s) its required contact closure.

Switches and relays enable an operator to separate the RED and BLUE systems at three key points in the system. When a separation is executed, the auxiliary alarm oscillator and 20 kHz oscillator are automatically connected to the separated portion.

Page 4 N2-OP-76 Rev 02

B. SYSTEM DESCRIPTION (Cont) 1.1 (Cont)

Each PP/PA Control Station is equipped with lamps indicating whether the system is operating from the normal D.C. Supply or the alternate D.C. Supply. The Desk-Top Console contains a D.C.

Supply reset switch (this switch is not supplied on the Wall Mounted Control Station). The D.C. Supply switch should be pushed to reset the D.C. Power Supplies, (one main supply and three back-up supplies), after initial power has been applied.

This will insure that the system is operating from the Main D.C.

Supply.

Under normal operation, the D.C. Supply Normal (Green) lamp will be illuminated (indicating the Main D.C. Supply is operational).

If the Main D.C. Supply should develop a fault, the system will automatically switch to the alternate supply in the Main Relay and Control Cabinet, 2COP-RSB81. This switching action will extinguish the Normal lamp and illuminate the Alternate (red) lamp at the Control Stations. If the alternate supply in the Main Relay Cabinet develops a fault, the system will switch automatically to the Main D.C. Supply in the Back-Up Relay and Control Cabinet, 2COP-RSB80. This switching action will illuminate both D.C. Supply lamps at the Control Stations.

Should the Back-Up Relay and Control Cabinet Main D.C. Supply develop a fault. The system will automatically switch to the alternate D.C. Supply in the Back-Up Relay and Control Cabinet.

This switching action will again illuminate only the red lamp.

1.2 The Maintenance and Calibration Communications Subsystem (COJ)

The Maintenance and Calibration Communications Subsystem enables one or more persons at work in one area of the plant, to be in voice contact with one or more persons at work on a related task in another area of the plant. It provides eleven separate and independent communications channels between selected points throughout the plant. Each point, as determined by permanently installed communications jacks throughout the plant, can be lined up to any one of the eleven channels, or turned off, by means of a selector switch for that jack located in the auxiliary relay room.

1.3 Dial TeleDhone Subsystem

Enables a caller at a handset to direct dial a call to any other handset on this system inside the plant.

Enables a caller at a handset to dial a call to a location outside the plant via the NMPC tie lines.

Provides a direct telephone link used solely for power dispatching purposes.

Page 5 N2-OP-76 Rev 02

B. SYSTEM DESCRIPTION (Cont) 1.4 The Hand-Held Portable Radio Communications Subsystem (COR/COS)

This communication system enables the user to maintain voice contact with one or more similar units while moving about the plant as may be required to perform maintenance or emergency situation tasks. The portable hand-held radio system uses transmitters on the Lower VHF Band with Leaky Wire Antenna System, thereby allowing communications by Hand-Held portable radios in most areas of the plant without interfering with sensitive plant instrumentation. This system is meant to be used by particular individuals and not by all employees and contractors.

1.5 The Sound-Powered Communications Subsystem (COJ)

The Sound-Powered Communications Subsystem is provided for voice communication in the event of a total loss of electric power to the PP/PA and M/C subsystems. The SPC subsystem requires no plant electrical power.

2.0 ExtraDlant Communications Subsystem 2.1 Telephone and Radio Links Telephone and radio links provide direct communication with special organizations and agencies such as the local law enforcement authority, local fire department, other power stations, and the commercial telephone systems.

2.2 EmerQency Radio System Emergency Radio System will allow for communication with Niagara Mohawk Radio System and the Oswego County Fire Control. This system will be further discussed in the Emergency Plan. Each of the communications subsystems is of a different type from the others, and each subsystem is installed separately from the others. Thus, damage to or a fault on any one subsystem would not affect the operability of the others.

C. OPERATING REQUIREMENTS The following systems must be in operation in accordance with their applicable operating procedure in order to provide unrestricted operation of plant communication equipment.

N2-OP-71C, 600V A.C. Distribution

N2-OP-73A, Normal DC Distribution Page 6 N2-OP-76 Rev 02

F. NORMAL OPERATION (Cant) 1.2 Select the channel to be used as follows:

1.2.1 Go to 2COJ-RSC88, MAINTENANCE CALIBRATION SELECTOR SWITCH PANEL located in the Auxiliary Relay Room CB288, on the mid portion of the North Wall.

1.2.2 Locate the two (or more) control switches associated with the jacks, (such as switch 35 for jacks JK35A AND JK358), that will be used.

1.2.3 Turn the control switches to the desired channel (1 through 11).

G. SHUTDOWN 1.0 The PP/PA communication system is normally left in operation at all times. IF for some reason it is required to be shutdown, de-energize power supplies as listed on Attachment 1, except for power to Maintenance Calibration System.

2.0 The dial telephone system is normally left in operation at all times.

IF for some reason it is required to be shutdown, notification must be made to the NRC, according to NRC Bulletin 85-79.

3.0 The Maintenance Calibration Communication system is normally left in operation at all times. IF for some reason it is required to be shutdown, THEN take to OFF, 2LAC-PNLN04-4.

H. OFF-NORMAL PROCEDURE NOTE: PP/PA central control consoles in the control room OR remote shutdown room are used for plant-wide broadcast of the evacuation, station, fire alarms. and Refer to EPPs for proper use of PP/PA system during emergency.

1.0 Site-Wide AND Emergency Announcements 1.1 IF a Site-Wide OR Emergency Announcement is required, perform the following:

1.1.1 Actuate the MERGE switch.

1.1.2 Sound the appropriate alarm.

1.1.3 Make announcement on the PAGE system.

1.1.4 Call the Unit 1 CSO and verify announcement was heard on PAGE system.

Page 8 N2-OP-76 Rev 02

Facility: Nine Mile Point # 2 Date of Examination: 12/06/99 Examination Level (circle one): SRO Operating Test Number: Cat A Test 2 Administrative Topic/Subject Describe method of evaluation:

Description 1. ONE Administrative JPM, OR

2. TWO Administrative Questions A. 1 Startup Question 1. Given conditions, classify a Reactivity Management Event. K/A Requirements 2.2.1, 2.2.35 Question 2. A reactor startup is in progress, what administrative controls are in place to prevent mispositioned control rods? K/A 2.1.2, 2.2.1, 2.2.34 Security Question 1. What actions are required to obtain access to the Steam Tunnel and responsibilities for maintaining security of the area? K/A 2.1.2, 2.1.13 Question 2. What actions must be taken in the event of the loss of a vital area key? K/A 2.1.2, 2.3.10l Question: 1. What approvals are required if a surveillance test cannot be A.2 Surveillance performed within the specified frequency? K/A 2.1.12, 2.2.12 Testing Question 2. What are the post maintenance test requirements following maintenance on a containment isolation valve? K/A 2.1.12, 2.1.28, 2.1.33, 2.2.18, 2.2.21, 2.2.24 Question 1. During an ATWS, an auxiliary operator must be dispatched to the A.3 Radiation HCUs to vent CRDM overpiston areas. What actions must be taken to assure Monitoring ALARA requirements are met? K/A 2.3.2 Question 2. A failure of the Digital Control System communication link to the Digital Radiation Monitoring System (DRMS) results in the loss of all control room annunciation associated with DRMS. What are the Technical Specification restrictions on plant operation?

K/A 2.3.11, 2.1.33, 2.1.12 JPM: (New) Emergency Plan classification of each SRO candidates scenario A.4 Emergency (to be administered after each scenario). K/A 2.4.29, 2.4.41 Classification

a tin

-g-- est N um b Operating Test Numbr l Examination Level SRO Administrative Topic A.1 Subject

Description:

Startup Requirements Question Number: 1 oow !M Z- 'm 4001-1011 i .1-During a reactor startup using control rod sequence A2UP, the ATC RO notices that during the performance of RWM step 4, control rod 26-07 (RWM Step 3) is at position 02. The Reactor Operator reports that he failed to move the rod to position 04 when positioning it.

Classify the Reactivity Management Event?

V. MWS Severity Level 2 Event OR Reactivity Event Technical Rerenceis):

GAP-OPS-05, Rev 00 Section 3.13, Section 4.0, Attachment 4 lIA#:000w Ilp

[ 2.2.1, 2.2.35 13.6, 3.2 ertn alj~

l Cow i ti.iN..: = I . I

. IC NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION GENERATION ADMINISTRATIVE PROCEDURE GAP-OPS-05 REVISION 00 REACTIVITY MANAGEMENT TECHNICAL SPECIFICATION REQUIREDll 8

Approved by:

R. G. Smith Date /

D4/,te Approved by: Dite K. A. Dahlberg THIS PROCEDURE SUPERSEDES N1-ODP-OPS-0106 AND. N2-ODP-OPS-0110 Effective Date: 06/15/98

3.12.3 Any work identified in step 3.12.2 having an impact on reactivity management should be forwarded to Reactor Engineering 2 for evaluation. During off-hours, any licensed SRO or STA can fulfill this function for Reactor Engineering.

3.13 ReactivitY Management Incident ReDortinQ and Trending 3.13.1 The following criteria should be used to classify reactivity management events (See Attachment 4 for examples):

a. Severity Level 1 (SLI) Event - Significant Reactivity Event:

An unplanned or uncontrolled plant change that significantly degrades the ability to control or monitor reactivity.

'Significant" is defined as generally meeting one or more of the following criteria:

1. A reactivity related Technical Specification limit was exceeded;

2. An unplanned or uncontrolled reactor power change greater than 2% of rated thermal power (RTP);

3. An unplanned or uncontrolled reactor power change which.

results in failure of the fuel cladding.

4. Dropped or mispositioned fuel bundle in the reactor.

b. Severity Level 2 (SL2) Event - Reactivity Event: An

- unplanned or unco'ntrolled plant change not categorized as "significant" which:

1. Impairs the ability to control or monitor reactivity;

2. Results in an unexpected reactivity change (occurrence and/or magnitude);

3. Adversely affects a set point or alarm significant to reactivity.

c. Severity Level 3 (SL3) Event - Reactivity Precursor: An unexpected plant change or problem that was one barrier away from resulting in a Class 1 or Class 2 Event.

d. Reactivity Management Related Problem (RRP): An unexpected problem which can be related to the ability to control or monitor reactivity, but does not meet the criteria for the Severity Level 1,'2, or 3 Events. Reactivity management related problems, when taken as a group, may indicate problems with equipment, processes, procedures, and/or performance.

3.13.2 A DER shall be generated for the events of severity Level 1, 2 or 3 listed in Attachment 4.

Page 15 GAP-OPS-05 Rev 00

3.13.3 A Reactivity Management Performance Monitoring Program should be established by Reactor Engineering Supervisor to monitor the effectiveness of the Reactivity Management Program.

3.13.4 A corrective action plan should be initiated to address adverse reactivity management performance trends.

3.14 3D Monicore 3.14.1 The Reactor Engifneering Supervisor shall approve changes to the 3D Monicore Data Class constants in accordance with department procedures.

3.14.2 Computer System Engineering personnel shall assist Reactor Engineering in changing the 3D Monicore data bank.

3.14.3 Before Beginning of Cycle (BOC) Startup, the Supervisor Reactor Engineering, in conjunction with Computer System Engineering personnel, should verify key 3D Monicore data classes.

3.15 Control Rod Problem Log 3.15.1 A Control Rod Problem Log should be in place to document control rod operational problems.

3.15.2 The CRD System Engineer should ensure the log is periodically updated.

3.15.3 The Reactor Engineer should review the CRD Problem Log to identify potential control rod movement concerns. These concerns should be communicated to operators prior to reactivity maneuvers.

4.0 DEFINITIONS 4.1 Additional Qualified Individual (C6)

A person that performs verification of control rod selection and positioning when moving control rods. This person may be an SRO, AOC, RO, STA, Reactor Engineer or Reactor Analyst Technician. Those individuals that are not licensed are authorized to perform verification of control rod selection and positioning.

4.2 Banked Position Withdrawal Seauence (BPWS) 4.2.1 The rod sequencing rules followed between WALL-RODS-IN" and the Low Power Set Point (LPSP) to assure compliance with the Control Rod Drop Accident Analysis.

4.2.2 The methodology used to withdraw control rods from the 100 percent control rod density point to low power setpoint that results in incremental control rod reactivity worth so peak fuel enthalpy resulting from a control rod drop is below 280 cal/gm.

Page 16 GAP-OPS-05 Rev 00

4.3 Control Rod Exercising Instructions - Instructions for conducting rod exercising accounting for fuel preconditioning and other requirements.

4.4 Core Reactivity Control (CRC! Book - A binder located in the Control Room, provided to the Operating Shift by the Supervisor Reactor Engineering and maintained in accordance with Reactor Engineering Instructions. The CRC book contains as a minimum:

Identification of CRAM RODS

Control Rod Exercising instructions

Allowable Recirculation Flow window to maintain desired power level.

Shutdown control rod sequence, if applicable

Special Instructions/Precautions as necessary 4.5 CRAM Rods - High worth control rods used for rapid power reductions in an emergency/off-normal situation.

4.6 Deep Control Rod - A control rod inserted to between position 24 and 00.

4.7 Fuel Preconditioning Recommendations - Special recommendations on power increases provided by the fuel vendor or Nuclear Fuels Engineering to minimize fuel damage due to Pellet-Clad-Interaction.

4.8 Mispositioned Control Rod - A control rod moved more than one notch beyond its target position, or a single notch error identified after the verification signoff is performed.

4.9 Reactivity - A measure of the effect on the rate at which neutron population will increase or decrease in nuclear fuel. In particular, the following parameters can significantly change reactivity: control rod position; core loading; fuel-storage configuration; reactor power level; reactor coolant system temperature, pressure, flow, and reactor coolant void fraction.

4.10 Reactivity Controls - Hardware or administrative controls to ensure reactivity changes are performed within the bounds of analysis.

4.11 Reactivity Event - A failure of equipment, procedures, or work practices that causes or could cause a thermal limit to be exceeded, a core instability to occur, an unexpected criticality, or a failure to control global or local core reactivity as intended or in accordance with procedural requirements.

4.12 Reactivity Management - The systematic and philosophical direction given to controlling any and all evolutions that could affect reactivity.

4.13 Reactivity Management Related - Pertaining to the ability to monitor, measure, or control reactor power or fuel criticality status.

Page 17 GAP-OPS-05 Rev 00

4.14 Seauence - One of four groupings of control rods defining which rods are inserted and if inserted, deep or shallow.

4.15 Shallow Control Rod - A control rod inserted to between position 30 and 48.

4.16 Shutdown - All rods inserted to; 02 or beyond (NMP-2) or 04 or beyond (NMP-1). If shutdown margin for the current cycle has been

- demonstrated, this definition could be met if all rods except one are inserted to position 00.. The remaining rod can be at any position.

4.17 Startup/Shutdown Control Rod Movement Instructions - Instructions to achieve the desired Control Rod Pattern from the ALL-RODS-IN condition or to direct control rod insertions to the ALL-RODS-IN position. These instructions:

Implement the Banked Position Withdrawal Sequence (BPWS).

Control deviations from the BPWS above the low power setpoint.

Ensure a monitored approach to criticality.

Document reactivity changes.

4.18 Target Control Rod Pattern - The control rod pattern, developed by calculation, expected at 100 percent power with the desired flow.

4.19 Turbine Valve Testing Instructions - Instructions for required power drops and returning to rated power associated with the test accounting for fuel ramp rate limitations and other requirements.

5.0 REFERENCES

AND COMMITMENTS 5.1 Licensee Documentation 5.1.1 Unit 1 Technical Specification Section 6.2.2.f 5.1.2 Unit 2 Technical Specification Section 6.2.2.f 5.2 Standards, Regulations. and Codes 5.2.1 For NMP-1, ANSI/ANS-3.1-1971, Qualifications of Nuclear Power Plant Personnel 5.2.2 For NMP-2, ANSI/ANS-3.1-1978, Qualifications of Nuclear Power Pl ant Personnel 5.2.3 Power/Flow Ul Operating Map DWG F45683C 5.2.4 Power/Flow U2 Operating Maps EM-950A/B Page 18 GAP-OPS-05 Rev 00

ATTACHMENT 4: EVENT CLASSIFICATION Sevwlty Level 1 Events:

increase in frequency or severity of SL2 events

core thermal hydraulic instability

unplanned criticality during refueling plant transient outside design basis operation of core outside of design or licensing basis control rod drop accident misloaded fuel bundle in the reactor core

violation of TS Thermal Limit Action Statement

anticipated transient without scram (ATWS)

fuel damage resulting from uncontrolled, unplanned, or improperly performed reactivity change Severity Level 2 Events:

increase in frequency or severity of SL3 events

TS Thermal Limit Violation (MFLPD, MFLCPR, MAPRAT > 1.000)

improper heat balance caused by undetected instrument or sensor failure resulting in violation of the licensed thermal power limit

error in control rod movement instructions or fuel movement instructions that results in an improper reactivity change

procedure violation resulting in improper bypass of a control rod

error in data or calculation used to monitor cOre reactivity (i.e., reactivity anomaly)

calculation error in reactivity related surveillance test (i.e., scram time testing, shutdown margin, reactivity anomaly, etc.) and not detected until after approval

miscalibrated nuclear instruments

improperly performed or inadequate maintenance resulting in reactivity change (i.e., causing a Loss of Feedwater Heating during maintenance on feedwater heaters)

mispositioned control rod resulting from personnel error

violation of Fuel Preconditioning Recommendations.

Severity Level 3 Events:

error in control rod movement instructions or fuel movement instructions but discovered by bperator/RE before implementation

mispositioned control rod resulting from equipment problem (i.e., triple-notch event)

misloaded fuel bundle in the spent fuel pool

calculation error in reactivity related surveillance test (i.e., scram time testing, shutdown margin, reactivity anomaly, etc.) detected at the approval step Reactivity Management Related Problem:

miscellaneous control rod equipment problem (i.e., double-notching, difficult to move off 00, etc.)

abnormally fast or slow control rod stroke speeds core monitoring code work arounds (i.e., monitoring cases failing because on inadequate disk space, start/restart cases fail unless selected points are substituted, etc.)

RCS Flow Control Valve problems at Unit 2

excessive LPRM Failure.

Page 25 GAP-OPS-05 Rev 00

NieMile Point 2-Category "A" xamination utline Cro6ss ReferenceX Operating Test Number Cat "A" Test: 2 Examination Level SRO Administrative Topic A.1 Subject

Description:

Startup Requirements Question Number: 2 Question: i -X A reactor startup is in progress using control rod sequence A2UP. You have completed moving control rods in RWM Step 4. Prior to and while moving control rods in RWM Step 5, what actions are taken by the Reactor Operator to ensure control rods are moved to the correct position?

Answe:. If.-;.<..-.H - -:-;..A m R- - . .t.; 0 Prior to commencing a new page (i.e., RWM Step 5):

Update the final rod position (posted by the 4-rod display) with the final position of the control rods in RWM Step 5.

Reactor Operator and verifier initial above the appropriate "TO" position for RWM Step 5 on the Control Rod Sequence Sheet.

Conduct rod movements using the Control Rod Sequence Sheets.

RO verbalizes intended actions including selected rod, initial position, and final position. Intended actions (selection and positioning) are verified and verbally acknowledged by an additional qualified individual (verifier).

Technical Refere~nc(s):

GAP-OPS-05, Rev 00 Section 3.4 Comments:

.1.

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION GENERATION ADMINISTRATIVE PROCEDURE

.- GAP-OPS-05

- : REVISION 00 REACTIVITY MANAGEMENT TECHNICAL SPECIFICATION REQUIRED Approved by: Ad-~n XG. t & Hi R. G. Smith Plant Manager i% - t Date Approved by:

K. A. Dahlberg Plant Manager - Un t 2 Da e THIS PROCEDURE SUPERSEDES N1-ODP-OPS-0106 AND N2-ODP-OPS-0110 06/15/98 Effective Date:

3.3.2 (Cant) r-

'a_ e. Changes to a Reactivity Maneuver Request Form after it has been approved by the SSS may only be performed with concurrence by the SSS and Reactor Engineer or STA. Changes shall be initialed and dated by the SSS and Reactor Engineer or STA.

3.3.3 Fuel Movement Instructions (FMIs)

a. Once in the Spent Fuel Pool, all fuel movement shall be performed using approved Fuel Movement Instructions.

b. Fuel Movement Instructions and associated procedural requirements shall ensure that fuel is only placed in pool or core locations in a configuration analyzed to meet shutdown margin (SDM) requirements for fuel movement and storage.

c. Fuel Movement Instructions shall be prepared by reactor engineering using approved procedures. The approved procedures should implement independent verification by another member of reactor engineering. The Reactor Engineering Supervisor should approve the Coversheet.

d. Changes to Fuel Movement Instructions after they have been approved may only be performed with concurrence by the SSS and reactor engineer. Changes shall be initialed and dated by the SSS and reactor engineer.

3.3.4 General Reactor Operator Instructions (CRC-Book)

Instructions for Operators to maintain desired steady state power level. These instructions include an allowable Core Flow range to maintain reactor power and are contained in the CRC book.

3.4 Reactivity Controls During Control Rod Movement 3.4.1 Operators shall conduct control rod movements in accordance with Reactivity Maneuver Requests (Attachment 1), Startup/Shutdown Control Rod Movement Instructions or other approved procedures.

NQTE: Although the Additional Qualified Individual may not be licensed or qualified to manipulate the controls of the facility, the Additional Qualified Individual is authorized to perform verification of rod selection and positioning.

3.4.2 All control rod selection and positioning should require an (C6) additional qualified individual (SRO, AOC, RO, STA, Reactor Engineer, or Reactor Analyst Technician) to perform verification, except when deemed appropriate by the SSS (For

- example: emergency power reductions).

Page 9 GAP-OPS-05 Rev 00

3.4.3 While manipulating control rods, except during emergency power reductions or EOP's, operators should verbalize actions including rod selected, their intended initial position and final position. This should be verified and verbally acknowledged the additional qualified individual by prior to rod movement.

3.4.4 At Unit 2, the following requirements should be utilized for

_~ 7 .control rod movement, except during emergency

.-.EOPs, or Weekly.Control Rod Movement power reductions,-..

Verification Surveillance. and Position Indicator

a. Prior to commencing a new page on the Startup or Shutdown Rod Sequence Sheets or a Reactivity Maneuver the Reactor Operator should ensure Request Form, that a sign indicating the final rod position for the rods on that posted beside the 4-Rod display. page has been

b. Once the sign is posted, the Reactor additional qualified individual shouldOperator initial and the appropriate 'TO" position on the sequence above the Reactivity Maneuver Request Form. sheet or NOTE: Rod changes require intense focus and concentration and require-frequent breaks. The following maximum time period for movements, but is the responsible individuals should take breaks the needed. whenever

c. Relief should be provided to both the RO and additional qualified individual at intervals not to approximately 60 minutes for a period of exceed minutes. Due to the routine nature of at least 30 weekly rod exercising, the RO and additional qualified should take a short break after every individual page.

3.4.5 At Unit 2, use of continuous withdraw of control rods is limited to those rods that are intended to be withdrawn position 48, unless otherwise directed directly to by procedure.

3.5 Reactivitv Controls During Recirculation Flow Changes 3.5.1 Operators should conduct recirculation flow accordance with a Reactivity Maneuver Requestchanges in

1) or other Approved procedures. A Reactivity Form (Attachment Form is not needed for recirculation flow Maneuver Request maintain power "Power.Maintenance". changes required to 3.5.2 During recirculation flow changes, Operators their Actions and receive confirmation from should verbalize Qualified Individual. the Additional 3.5.4 During recirculation flow changes monitor redundant nuclear instrumentation and recirculation flow indication.

Page 10 GAP-OPS-05 Rev 00

Nine Mille Pon2 Cat rtonOline Cross eference, Operating Test Number Cat "A" Test: 2 Examination Level SRO Administrative Topic A. 1 Subject

Description:

Security Question Number: 1 Question:-

During an outage, with the plant in Mode 4, you are directed to hang a Markup on feedwater valves in the Steam Tunnel.

What must you do to obtain access to the Steam Tunnel and what are your responsibilities for maintaining security of the area?

NOTE: RWP and Confined Space requirements are NOT required when answering this question.

If asked if the team tunnel area has been "de-vitalized", inform the candidate that the area has NOT been de-vitalized.

An sWr: - I 0' I Permission to access the Steam Tunnel must be obtained from Radiation Protection prior to obtaining the key. The key is obtained from SSS (done by getting the key from the locked key cabinet and completing the sign out log).

Once an individual has the key they must maintain it in their possession and no one else is allowed to use the key.

The key may NOT leave the protected area and must be returned at the end of the shift or completion of the task whichever is sooner.

Techical Reference 5: -I NIP-SEC-02, Sections 3.2.3, 3.2.6, 3.2.7 GAP-OPS-01, Section 3.7.4

Nine Mile Point 2..

Category "A" - Examination Outline Cross Reference Operating Test Number Cat "A" Test: 2 Examination Level SRO Administrative Topic A.1 Subject

Description:

Security Question Number: 1 A#:f I3Impo rtanc4::I 2.1.2, 2.3.10 4.0, 3.3 Comments:

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION NUCLEAR INTERFACE PROCEDURE NIP-SEC-02 REVISION 08 GENERAL SECURITY REQUIREMENTS TECHNICAL SPECIFICATION REQUIRED Approved by: -7122 C. D. Terry ate Safety Assessment and Support Effective Date: 07/29/98

3.2.3 Personnel issued vital area keys shall retain the keys in their personal possession and shall not remove the keys from the protected area, except as permitted by Nuclear Security Branch procedures. These vital area keys shall be attached to the individual's photo ID badge and shall only be removed by Nuclear Security.

3.2.4 Individuals who have been issued a vital area key on their photo ID badge shall return the key to Nuclear Security whenever:

a. The individual's job function changes such that a vital area key is no longer required to perform job duties.

b. The individual changes departments.

3.2.5 The SSS shall control temporary issuance of vital area keys assigned to the Control Room ensuring:

a. A key sign out log for temporarily issued keys is used.

b. A separate locked cabinet is used to store the key log and unissued keys.

3.2.6 Personnel receiving a temporarily issued vital area key from the SSS shall retain the key in their possession and shall not remove the key from the protected area.

3.2.7 Personnel shall return temporarily issued vital area keys to the SSS upon completion of use or prior to completing their shift, whichever is sooner.

3.3 Deliveries into the Protected Area 3.3.1 Nuclear Security shall ensure packages and materials to be delivered into the protected area from offsite are properly identified, authorized, and searched in accordance with applicable security procedures.

3.3.2 For deliveries to Materials Management arriving during normal working hours, storekeeper authorization is required.

3.3.3 For all other deliveries, authorization shall be provided by a NMPC Nuclear Division Supervisor, who possesses unescorted access authorization and who is knowledgeable in the details of the delivery (ie., contents, arrival time, name of carrier, etc.).

3.3.4 When applicable and before permitting the delivery into the protected area, Nuclear Security shall contact Radiation Protection to ensure that appropriate surveys are performed in accordance with radiation protection requirements.

Page 5 NIP-SEC-02 Rev 08

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION GENERATION ADMINISTRATIVE PROCEDURE GAP-OPS-O1 REVISION 11 ADMINISTRATION OF OPERATIONS TECHNICAL SPECIFICATION REQUIRED Approved by: - ,, ,, V rt

- - Date/ ,

R. G. Smith ,,Plant Manager - Unit -1 Date Approved by: UP4.-f N. C. Paleologos Plant anager - Unit 2 Date 12/31/1998 Effective Date:

3.7.4 Unit 2 Steam Tunnel The key for access to the Unit 2 Steam R-240-6) shall be controlled by the SSS Tunnel (Vital Area Door accordance with NIP-SEC-02, Security and issued in requirements.

NOTE: This key is required to enter and Tunnel. This key shall remain withto the exit the Steam whom it was issued until returned to individual to the SSS. Personnel accessing this area shall obtain Radiation approval for entry prior to key issuance. Protection 3.7.5 Eneraency Access The SSS may use or authorize use of HRA the "break-to-enter" key box located Master keys stored in in the Control Room. The box contains keys to access transient, very high radiation areas. The SSS shall high, locked high and Protection technician when using these utilize a Radiation compliance with technical specifications. keys, to ensure 3.7.6 Vital Area Key Inventory

a. The SSS shall control temporary issuance assigned to the Control Room, ensuring: of vital area keys A key signout log is used for temporarily The key signout log and unissued keys issued keys separate, locked cabinet. are stored in a

b. The Shift Security Supervisor, with assistance from the SSS shall conduct a daily inventory of vital the Control Room. area keys stored in 3.7.7 Loss of Control A controlled key not properly issued or a properly issued key found unattendedfrom its storage location loss of key control. The following shall constitute a shall apply if a loss of key control occurs:

a. Vital Area Key The SSS and Nuclear Security shall be of any loss of control of a vital area notified immediately key.

b. Non-Vital Area Key The SSS shall be notified immediately of a non-vital area controlled key. of any loss of control SSS shall assess the significance of Upon notification, the initiate appropriate action to assure the loss of control and the locked component, device or door positive control of is restored or maintained.

Page 22 GAP-OPS-O1 Rev 11

Nine_ Mil Point Ca egory "A"-xamination Outline Cross Refee nce Operating Test Number Cat "A" Test: 2 Examination Level SRO Administrative Topic A.1 Subject

Description:

Security Question Number: 2

[Question:

During an outage, with the plant in Mode 4, you have issued the key to the steam tunnel. The individual who signed it out reports that they have lost the key. What actions must be taken?

Answer: e<

Ensure the S.S.S, Security and Radiation protection have been notified.

Immediately establish positive access control by posting an individual at the area.

Initiate a Security Work Request (SWR) to replace the lock within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

Maintain an individual at the area until it can be locked or roped off, posted and a flashing yellow light installed.

lTechnical Reference(s):

S-RAP-RPP-0801, Section 3.5 GAP-OPS-01, Section 3.7.7

< I Irmportaniridl 12.1.2, 2.3.10 14.0, 3.3l Comments:: .: . ` :

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION RADIATION PROTECTION ADMINISTRATIVE PROCEDURE S-RAP-RPP-080 1 REVISION 08 HIGH RADIATION AREA MONITORING AND CONTROL Approved by:

P. 0. Smalley Manager Radiation P Date Approved by:

D. W. Barcomb Manager Ra on Pr'btection - Unit 2 Date Effective Date: 04/05/97

3.4.2 (Cont)

If NO enclosure exists that can be locked and NO enclosure can be reasonably constructed around the individual areas (e.g., Drywell, Torus area, suppression pool) then:

a. Obtain consent and approval of the Supervisor Radiation Protection or designee to perform the following steps:

1. Rope off the area; AND

2. Conspicuously post the area; AND

3. Activate a flashing light as a warning device; OR

4. Provide continuous surveillance ensuring positive access control over the area.

b. If flashing lights are used, a verification frequency of at least once per day or as directed by RP supervision should be established to ensure the operability of the flashing lights.

3.5 Broken Locks and Lost Keys RP Chief Technicians shall implement controls for each area that has an inoperable door/gate (cannot be maintained locked) or unaccounted for key as follows:

3.5.1 Locked High Radiation Area

a. Immediately establish positive access control at entrance(s).

b. Notify RP supervision AND Station Shift Supervisor (SSS).

Additionally, notify Security for Main Steam Tunnels.

c. Process a Security Work Request (SWR) and request immediate (within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ) response to replace the core or repair the door/gate as appropriate.

d. If the replacement or additional XH/XR lock CANNOT be installed in a timely manner, then:

1. In accordance with 10CFR20.1601(b), an individual shall be posted at the area to prevent unauthorized entry.

This shall be maintained until one of the following controls can be established.

2. Install if possible a XH/XR cored padlock and chain to secure the door/gate.

Page 3 S-RAP-RPP-0801 Rev 08

3.5.1.d (Cont)

3. The area shall be roped off, conspicuously posted and a flashing yellow light activated as a warning device a time period not to exceed the next regularly scheduled for working day.

3.5.2 High Radiation Area

a. Immediately establish positive access control at entrance(s).

b. Ensure the requirements of Section 3.3 are met.

3.6 High Radiation Area Access. Monitoring. and Survey Requirements 3.6.1 For entry into a High Radiation Area, station personnel sign in and work under a Radiation Work Permit (RWP). shall 3.6.2 For High Radiation Areas which are locked, station personnel should obtain an H-key or XH/XR key from the RP Chief Technician/assigned Backshift Technician (or Control Room for Main Steam Tunnels) by signing out the key on the appropriate Key Sign Out Log.

a. Except for keys issued for Operations Department Rounds, keys shall be issued by the RP Chief Technician/assigned Backshift Technician.

b. Keys issued to support Laundry or Trash walkdowns ups shall only be issued to the assigned RP TechnicMi. or pick 3.6.3 RP Chief Technicians/assigned Backshift Technicians personnel entering a High Radiation area are monitored shall ensure provided with, or accompanied by, one of the following: by being

a. A radiation monitoring device which continuously the radiation dose rate in the work area. indicates NOTE: Personnel are required to monitor area radiation levels when entering a High Radiation Area to satisfy 10CFR20.2103, Records. The instrument used for the survey also satisfies Technical Specification 6 .12.1.a requirements.

b. A Radiation Monitoring device (e.g., Digidose) which continuously integrates radiation dose and alarms preset integrated dose. at a Use of this method is authorized only after:

1. Area dose rates have been established.

Page 4 S-RAP-RPP-0801 Rev 08

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION GENERATION ADMINISTRATIVE PROCEDURE GAP-OPS-O1 REVISION 11 ADMINISTRATION OF OPERATIONS TECHNICAL SPECIFICATION REQUIRED Approved by: ,-<6 /,

R. G. Smith ~~P1nt anaer Unt -1 Date Approved by:

N. C. Paleologos PlantManager - Unit 2 )Xe IL2/ZZ Ie Date 12/31/1998 Effective Date:

3.7.4 Unit 2 Steam Tunnel The key for access to the Unit 2 Steam Tunnel (Vital R-240-6) shall be controlled by the SSS and issued inArea Door accordance with NIP-SEC-02, Security requirements.

NOTE: This key is required to enter and to exit the Steam Tunnel. This key shall remain with the individual to whom it was issued until returned to the SSS. Personnel accessing this area shall obtain Radiation Protection approval for entry prior to key issuance.

3.7.5 Emerqencv Access The SSS may use or authorize use of HRA Master keys the "break-to-enter" key box located in the Control stored in box contains keys to access transient, high, locked Room. The high and very high radiation areas. The SSS shall utilize a Protection technician when using these keys, to ensureRadiation compliance with technical specifications.

3.7.6 Vital Area Key Inventory

a. The SSS shall control temporary issuance of vital area keys assigned to the Control Room, ensuring:

A key signout log is used for temporarily issued keys The key signout log and unissued keys are stored in a

separate, locked cabinet.

b. The Shift Security Supervisor, with assistance from the shall conduct a daily inventory of vital area keys storedSSS the Control Room. in 3.7.7 Loss of Control A controlled key not properly issued from its storage or a properly issued key found unattended shall constitutelocation loss of key control. The following shall apply if a a loss of key control occurs:

a. Vital Area Key The SSS and Nuclear Security shall be notified immediately of any loss of control of a vital area key.

b. Non-Vital Area Key The SSS shall be notified immediately of any loss of of a non-vital area controlled key. Upon notification, control SSS shall assess the significance of the loss of control the initiate appropriate action to assure positive control and the locked component, device or door is restored or of maintained.

Page 22 GAP-OPS-O1 Rev 11

Question: X: ..

On 12/14/99 at 0000 hours0 days 0 hours 0 weeks 0 months , it is discovered that N2-OSP-RHS-Q@004, RHR SYSTEM LOOP A PUMP & VALVE OPERABILITY TEST AND ASME Xl PRESSURE TEST, was last performed on 9/1/99 at 0000 hours0 days 0 hours 0 weeks 0 months .

What approvals are required if the test cannot be performed within the next 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months ?

Answer: :

The test cannot be completed before exceeding 1.15 times the surveillance interval, therefore Branch Manager approval is required.

The following is not required by the candidate to answer the question:

1. On 12/2/99 at 0000, 92 days expired.

2. On 12/15/99 at 1912, 105.8 days expires (GAP-SAT-01, 15%

extension)

3. On 12/25/99 at 0000, 1.15 days expires (25% extension)

Technical Reference s):: -- ?*:0 GAP-SAT-01, Rev 06 Section 3.2, Steps 3.2.3 lKIA #- iIlmportance l 2.1.12, 2.2.12 4.0, 3.4 1Atm E

f ;L ...: :E-.^ace./i<^,

... :r. ::i:

a, '., SE-:::......

' 1I . V ,

. .-, I I':A:::

I

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION GENERATION ADMINISTRATIVE PROCEDURE

- GAP-SAT-O1 REVISION 06 SURVEILLANCE TEST PROGRAM TECHNICAL SPECIFICATION REQUIREDl Approved by:

R. G. Smith PlantAn flate ~

'S1 Approved by:

N. C. Paleologos PiL~- 4 - ZY- 7?

Plant Manager - Unit 2 Date Effective Date: 06/24/1999

1.0 PURPOSE To provide administrative controls for surveillance inspections required by Technical Specifications tests and and other license requirements.

1.1 AnDlicabilitv This procedure applies to personnel responsible for performing surveillance tests at Nine Mile Point Nuclear Station.

2.0 PRIMARY RESPONSIBILITIES 2.1 Responsible Branch Managers have overall responsibility surveillance and periodic tests comply with Technical to ensure and other license requirements. Specifications 2.2 The Station Shift Supervisor (SSS) is responsible performance of surveillance tests and to determine to authorize the the operability status of associated systems, structures, and components.

2.3 Supervisors are responsible to ensure assigned surveillance performed as scheduled or are rescheduled or delayed tests are as allowed.

3.0 PROCEDURE 3.1 Surveillance Test Program (C3) 3.1.1 A lead group shall be assigned responsibility for each surveillance test required by Technical Specifications other license requirements. The lead group shall: and

a. Ensure procedures are prepared and approved for assigned activity each

b. Ensure surveillance test requirements comply with Technical Specifications Unit

c. Provide input to the Preventive Maintenance and Surveillance Test Database (PMST) per GAP-PSH-02 3.2 Scheduling Surveillance Tests and LCO SDecified Actions 3.2.1 Each required surveillance test shall be scheduled PSH-02, except as noted below: per GAP-

a. Each department is responsible for scheduling, performing, and documenting completion of assigned "short frequency" tests (frequency of less than days). seven Page 1 GAP-SAT-01 Rev 06

3.2.1 (Cont)

b. Each department shall conduct "Event-Related (those associated with specific occurrences Tests" mode or LCO action statement requirements) such as request of the SSS. at the (C6) c. Unless-an LCO action specifically requires of a surveillance, LCO specified actions performance scheduled AND completed WITHIN the specifiedshall be requirements. Application of the 25% time surveillance extension to LCO actions is prohibited.

3.2.2 The responsible planner shall ensure a prepared for each surveillance test to Work Order is be performed per GAP-PSH-01.

3.2.3 Lead groups should ensure surveillance tests are completed on or before the Next Due Date. Unless by Technical Specifications, extensions otherwise specified may be authorized as follows: beyond Next Due Date

a. Greater than +15%, but NOT to exceed +25%,

assigned surveillance interval with approvalof the Manager of Branch

b. For a second consecutive performance greater but NOT to exceed +25% of the assigned than +15%,

surveillance interval with approval of the Branch Manager Plant Manager AND the 3.2.4 Responsible supervision may reschedule or delay performance of the surveillance test, IF:

a. The equipment is inoperable; OR

b. The station is NOT in the required condition performance of the test for 3.2.5 If a surveillance test cannot be performed specified plant or system conditions: within the

a. Responsible supervision shall notify the requires SSS notification at completion), SSS (if the ST and:

1. Reschedule the ST for a time when the conditions exist (primary alternative);necessary OR

2. Initiate a revision or change to the procedure allow the test to be performed under different to conditions

b. The SSS shall determine operability of equipment and take appropriate actions required by Technical Specifications.

Page 2 GAP-SAT-01 Rev 06

NineMile PoinRt 2 Category "A" - Examination Outlin c -

eross Referencet:

Operating Test Number ICat "A" Test:

Examination Level I APC}

Administrative Topic A.2 Subject

Description:

Surveillance Testing Question Number: 2 Question:

During a refueling outage, the 2DER*MOV120, EQUIP DRAINS OUTBD ISOL VLV, is scheduled to have its disk and seat replaced. Following completion of the work, what testing is required?

Answer: T--

. Stroke timing and exercise

. Full stroke freedom of movement verification

Position Indication

As-left leak rate Technical References):

GAP-SAT-02, Rev 07, Section 3.2 GAP-SAT-02, Rev 07, Definition 4.12 GAP-SAT-02, Rev 07, Attachment 1 NIP-DES-04, Attachment 5 T.S. 4.6.1.2.2, Table 3.6.1.2-1 K IAt #Y:- t- I ' Im

f . g~tmortance :000 2.1.12, 2.1.28, 4.0, 3.3, 2.1.33, 2.2.18, 4.0, 3.6, 2.2.21, 2.2.24 3.5, 3.8 lh M J! MI KIW I L . - -'

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION GENERATION ADMINISTRATIVE PROCEDURE GAP-SAT-02 REVISION 07 PRE/POST-MAINTENANCE TEST REQUIREMENTS TECHNICAL SPECIFICATION REQUIRED Approved by:

R. G. Smith Plant Manag.}>>- Unit 1 Date Approved by: 16-?--7 ? 9 N. C. Paleologos Plant Manager - Unit 2 -5 -

Date Effective Date: 10/3Q/98

3.2 Performance of Pre-Maintenance Test and PMT (C2) 3.2.1 If an SSC has operability conditions defined by technical specifications, the SSS shall ensure Pre-Maintenance Test (Unit 2 only) performance. Otherwise, the SSS may delegate responsibility for ensuring Pre-Maintenance Test (Unit 2 only) performance to the responsible supervisor.

3.2.2 To the extent possible, PMT should be performed under conditions that represent normal operating parameters such as flow, pressure, temperature, input signal values, and fluid type.

3.2.3 If multiple Pre-Maintenance Tests (Unit 2 only) and/or requirements are specified, Pre-Maintenance Tests (Unit PMT and/or PMT should be performed in a logical order so that2 only) adjustments made during one test do not invalidate a previously performed test.

3.2.4 Personnel shall perform Pre-Maintenance Tests (Unit 2 only) and/or PMT per applicable procedure/work instructions, and report Pre-Maintenance Tests (Unit 2 only) and/or PMT results to the responsible Branch Supervisor/SSS, as applicable, for evaluation per GAP-PSH-01.

(C8) 3.2.5 The SSS shall determine SSC operability based on a review of work documentation, PMT results, and applicable technical specification requirements (including LSFT requirements at Unit 2).

4.0 DEFINITIONS 4.1 DAnyn (as used in Attachments 1-3). An activity that could affect proper functioning of a component. Includes disassembly the of a component or power supply. Does not include removal of inspection covers on pressure retaining components, or non-intrusive maintenance, (such non-visual inspections or surface cleaning). as 4.2 CIV. Containment Isolation Valve 4.3 Functional Test. A test (such as a technical specification test) that demonstrates a component is capable of performingsurveillance its design functions. At Unit 2, this includes Logic System Functional Test requirements outlined as surveillance requirements in Technical Specifications.

4.4 Inservice Inspection (ISI). Non-destructive examination per ASME Code Section XI. B&PV 4.5 Leakage Test. A test for leakage at the point of maintenance, such Downy Wand or Snoop test. as a Page 3 GAP-SAT-02 Rev 07

4.6 Load Test. A test designed to ensure a component is capable a required load. of carrying 4.7 MOV Dynamic Test. A test performed on motor operated valves to prove that the valves will operate under design flow conditions.

4.8 MOV Static Test. A test performed on motor operated valves and trend valve/actuator baseline conditions. to develop 4.9 Operational Test. A test that demonstrates normal operation under normal service conditions. of equipment 4.10 PIV. Pressure Isolation Valve.

4.11 Post-Maintenance Test (PMT). A test performed during maintenance activities to verify an original deficiencyor following corrected and to ensure a particular SSC performs its has been design function.

4.12 Pre-Maintenance Test. A test performed prior to- maintenance to determine the "As Found" condition of a particular activities used only as required for Unit 2 Appendix J, Option B, SSC, currently Program Plan.

4.13 Pressure/Flow Test. A test performed at one operating demonstrate a that a fan or pump as operating on its point to head/capacity curve, or to show that a pressure boundary is sufficiently leak tight.

4.14 Pump Curve Validation. A test performed at a range of pressures and flows to demonstrate the validity of a pump head/capacity major pump maintenance. Requirements for pump curve curve after provided in specification MDC-11 (Unit 1 ONLY). validation are 4.15 Stroke Test. Movement of a valve or damper through a of its travel to assure freedom of movement. sufficient portion 4.16 Stroke Timing Test. Timing of the movement of a valve a sufficient portion of its travel to ensure the travelor damper through This test usually requires full travel unless partial time is correct.

previously documented. travel times are 4.17 VT-2. ASME XI, IWA-5240 code required visual examination leakage. for evidence of

5.0 REFERENCES

AND COMMITMENTS 5.1 Licensee Documentation Unit 1 and 2 Technical Specifications, Section 3.0/4.0, Conditions for Operation and Surveillance Requirements Limiting Page 4 GAP-SAT-02 Rev 07

ATTACHMENT 1 MECHANICAL PRE/POST-MAINTENANCE TEST GUIDELINES MECHANICAL' MAINTENANCE CO MC PRE/POST-MAINTENAN CE iTEST GUIDE:NES Compressors Any 1. Full cycle test (unusual noises)

2. Vibration levels

3. Bearing temperature

4. Leakage at operating pressures

5. Check parameters

Cooling flow

Oil level

Temperatures

Oil Contamination Containment: Primary Any opening of an airlock, Appendix J Program Plan testing, as applicable (may require Pre-Maint. test at Unit 2 (C10) hatch, or penetration; and - check with Appendix J Coordinator) any activity affecting the drywell head Containment: Airlock, airlock seea, Secondary Containment leakage test (Unit 1 TIS 4.4.1, Unit 2 TIS 4.6.5.1.c)

Secondary or penetration repair/replacement Control Room Pressure Door, door seal, Control Room pressure boundary test (Unit 1 TIS 4.4.5.g, Unit 2 T/S 4.7.3.e)

Boundary or penetration repair/replacement Coolers Any See Heat Exchangers or Freon Units Cranes/Hoists Any 1. Load test

2. Brake/clutch operability

3. Limit switch operability check Dampers Actuator repair 1. Stroke test or replacement 2. Stroke timing check Damage repair 1. Stroke test or replacement 2. For Reactor Building or Control Room isolation dampers, a system pressure/flow interlock test

3. Stroke timing check Diesels Any 1. EDG Synchronization and load test

2. Auto start functional test

3. Manual start test

4. Diagnostic baseline checks

Vibration

Cylinder compression

5. Fluid parameter checks

Lube oil level

Cooling water flow

Cooling water temperature

Fuel oil sampling

Governor control oil system

6. Engine analyzer

7. Voltage regulation and frequency checks

8. Protective features auto test

Overspeed

Generator differential

Low lube oil pressure

High crankcase pressure

9. Position indicator checks

10. Oil contamination Fans/Filter Units Any 1. Head/capacity (pressure/flow) test

2. Function test and manual start

3. Dynamic balance checks

4. Check

Bearing temperature

Vibration level

Abnormal noise

5. Measure running current Filters (Air) Housing maintenance 1. Leakage test

2. For SGTS, Control Room Emergency Ventilation, or Reactor Head Evacuation Filter Assembly, chemical absorption test Media replacement Flow, delta pressure, and chemical absorption test Intake area smoke, chemical Chemical absorption test release, or painting Filters (Fluid) Housing maintenance ISI/IST, Hydro Page 7 GAP-SAT-02 Rev 07

ATTACHMENT 1 MECHANICAL PRE/POST-MAINTENANCE TEST GUIDELINES(Cont)

MECHANICL MAINTENANCE COMPONENT l00 ACTIVITYNCE -;0. - i-PRE/POST-MAINTENA T Filters (Fluid Cont) Media Replacement 1. Flow check

_2.

Delta pressure check Fire Barriers: Door, door seal, Non-pressure boundary Visual inspection or penetration repairlreplacement Flanges Gasket replacement 1. Leakage check

2. System flow test

3. If part of primary containment pressure boundary, Appendix testing, as applicable J Program Plan Freon Units (Chillers) Any 1. Full cycle test

2. Leak check/vibration check at operational condition Gates (unusual noises)

Any Exercise test (raise/lower to check for binding/hang-ups Gears Any 1. Operability test under load (ST for driven device)

2. Check for noise/vibration Hatches: Any Leakage test Non-containment Heat Exchangers Tube plugging 1. Tube leakage test

2. For Unit 1 Containment Spray, leak test

3. Verification of heat exchanger capability, either by test

4. Hydrostatic or operational test for tube end tube sheet or analysis

5. Heat exchanger parameter check leakage test

Temperature

Flow

External leakage Hydraulic Units Any 1. Surveillance Test (for driven device)

2. Operability test and leakage check

3. Full cycle test

4. Timing or sequence check (C12) Internal Coolers Any 1. Verify adequate flow

. 2. Verify no internal leakage Piping System Maintenance I

1. System flushed

2. ASME Code requirements (hydro test)

3. Integrity check of mechanical joints

4. Cleanness check

5. System restoration

Piping supports

Heat tracing

Insulation

6. Ensure proper attachment of instrumentation lines

7. If part of primary containment pressure boundary, testing, as applicable (Pre- and Post-Maintenance Appendix J Program Plan Testing - Unit 2)

(C1 0) Weld repair 1. ISUIIST

2. Code required leakage test (VT-2)

3. If through wall repair, flush or run pump

4. If part of primary containment pressure boundary, Appendix J Program Plan testing, as applicable Pumps: Safety or Non- General Safety related 1. Appropriate Surveillance Test (ST)

2. If motor leads were disconnected, check direction of rotation

3. Inspect:

Filters

Oil level

Oil contamination

Cooling flow

Pressures

Bearing temperatures

4. Auto function test (all interlocks)

5. Inspect baseplate and foundation

6. Flush or internal inspection Packing/mechanical seal 1. Check for gross leakage replacement 2. Adequate seal cooling

3. Run pump for one hour and then readjust packing

4. Appropriate Surveillance Test (ST)

Adjustment or operating Run pump for one hour and then readjust packing pump packing Page 8 GAP-SAT-02 Rev 07

ATTACHMENT 1 MECHANICAL PRE/POST-MAINTENANCE TEST GUIDELINES(Cont)

MECHANICAL"!:-:' ::'MAIN'TENANCE l...COMPONENT AC ..

.. PRE/POST-MAINTENANCE ST.GUIDEUNES Pumps: Safety or Non- Overhaul, wear ring 1. Vibration Safety related (Cont) tolerance changes, impeller 2. Bearing temperature replacement/trimming 3. Internal visual inspection (C3,C6)4. Pump curve validation

Unit 1 - as required per MDC-1 1

Unit 2 - curve validation shall be performed for pumps in the IST program.

For remaining pumps, System Engineering (Tech. Supp. Engr.) will determine the required testing for curve validation.

5. ISI/IST

6. Code required leakage test/(VT-2)

7. Appropriate Surveillance Test (ST)

Casing repair 1. Vibration Testing

2. Code required leakage test (VT-2)

3. System flush Racks Any Load test Rod Drives/HCUs Any 1. Exercise test

2. Scram time test Any affecting coupling Coupling integrity test integrity Snubbers Any 1. Functional test/stroke test

2. VT 3/4 (when required)

Strainers Pressure boundary repair 1. ISI/IST

2. Code required leakage test (VT-2)

Any other 1. Flow test

2. Pressure differential check Tanks/Pressure Vessels Pressure boundary repair 1. ISM/1ST or replacement 2. Code required leakage test (VT-2)

3. Tank/vessel integrity checks

4. Content checks

Concentration

Level

Viscosity

Other

5. Parameter checks

Proper level

Pressure

Temperature

Cleanness

6. Flush Traveling Screens Any Full cycle test Turbines Any 1. Surveillance Test (ST) for driven component

2. Auto start functional test

3. Turbine protective feature test

4. Manual start test

5. Oil level check

6. Check for fluid leakage at normal system parameters

7. Vibration analysis

8. Visual check for rotor grounds

9. Fluid inspection for contamination

10. Grease sliding plates at foundation and pedestal

11. Auxiliaries for heating and cooling

12. Turbine (pump) performance check

Flow

Speed

Bearing temperature

Vibration amplitude Valves Non-CIV packing 1. Stroke timing test replacement and adjustment 2. Verify full stroke freedom of movement (Power operated valves only) 3. Leakage check at normal operating pressures

4. Leak rate test, if required

5. Running current checks on motor (C7) 6. GL 89-10 valves, verify final force or perform MOV Static Test Page 9 GAP-SAT-02 Rev 07

ATTACHMENT 1 MECHANICAL PRE/POST-MAINTENANCE TEST GUIDELINES(Cont)

AiMECHANI L MNECHANICAL I V~i: MMAINTEN COMPON NT: _.....

ANTNANCE AC:TT

-7e i

i-:--:

. M:i:-

-: -i; I:

PRE/POST-MAINTENANCE TT GUIDEUNE-

.......i-::

i--

E v alves *Akvn 1.

racKing replacement or I-or ClVs, Appendix J Program Plan testing, as applicable (Pre- and Post-adjustment for ClVs or PIVs Maintenance Testing - Unit 2) listed in NIP-DES-04 2. Stroke timing & exercise Attachments 5 or 6 3. Verify full stroke freedom of movement (at operating pressure)

4. Fail test if applicable

5. Position indication (C7) 6. GL 89-10 valves, verify final force or nerform MOV Stati, Test CIV repair/replacement 1. Perform any code required strength or seat tightness testing (C10) 2. Appendix J Program Plan testing, as applicable (Pre- and Post-Maintenance Testing - Unit 2)

3. Verify position indication (C7) 4. GL 89-10 valves MOV static and/or dynamic test, as directed by MOV coordinator

5. Stroke timing and exercise

6. ISI/IST

7. Code required leakage test (VT-2)

Check valves; installation if 1. Verify proper orientation new, or reworked, or

Direction of flow pressure boundary breached

Valve attitude (top-up, bonnet accessibility)

2. Code required leakage test (VT-2)

3. Visual local leak test at normal operating temperature and pressure (C10) 4. For CIVs, Appendix J Program Plan testing, as applicable (Pre- and Post-Maintenance Testing - Unit 2)

5. Operational test

Opening/closing

No abnormal noise

Valve chatter

Cavitation

6. Appropriate Surveillance Test (ST)

7. ISIUIST Limit switch replacement 1. Stroke timing and exercise or adjustment 2. Verify limit switch actuation of controlled device including any interlocks (C10) (stem mounted or internal) 3. For limit seated CIVs, Appendix J Program Plan testing, as applicable (Pre- and (C1li) Post-Maintenance Testing - Unit 2)

4. Position indication test as required

5. GL89-10 valves, MOV static test or other verification method as approved by MOV Coordinator Pressure regulating valve 1. Set point calibration check repair or replacement 2. Valve seat leakage test Torque switch replacement 1. Stroke timing and exercise (ClO or adjustment 2. For ClVs, Appendix J Program Plan testing, as applicable (Pre- and Post-Maintenance Testing - Unit 2)

(C7) 3. GL 89-10 valves MOV static test MOV Actuator - Motor 1. Stroke timing and exercise (C10) change (like for like), Motor 2. For ClVs, Appendix J Program Plan testing, as applicable (Pre- and Post-pinion change (like for like), Maintenance Testing - Unit 2)

Tripper finger adjustment MOV Actuator upper 1. Stroke timing and exercise (C7) housing cover removal 2. GL 89-10 valves, verify final force or perform MOV Static Test MOV replacement 1. Verify Engineering reperforms calculations per NRC Generic Letter 89-10 MOV Program (C7) 2. GL 89-10 valves, MOV static and dynamic tests, as directed by MOV coordinator

3. Stroke timing & exercise

4. Position Indication as required

5. ISIPIST

6. Code required leakage test (VT-2)

(CO0) 7. For CIVs, Appendix J Program Plan testing, as applicable (Pre- and Post-t Maintenance Testing - Unit 2)

Page 10 GAP-SAT-02 Rev 07

ATTACHMENT 1 MECHANICAL PRE/POST-MAINTENANCE TEST GUIDELINES(Cont)

_I . -.. .. . .

. MECHANICAL:---- I I' COMPONENT....'.":

I

'ACTIVITY 1 MAANTNNTENANCEUIJ PRE/POST-MAINTENAN IDE r E

_ -?

Valves (Cont) I Motor operator replacement, 1. Stroke timing and exercise

\--1 (C7) gear train repair, spring pack 2. GL 89-10 valves, MOV static test replacement, spring pack 3. Verify limit switch actuation of controlled device including any interlocks adjustment, operator 4. Seat leakage test removal, operator changes 5. Starting/running motor current affecting speed or 6. Verify torque and limit switch settings thrust/torque, 7. Automatic function test motor modifications 8. Position verification check

9. MOV grease/lubrication (C4) 10. Full-stroke exercising check (two strokes) at normal system flow, pressure and temperature (C10) 11. For CIVs, Appendix J Program Plan testing, as applicable (Pre- and Post-Maintenance Testing - Unit 21 (C4) Air operator replacement 1. Full-stroke exercising check (two strokes) at normal system parameters

2. Automatic function test

3. Position verification check

4. Control valve loop alignment verification

5. Positioner and E/P or S/P converter calibration

6. Stroke timing

7. Verify limit switch actuation of controlled device, including any interlocks

8. Snoop air connections (C10) 9. For CIVs, Appendix J Program Plan testing, as applicable (Pre- and Post-Maintenance Testing - Unit 2)

Solenoid valve repair or 1. For each sequence solenoid/actuator, full-stroke exercising check replacement, controller 2. Seat leakage test replacement 3. Automatic function test

4. Position indication verification check

5. Stroke time as required

6. Code required leakage test (VT-2)

(C10) 7. For CIVs, Appendix J Program Plan testing, as applicable (Pre- and Post-Maintenance Testing - Unit 2)

8. ISI/IST rMSSurc boundary repair

~~

I IlI/IT I I.

2. Code required leakage test (VT-2)

3. If part of primary containment pressure boundary, Appendix J Program Plan

.. testing, as applicable (Pre- and Post-Maintenance Testing - Unit 2)

I Valve Internals Air/motor operated valve 1. For CiVs. Appendix J Program Plan testing, as applicable (Pre- and Post-(C10) repair/replacement including Maintenance Testing - Unit 2) stem, disc, or seat 2. MOV grease/lubrication changes or lapping 3. Verify position indications (remote and local)

4. For packing adjustment, stroke timing (C4) 5. Full stroke exercise (two strokes)

(C7) 6. GL 89-10 valves, MOV static test and/or dynamic test as directed by MOV coordinator

7. Stroke time as required

8. Code required leakage test (VT-2)

9. ISI/IST Pressure isolation valve 1. Stroke time & exercise repair/replacement 2. Position indication as required

3. Seat leakage test (Unit 1 T/S 3.2.7.1, Unit 2 T/S 3.4.3.2.d)

(C10) 4. Appendix J Program Plan testing, as applicable (Pre- and Post-Maintenance Testing - Unit 2)

5. Code required leakage test (VT-2)

6. ISI/IST (C7) 7. GL 89-10 valves, MOV static test and/or dynamic test as directed by MOV coordinator (C10) CIV repair/replacement 1. Appendix J Program Plan testing, as applicable (Pre- and Post-Maintenance Testing - Unit 2)

2. Stroke timing & exercise (C7) 3. GL 89-10 valves, MOV static test and/or dynamic test as directed by MOV coordinator

4. Position Indication

5. Code required leakage test (VT-2)

6. ISI/IST unI I only) lorus to 1. Pressure decay rate test Drywall vacuum breaker 2. Force test per T/S 4.3.6.b.1 repair/replacement 3. Appendix J Program Plan testing, as applicable Page 11 GAP-SAT-02 Rev 07

ATTACHMENT 1 MECHANICAL PRE/POST-MAINTENANCE TEST GUIDELINES(Cont)

MECHANICL .:MAINTENANCE -

f'COMPONENT. .-. i.-RACTIVITY PREPOST-AINTENANCE EST UIDL Valve Intemals (Cont) (Unit 2 only) Suppression 1. Cycle through at least one complete cycle of full travel (T.S.

Pool/Drywell Vacuum 4.6.4.b.1)

2. Verify the position indicators -operable' by performance Breaker repair/replacement Calibration' (T.S. 4.6.4b.3b) of a Channel

3. Set point test (T.S. 4.6.4b.3s)

4. Leak rate test, if required (Unit 2 only) Vacuum 1. Exercise Breakers, other than 2. Set point test Drywell/Suppression chamber repair/replacement (Unit 1 only) Reactor 1. Force test per TIS 4.3.6.b.1 Building to Torus vacuum 2. Appendix J Program Plan testing, as applicable breaker repair/replacement Accumulator check valve 1. Leakage check per TIS 4.1.3.5.b.2 (Unit 2) repair/replacement 2. Exercise

3. Code required leakage test (VT-2)

4. ISI/IST Safety Valve 1. Relief setpoint test before installation repair/replacement 2. Leak test at operating pressure (see OM-1 for Unit 2)

3. Valve seat leakage test

4. Proper position indications, chattering check, packing

5. Code required leakage test (VT-2) leakage

6. Visual ERV/ADS At Unit 1, flow test per T/S 4.1.5.a

_ __ repair/replacement At Unit 2, flow test per T/S 4.5.1.e.2.b Page 12 GAP-SAT-02 Rev 07

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION NUCLEAR INTERFACE PROCEDURE NIP-DES-04 REVISION 24 LIST OF CONTROLLED LISTS TECHNICAL SPECIFICATION REQUIRED Approved By:

.21./, X R. B. Abbott Vice President Nuclea Engineering Date Effective Date: 03/09/99

C ATTACHMENT 5: UNIT 2 PRIM/(( ,ONTAINMENT ISOLATION VALVES PaOP I of I13 r

ISOLATION VALVE FUNCTION VALVE VALVE NO. ISOLATION MAXIMUM CLOSING GROUP SIGNAL (a) TIME (SECONDS)(p)

A. AUTOMATIC 2MSS*AOV6 AB,C,D Inside MSIV 2MSS*AOV7 AB,C,D Outside MSIV 1 Z,XC,D,E,P,T,R,RM,AA 3 to 5 1 Z,X,C,D,E,P,T,R,RM,AA 3 to 5 2MSS*MOV208 MSL Drain Line Outside IV 2MSS*MOV111 Main Steam Drain Line Inside IV 1 Z,X,C,D,E,PT,R,RM,AA 18 2MSS*MOV112 Main Steam Drain Line Outside IV 1 Z,X,C,D,E,P,T,R,RM,AA 60 1 Z,X,C,DE,P,T,R,RM,AA 60 2RHS*M0V33 A,B RHS Cont. Spray Outside IVs 2RHS*MOV104 RHS Reactor Head Spray Outside IV

RM and

35 2RHS*MOV40 A,B 5 A,L,M,Z,RM,CC,DD 50 Shutdown Cooling Return Outside IVs 5 A,LM,Z,RM,CC,DD 2RHS*MOV67 A,B SDC Inboard IV Bypass Valves 29 2RHS*MOV112 5 A,L,M,Z,RM,CC,DD 18 SDC Supply Inside IV 5 A,L,M,Z,RM,CC,DD 2RHS*MOV113 SDC Supply Outside IV 29 5 A,L,M,Z,RM,CC,DD 29 2CSH*MOV111 CSH Test Return to Suppression Pool

RM and

60 Outside IV 21CS*MOV164 RCIC Vacuum Breaker Outside IV 11 H & F, RM 21 2CCP*MOV94 A,B CCP Supply to RCS Inside IVs CCP 8 B,F,Z,RM 38 Supply to RCS Outside IVs 8 B,F,Z,RM 2CCP*MOV16 A,B CCP Return from RCS Pumps Inside IVs 38 2CCP*MOV15 A,B CCP 8 B,F,ZRM 38 Return from RCS Pumps Outside IVs 8 BF,ZRM 38 2DFR*MOV120 DFR Drain Tank Line Outside IV 2DFR*MOV121 DFR Drain Tank Line Inside IV 8 BF,Z,RM 45 8 BF,Z,RM 54 2DER*MOV119 DER Line from Drywell Inside IV 2DER*MOV120 DER Line from Drywell Outside IV 8 B,F,Z,RM 35 8 B,F,Z,RM 35 2RCS*SOV104 RCS Sample Inside IV 2RCS*SOV1O5 RCS Sample Outside IV 2 B,C,Z,RM 5 2 B,C,Z,RM 5 Page 9 NIP-DES-04 Rev 24

ATTACHMENT 5: UNIT 2 PRIMARY CONTAINMENT ISOLATION VALVES ( -

_ _ Page 2 of 13 ISOLATION VALVE FUNCTION VALVE NO. VALVE ISOLATION MAXIMUM CLOSING GROUP SIGNAL (a) TIME CLONG()

2FPW*SOV218 i RCS A Water Spray Outside IV 2FPW*SOV219 i RCS A Water Spray Inside IV NA NA 2FPW*SOV220 i RCS B Water Spray Outside IV NA NA 2FPW*SOV221 i RCS B Water Spray Inside IV NA NA NA NA 2DFR*MOV139 2DFR*MOV140 nnK Vent Line Outside IV 8 B,F,Z,RM DFR Vent Line Inside IV 20 8 B,F,Z,RM 20 2DER*MOV130 DER Vent Line Inside IV 2DER*MOV131 DER Vent Line Outside IV 8 B,F,Z,RM 18 2CCP*MOV265 Sply to Drywell Space Cooler Outside IV 8 B,F,Z,RM 18 2CCP*MOV273 Sply to Drywell Space Cooler Inside IV 8 B,F,Z,RM 60 2CCP*MOV122 Return from DrywellSpace Cooler Inside B,F,Z,RM 2CCP*MOV124 Return from Drywell Space Cooler Outside IV 8 B,F,Z,RM 60 IV 8 B,F,Z,RM 60 2CPS*AOV104 60 Purge Inlet to Drywell Outside IV 2CPS*AOV105 Purge Inlet to Sup. Chamber Outside IV 8 B,F,Y.Z,RM 2CPS*AOV106 n Purge Inlet to Drywell Inside IV 9 B,F,Y,Z,RM 5 2CPS*AOV107 n Purge Inlet to Sup. Chamber Inside 9 B,F,Y,Z,RM 5 2CPS*AOV108 n Purge Exhaust from Drywell Inside IV IV 9 B,F,Y,Z,RM 2CPS*AOV109(n 9 5 Purge Exhaust from Sup. Chamber Inside B,F,YZ,RM 5 2CPS*AOV110 Purge Exhaust from Drywell Outside IV 9 B FFY Z, RM 5 2CPS*AOV111 Purge Exhaust from Sup. Chamber OutsideIV 9 BBF' Y'Z,RM IV 9 B,F,YZ,RM 5 2IAS*SOV164 5 ADS Hdr A N2 Supply Outside IV 2IAS*SOV165 ADS Hdr B N Supply Outside IV 8 B,F,YZ,RM 5 2IAS*SOV166 IAS to MSS eafety Relief Valve Outside 8 B,F,Z,RM 5 2IAS*SOV184 IAS to MSS Safety Relief Valve Inside IV 8 B,F,Z,RM 2IAS*SOV168 Inst. Air to Testable Check Outside IV IV 8 B,F,Z,RM 5 2IAS*SOV180 Inst. Air to Testable Check Inside IV 8 B,F,Z, RM 5 2IAS*SOV167 IAS to test Ck. & Vac. Bkrs. Outside IV 8 5 2IAS*SOV185 B,F,Z,RM IAS to test Ck. & Vac. Bkrs. Inside IV 8 B,F,Z,RM 5 8 B,F,Z,RM 5 5

Page 10 NIP-DES-04 Rev 2

( ATT~rulmm Al I111E-tLfl r-1:

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PIMArR LUNIAINMENT ISOLATION VALVES Page 3 of 13

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ISOLATION VALVE FUNCTION VALVE NO. VALVENO. VALVE ISOLATION ROUPMAXIMUM GROUP CLOSING SIGNAL (a) TIME (SECONS)(p) eHU-bMUV1 A,B H Recombiners Sply to Supp. Chamber O6tside IVs 8 2HCS*MOV2 A,B H Recomb. Ret. from Supp. Chamber B,F,Z,RM 30 O6tside IVs 8 B,F,Z,RM 2HCS*MOV3 A,B H2 Recomb. Return from Drywell Outside IVs 30 2HCS*MOV4 A,B~;q H2 Recomb. Sply. to Supp. Chamber Inside IVs 8 B,F,Z,RM 30 2HCS*MOV5 A,B n) H2 Recomb. Ret. from Supp.Chamber Inside IVs 8 B,F,Z,RM 30 2HCS*MOV6 A,B ,q) H2 Recomb Ret. from Drywell Inside IVs 8 B,F,Z,RM 30 8 B,F,Z,RM 30 2CPS*SOV119 Containment Purge to Supp. Chamber Outside IV 9 2CPS*SOV120 Containment Purge to Drywell Outside IV B,F,Y,Z,RM 2 2CPS*SOV121(n) Containment Purge to Supp.Chamber Inside IV 9 B,F,Y,Z,RM 2 2CPS*SOV12 (n) Containment Purge to Drywell Inside IV 9 B,F,YZ,RM 2 9 B,F,YZ,RM 2 2CMS*SOV24A,B,C,D CMS from Drywell Inside & Outside IVs 2CMS*SOV26A B C D CMS from SP Inside & Outside IVs 8 B,F,Z,RM 5 2CMS*SOV32 A,B CMS to Drywell Outside IVs 8 B,F,Z,RM 5 2CMS*SOV33 A,B (n) CMS to Drywell Inside IVs 8 B,F,Z,RM 5 2CMS*SOV34 AB(n) CMS to SP Inside IVs 8 B,F,Z,RM 5 2CMS*SOV35 A,B CMS to SP Outside IVs 8 B,F,Z,RM 5 2CMS*SOV6O A,B CMS from Drywell Outside IVs 8 B,F,Z,RM 5 2CMS*SOV61 AB(n) CMS from Drywell Inside IVs 8 B,F,Z,RM 5 2CMS*SOV62 A,B CMS to Drywell Outside IVs 8 B,F,Z,RM 5 2CMS*SOV63 A,B(n) CMS to Drywell Inside IVs 8 B,F,YZ,RM 5 8 B,F,Z,RM 5 2CPS*SOV132 Nitrogen to 2CPS*AOV107 Outside IV 2CPS*SOV133 Nitrogen to 2CPS*AOV109 Outside IV 9 B,FY Z,RM 5 9 B,F,YZ,RM 5 2LMS*SOV152(i) LMS from Drywell Inside IV 2LMS*SOV153(i LMS from Drywell Outside IV 5 2LMS*SOV156 i 8 B,F,Z,RM LMS from SP Inside IV 8 BF,Z,RM 5 2LMS*SOV157 i LMS from SP Outside IV 8 B,F,Z,RM 5 8 B,F,Z,RM 5 Page 11 NIP-DES-04 Rev 24

( ATTACHMENT 5: (

UNIT 2 PRIMARY CONTAINMENT rsnlATTniJ n__ . .

~ Vfl VL.)

rage q of 13 ISOLATION VALVE VALVE FUNCTION NO. V VALVE ISOLATION MAXIMUM CLOSING GROUP SIGNAL (a) TIME (SECONDS)(I) 2RCS*SOV65 AB 2RCS*SOV66 AB 11 Hyd.

Hyd. Unit Unit to RCS FCVs Outside IVs to RCS FCVs Outside IVs 8 B,F,Z,RM 20 2RCS*SOV67 A,B 1 Hyd. Unit to RCS FCVs Outside IVs 8 B,F,Z,RM 2RCS*SOV68 A,B 1 8 B,F,Z,RM 20 Hyd. Unit from RCS FCVs Outside IVs 20 2RCS*SOV79 A,B 1 Hyd. Unit to RCS FCVs Inside IVs 8 B,F,Z,RM 2RCS*SOV80 A,B 1 8 B,F,Z,RM 20 Hyd. Unit to RCS FCVs Inside IVs 20 2RCS*SOV81 A,B 1 Hyd. Unit to RCS FCVS Inside IVs 8 B,F,Z,RM 2RCS*SOV82 A,B 1 8 B,F,Z,RM 20 Hyd. Unit from RCS FCVs Inside IVs 20 8 B,F,Z,RM 20 21CS*MOV121 RCIC Steam Supply Outside IV 2ICS*MOV128(q)

I RCIC Steam Supply Inside IV 10 K,M,H,Z,RM BB CC DD I

21CS*MOV170 10 K,M,H,RM,B6,Ct,Db 30 A

RCIC Warmup Va ve Inside IV 30 10 K,M,H,RM,BB,CC,DD 18 I )wre*Mnl1nr . _

2WCS*MOV112 WCS Supply from RCS & RPV Inside IV WCS Supply from RCS & RPV Outside IV B,J,U,S,Z,RM,DD 14 7 B,J,U, S,Z,RM,DD 21CS*MOV148 14 RCIC Vacuum Breaker Outside IV 11 H & F, RM 2NMS*SOVlA,B,C,D,E 21 Traversing Incore Probe Ball Outside IVs 3 B,F,Z,RM 2GSN*SOV166 Nitroqen Purge to TIP Indexing Mechanism Outside IV 3 B,F,Z,RM 5 2RHS*MOV142(j)(m) RHS Drain to Radwaste Outside IV 2RHS*MOV149(j) (i) RHS Drain to Radwaste Inside IV 4 A,Z,F,RM 2RHS*SOV35 A/t 4 A,Z,F,RM 30 25 RHS Sample HX Outside IWs 2RWS*SOV 36 A/B 4 A,Z,F,RM 5 (j) 2RDS*AOV124 2RDS*AOV13Z 2RDS*AOV123 2RDS*AOV130 k) k)

k) k)

RHS Sample HX Inside IVs SCRAM Discharge Volume Vent SCRAM Discharge Volume Vent SCRAM Discharge Volume Drain SCRAM Discharge Volume Drain 4

NA NA NA NA A,Z,F,RM NA NA NA I

NA Page 12 NIP-DES-04 Rev 2

(

ATTACHMENT 5: UNIT 2 PRIMARY CONTAIN.MENT ISOLATION VALVES pana q nf 11 I - . .. . .

1ZULAI I1N VALVE FUNCTION I VAIVF NO. VALVE ISOLATION MAXIMUM CLOSING I GROUP SIGNAL (a) TIME (SECONDS)(D)

B. Remote Manual 2RHS*MOV15 A B Containment Spray to Drywell Outside IVs 2RHS*MOV1 A A C(o) RHS Pump Suction Outside IVs 12 RM NA 2RHS*MOV30 A,A RHS Test Line to SP Outside IVs 12 RM NA 2RHS*MOV25 A,B(q) Containment Spray to Drywell Outside IVs 12 RM NA 2RHS*MOV24 A,B,C RHS/LPCI to RPV Outside IVs 12 RM NA 12 RM NA 2CSH*MOV118(q)(o) CSH Suction from SP Outside IV 2CSH*MOV105 HPCS Min Flow Bypass Outside IV 12 RM NA 2CSH*MOVIO7 CSH to RPV Outside IV 12 RM NA 12 RM NA 2CSL*MOVI112(o) CSL Suction from SP Outside IV 2CSL*MOV1O4 CSL to RPV Outside IV 12 RM NA 12 RM NA ICS Suction from SP Outside IV 2ICS*MOV143 (n) ICS Min Flow to SP Outside IV 12 RM NA 2ICS*MOV122 q ICS Turbine Exhaust to SP Outside IV 12 RM NA 2ICS*MOV126 q ICS to RPV Outside IV 12 RM NA 12 RM NA 2NMS*VEXI A,B,C, D,E(d) Traversing Incore Probe Shear Outside IVs 12 RM NA 2FWS*MOV21 A,B Feedwater to RPV Outside IVs 12 RM NA 2WCS*MOV200 WCS to RPV Outside IV 12 RM NA 2RHS*MOV26 A,B(c)(o)RHS HX Vent Inboard IVs 2RHS*MOV27 A,B( c( o)RHS HX Vent Outboard IVs 12 RM NA 12 RM NA 2SLS*MOV5 A,B(g) SLS to RPV Outside IV 12 RM NA Page 13 NIP-DES-04 Rev 24

C .........

ATT MTrH, 11JT V. uilJ 03nn f

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rruiuKu LUNIAMlMtNI IbULAIION VALVES Page 6 of 13 ISOLATION VALVE FUNCTION VALVE ISOLATION MAXIMUM LOSING J AV N. _GOP SIGNAL (.a) TIME (SECONDS)(p)

C. Manual 2SAS*HCV16O SAS to Drywell Outside IV 2SAS*HCV161 SAS to Drywell Outside IV 2SAS*HCV162 SAS to Drywell Inside IV 2SAS*HCV163 SAS to Drywell Inside IV 2AAS*HCV134 AAS to Drywell Outside IV 2AAS*HCV135 AAS to Drywell Outside IV 2AAS*HCV136 AAS to Drywell Inside IV 2AAS*HCV137 AAS to Drywell Inside IV 2RHS*V192 RCIC/RHS Vacuum Breaker Outside IV 2SFC*V203 Inner Refuel Seal Leakoff Outboard IV 2SFC*V204 Inner Refuel Seal Leakoff Inboard IV D. Other Safety Relief 2RHS*RV20 A,B,C d RHS RV Disch. to SP Outside IVs 2RHS*RV61 ABC d) RHS RV Disch. to SP Outside IVs 2RHS*RV1 08(d RHS RV Disch. to SP Outside IVs 2RHS*RV110(d SDC to RHS Pump Suction RV 2RHS*RV139 d RHR Hdr. Flush to Radwaste RV 2RHS*RV152 nl SDC Supply from RCS RV Inside IV 2RHS*RV56 A,BCd RHS HX Shell Side RVs 2RHS*SV34 AB d RHS HX Steam Supply Safety Valves 2RHS*SV62 A B d RHS HX Steam Supply Safety Valves 2RHS*RVV35 A,B(d) RHS Vacuum BreaKers 2CSL*RV105(d) CSL RV Disch. to SP Outside IV 2CSL*RV123(d) CSL RV Disch. to SP Outside IV Page 14 NIP-DES-04 Rev 2'

( ( (I ATTACHMENT 5: UNIT 2 PRIMARY CONTAINMENT ISOLATION VALVES Page 7 of 13 ISOLATION VALVE FUNCTION VALVE NO. VALVE ISOLATION MAXIMUM CLOSING GROUP SIGNAL (a) TIME (SECONDS)(n) 2RHS*RVV36 A,B(d) RHS Vacuum Breakers 2CCP*RV170(n) CCP RV Discharge Inside IV 2CCP*RV171(n) CCP RV Discharge Inside IV 2CSH*RV113(d) CSH RV Disch. to SP Outside IV 2CSH*RV114(d) CSH RV Disch. to SP Outside IV 2RHS*RV57A,B(r) Outside IV Bonnet Pressure Relief Check Valves 2RHS*AOV16 AB,C(h) RHS/LPCI to RPV Inside IVs 2RHS*AOV39 AB(h) SDC to RCS Inside IVs 2CPS*V50 Nitrogen Supply to CPS*AOV107 Inside IV 2CPS*V51 Nitrogen Supply to CPS*AOV109 Inside IV 2CSH*AOV108(h) CSH to RPV Inside IV 2CSL*AOV101(h) CSL to RPV Inside IV 2ICS*AOV156(h) ICS to RPV Outside IV 2ICS*AOV157(h) ICS to RPV Inside IV 2SLS*V10 SLS to RPV Inside IV 2GSN*V170 N2 Purge to Tip Index Mech. Inside IV 2IAS*V448 1AS to ADS Accumulators Inside IV 2IAS*V449 IAS to ADS Accumulators Inside IV 2RCS*V59 A,B RDS to RCS Pumps A and B Seals 2RCS*V60 A,B Outside IVs RDS to RCS Pumps A and B Seals Inside IVs 2RCS*V90 A,B RDS to RCS Pumps A and B Seals Outside IVs Page 15 NIP-DES-04 Rev 24

Cf ATT ATTACIJMFlJT MMM A 11TT 3 nTUrfw-..-

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A.I 92 L flfTMADV rRI'Ini UNIilI'4I 1iULAIiUN VALVES fSTLIrayaThTro... ....................... ass Page 8 of 13 l ISOLATION VALVE NO. _

VALVE FUNCTION VALVE GROUP ISOLATION SIGNAL (a)

MAXIMUM CLOSING TIME (SECONDS)(p)

I 2RHS*V19 d)(f Discharge Check from RCIC to Supp. Pool 2RWS*V20(d) (f) Discharge Check from RCIC to Supp. Pool 2RHS*V11i df Check Valve from RCIC Drain to Supp. Pool 2RHS*V118 d)(f) Check Valve from RCIC Drain to Supp. Pool 2FWS*AOV23 A,B(h) Feedwater to RPV Outside IVs 2FWS*V12 A,B Feedwater to RPV Inside IVs Excess Flow Check(e)

Reactor Instrumen-tatio-nLines 2ISC*EFV1 Inst. Line from MSS 2ISC*EFV2 Inst. Line from N14, 2000 2ISC*EFV3 Inst. Line from N14, 160° 2ISC*EFV4 Inst. Line from N13, 190° 2ISC*EFV5 Inst. Line from N14, 20° 2ISC*EFV6 Inst. Line from N14, 3400 2ISC*EFV7 Inst. Line from N13 100 2ISC*EFV8 Inst. Line from N12' 1600 2ISC*EFV10 Inst. Line from N12, 2000 2ISC*EFV11 To 2ISC*FT47K,FT48B 2ISC*EFV13 To 2ISC*FT47H 2ISC*EFV14 Vessel Bottom Tap Loop A Jet Pump 2ISC*EFV15 Inst. Line from N12, 3400 21SC*EFV17 Inst. Line from N12, 200 2ISC*EFV18 To 2ISC*FT47J,FT48A 2ISC*EFV20 To 21SC*FT47E 2ISC*EFV21 Vessel Bottom Tap for CSH, RDS 2ISC*EFV22 Vessel Bottom Tap for WCS and Loop B J.P.

2ISC*EFV23 To 2ISC*FT48C and Postaccident Sampling 2ISC*EFV24 To 21SC*FT48D and Postaccident Sampling 2ISC*EFV25 To 21SC*FT47L 2ISC*EFV26 To 2ISC*FT47C Page 16 NIP-DES-04 Rev 2

((

ATTACHMENT 5: UNIT 2 PRIMARY CONTAINMENT ISOLATION VALVES Page 9 of 13 ISOLATION VLVE NO. VALVE FUNCTION VALVE ISOLATION IROOLATIONMAXIMUM CLOSING GROUP SIGNAL (a) TIME(EOD)~

2ISC*EFV?7 T- nlrrc,17A IU L13,-rlf1/A 2ISC*EFV28 To 21SC*FT47R 2ISC*EFV29 To 2ISC*FT47G 2ISC*EFV30 To 2ISC*FT47N 21SC*EFV31 To 2ISC*FT48A 2ISC*EFV32 To 21SC*FT47T 2ISC*EFV33 To 21SC*FT47V,FT48C 2ISC*EFV34 To 21SC*FT47B 2ISC*EFV35 To 21SC*FT47D 2ISC*EFV36 To 2ISC*FT47F 2ISC*EFV37 To 21SC*FT47S 2ISC*EFV38 To 21SC*FT47M 2ISC*EFV39 To 21SC*FT47P 2ISC*EFV40 To 21SC*FT48B 21SC*EFV41 To 21SC*FT47U 21SC*EFV42 To 21SC*FT47W,FT48D 2ISC*EFV9 Containment Pressure 2ISC*EFV12 21SC*PT15C,16B,16D Containment Pressure 21SC*PT15B,17B,17D 2ISC*EFV16 Containment Pressure 21SC*EFV19 21SC*PT15A, 16A,16C Containment Pressure 21SC*PT15D,17A,17C 2CMS*EFV1A To CMS*PT1A 2CMS*EFVIB To CMS*PT1B 2CMS*EFV3A To CMS*PT2A 2CMS*EFV3B To CMS*PT2B 2CMS*EFV5A To CMS*PT7A 2CMS*EFV5B To CMS*PT7B 2CMS*EFV6 To CMS-PT168 2CMS*EFV8A To CMS*LT9A,IIA,114 2CMS*EFV8B To CMS*LT9B,IIB,105 2CMS*EFV9A To CMS*LT9A,llA,114 2CMS*EFV9B To CMS*LT9B llB,105 2CMS*EFV10 To CMS-P117i Page 17 NIP-DES-04 Rev 24

( ( (

ATTACHMENT 5: UNIT 2 PRIMARY CONTAINMENT ISOLATION VALVES Page 10 of 13 ISOLATION VALVE FUNCTION IVALVE NO. _ VALVE ISOLATION MAXIMUM CLOSING GROUP SIGNAL (a) _ .TIME (SECONDS)(p)

ICS*EFVI To 2ICS*PDT167 2ICS*EFV2 To 2ICS*PDT167 2DER*EFV31 To DER*PT134 2ICS*EFV3 To 21CS*PDT168 2ICS*EFV4 To 21CS*PDT168 2IAS*EFV200 To 21AS*PT230 off ADS 2IAS*EFV201 Accum.

To 2IAS*PT231 off ADS Accum.

21AS*EFV202 To 2IAS*PT232 off ADS Accum.

2IAS*EFV203 To 2IAS*PT235 off ADS 2IAS*EFV204 Accum.

To 21AS*PT234 off ADS Accum.

2IAS*EFV205 To 2IAS*PT233 off ADS Accum.

2IAS*EFV206 To 2IAS*PT236 off ADS Accum.

2RHS*EFV 5,6 To 2RHS*PDT18B 2RHS*EFV7 To 2RHS*PDT18A 2MSS*EFV 1A,B,C,D To Flow Elements 2MSS*EFV 2A,B,C,D A,B,C,D Steamlines To Flow Elements A,B,C,D Steamlines 2MSS*EFV 3A,B,C,D To Flow Elements A,B,C,D 2MSS*EFV 4A,B,C,D Steamlines To Flow Elements A,B,C,D Steamlines 2RCS*EFV44 A,B To 2RCS*PT 84 A/E 2RCS*EFV45 A,B To 2RCS*FT 7A/B, FT 9 A/B 2RCS*EFV46 A,B To 2RCS*FT 7A/B, FT 9 A/B 2RCS*EFV47 A,B To 2RCS*FT 6A/B, FT 8 A/B 2RCS*EFV48 A,B To 2RCS*FT 6A/B FT 8 A/B 2RCS*EFV52 A,B To 2RCS*PDT 15 A/

2RCS*EFV53 A,B To 2RCS*PDT 15 A B 2RCS*EFV62 A,B To 2RCS*PT44 A/B B 2RCS*EFV63 A,B To 2RCS*PT42 A/B Page 18 NIP-DES-04 Rev 2'

C' ( (

ATTACHMENT 5: UNIT 2 PRIMARY CONTAINMENT ISOLATION VALVES v I 11 Page 11 of .-

ISOLATION VALVE FUNCTION I VALVE NO. VALVE ISOLATION MA XIM 1UM n 1 bKUUP SIGNAL (a) TIME (SECONDSi)p)

.WCS*EFV221 To 2WCS-FT 134 2WCS*EFV222 To 2WCS*FT67X, PDS 115 2WCS*EFV223 To 2WCS*FT67Y 2WCS*EFV224 To 2WCS*FT67Y 2WCS*EFV300 To 2WCS*FT67X, PDS 115 2CSH*EFV1 To 2CSH*LT123, LT124 2CSH*EFV2 To 2CSH*LT123 LT124 2CSH*EFV3 To 2CSH*PDTIO4 2CSL*EFV1 To 2CSL*PDT132 and 2RHS*PDT18A Page 19 NIP-DES-04 Rev 24

ATTACHMENT 5: UNIT 2 PRIMARY CONTAINMENT ISOLATION VALVES Page 12 of 13 Table Notations

Isolates on injection signal, not primary containment isolation signal.

(a) See Technical Specification 3.3.2, Table 3.3.2-4, for operated by iso ation signal(s). valve groups (b) Deleted (c) These valves are the RHR heat exchangers vent lines isolation The vent line connects to the RHR safety relief valves valves.

header before it penetrates the primary containment. (SRVs) discharge indicators for these valves are provided in the ControlThe position manual isolation. Room for remote (d) Type C leakage tests not required.

(e) The associated instrument lines shall not be isolated testing. Type C testing is not required. These valvesduring Type A in accordance with Tech. Spec. Surveillance Requirement shall be tested 4.6.3.4.

(f) These valves are check valves located in the vacuum RHR SRVs discharge headers. the SRV discharge header breaker lines for pool water and therefore has no containment isolation terminates under those on lines feeding into it. valves other than (g) 2SLS*MOV5A and B are globe stop check valves. These reverse flow. The mot or operator is provided to remote valves close upon the valve from the Control Room. manually close (h) These valves are testable check valves. They The air operator on each valve is provided onlyclose upon reverse flow.

for periodic testing of the valve. These valves can only be tested against a zero d/p.

(i) Valves are maintained closed. The FPW lines are Type C tested. capped. Valves are (j) Not primary containment isolation valves. These valves isolation signal to provide integrity of "A" and "B" close on an LPCI loops.

(k) Valves close on a SCRAM signal; not part of primary containment isolation system but are included here for Type C testing Specification 3.6.1.2. These valves are not required per Technical this specification but are required to be OPERABLE to be OPERABLE per Specification 3.1.3.1. per Technical (R) Not subject to Type A or Type C leak test because under constant 1800 psig pressure and the possible ofdetrimental constant monitoring of shutdown. effects Page 20 NIP-DES-04 Rev 24

ATTACHMENT 5: UNIT 2 PRIMARY CONTAINMENT ISOLATION VALVES Page 13 of 13 Table Notations (Cont)

(m) These valves are leak tested once every two years in compliance with ASME Sec. XI test frequency requirements.

Criteria is 10 gpm per valve for 2RHS*MOV142The Leakage Acceptance Engineering Calc. Nos. H21C7038-01C and MOV149 (Ref.

and A10.1-E-130, and SE No.95-077, Rev. 0).

(n) These valves are Type C tested and may be tested in the reverse direction.

(o) Isolation barrier remains waterfilled tested with water in accordance with post-LOCA. Isolation valve is Technical Specification 4.6.1.2.3.

(p) The maximum isolation times for valves listed in this procedure primary are containment automatic isolation the accident analysis as described either the analytical times used in applying margins to the vendor test in the USAR; or times derived by industry codes and standards or the data obtained in accordance with analytical automatic primary containmentGL 89-10 calculated time. For non-isolation time is derived as follows: isolation valves, the maximum

1. Valves with full stroke times less maximum isolation time approximatelythan or equal to 10 seconds, closure time or the GL 89-10 calculated equals the vendor tested time multiplied by 2.0.

2. Valves with full stroke times greater isolation time approximately equals than 10 seconds, maximum time or the GL 89-10 calculated time the vendor tested closure multiplied by 1.5.

3. Valve closing times do not include response time. isolation instrumentation (q) These valves are leak tested and the seats. Reference UFSAR Table may be tested by pressurizing between 6.2-65.

(r) Relief Valves are Type C tested as part of 2RHS*MOV15A,B assembly.

Page 21 NIP-DES-04 Rev 24

CONTAINMEN- SYSTEMS PRIMARY CONTAINMENT PRIMARY CONTAINMENT LEAKAGE RVEILANT REIREMENTS 4.6.1.2.1 The primary containment leakage rates conformance with the criteria specified shall in the 10 CPR 50beAppendix demonstrated at test schedules J Testing Program Plan and described in Section 6.S.4.f. as in 4.6.1.2.2 Main steam line isolation valves and 3.6.1.2-1 shall be leak the tested in accordance with remainder of the valves specified in Table Plan as described in Section the 10 CFR 50 Appendix 6.8.4.f at a test pressure J Testing Program demonstrate that each of at-least 40 psig with valve satisfies the leakage air or nitrogen to limits specified in Table 3.6.1.2-1.

4.6.1.2.3 Containment isolation valves in hydrostatically primary containment shall tested lines which penetrate be leak tested in accordance the Program Plan as described with the 10 CFR 50 Appendix in Section 6.8.4.f at a J Testing test pressure of at least 1.10 Pa, 43.73 psig.

4.6.1.2.4 The provisions of Specification 4.0.2 are 4.6.1.2.1, 4.6.1.2.2,. and not applicable to Surveillance 4.6.1.2.3. Requirements NINE MILE POINT - UNIT 2 3/4 6-4

'Amendment No. ii, 4,7

ALLOWABLE LEAK RATES TfROUCH VALVES IN POTENTIAL BYPASS LEAKAGE PATHS PER VALVE I LINE DESCRIPTION TERMINATION LEAK RATE, VALVE MARK NO REGION SCFH 4 Main Steam Lines 2MSS*AOV6A, B, C, 0 Turbine Bldg. 24.0 2MSS*AOV7A, B. C, D Main Steam Drain Line (Inboard) 2MSS*MOV111, 112 Turbine Bldg. 1.875 Main Steam Drain Line 2MSS*MOV208 Turbine Bldg.

(Outboard) 0.625 -

4 Postaccident Sampling Lines 2CMS*SOV77A, B Radwaste 2CMS*SOV74A, 0.2344 2 CMS*SOV75A, B Tunnel B

2CMS*SOV76A, B Drywell Equipment Drain Line 2DER*MOV1 19 Radwaste 2DER*MOV1 20 1.25 Tunnel Drywell Equipment Vent Line 2DER*MOV1 30 Radwaste 2DER*MOV1 31 0.625 Tunnel Drywell Floor Drain Line 2DFR*MOV1 20 Radwaste 2DFR*MOV121 1.875 Tunnel Drywell Floor Vent Line 2DFR*MOV139 Radwaste 2DFR*MOV1 40 0.9375 Tunnel RWCU Line 2WCS*MOV102 Turbine Bldg.

2WCS*MOV1 12 2.5 Feedwater Line 2 FWS*AOV23A Turbine Bldg. 12.0 2FWS*V12A 2FWS*AOV23B 2FWS*V12B CPS Supply Line to Drywell 2CPS*AOV104 Standby Gas 4.38 2CPS*AOV1 06 Trtmt. Area CPS Supply Line to Drywell 2CPS*SOV120 Standby Gas 2CPS*SOV122 0.625 Trtmt. Area CPS Supply Line to Supp.

2CPS*AOV105 Standby Gas Chamber 2CPS*AOV107 3.75 Trtmt. Area CPS Supply Line to Supp. 2CPS*SOV119 Chamber Standby Gas 0.625 2CPS*SOV121 Trtmt. Area NINE MILE POINT - UNIT 2 3J4 6-6 Amendment No. 6t .

Examination Level Administrative Topic A.3 Subject

Description:

Radiation Monitoring Question Number: 1_

RM10%

-. 1" I- II - RM R Q3 During an ATWS, an auxiliary operator must be dispatched to the HCUs to vent CRDM overpiston areas. No Emergency Action Level classifications have been made. What actions must be taken to assure ALARA requirements are met?

7Answe_ j _ _~ = E~&

If available, RP Tech continuously monitors work

RWP, Radiation Survey Log sheets, RWP sign-in logs, documentation is processed.

Post-job ALARA Job review.

Need for generation of a DER is evaluated.

Technic-al 6,Reft,~ies) it=

GAP-RPP-02, Rev. 05, Section 3.2.1 N2-EOP-6, Section 12.0 S-RAP-ALA-0102, Section 3.5.1 NIP-ECA-01, Section 1.1.1.f KI A#:A I mOrtanc X 12.3.2 12.9

NIAGARA-MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION GENERATION ADMINISTRATIVE PROCEDURE GAP-RPP-02 REVISION 05 RADIATION WORK PERMIT 1lTECHNICAL SPECIFICATION REQUIRED Approved by:

R. G. Smith Plant Manager - r \,V Date Approved by: 2-at- A?

N. C. Paleologos Plant RU'ger - Unit 2 Date THIS IS A FULL REVISION Effective Date: 02/11/99

3. 1.1 (Cont) conditions) from the RWP requirement with RP supervision approval. There are three types of RWPs:

a. General RWP - For personnel access to RCA for general tours, supervisory oversight, inspections, or RP approved work in areas not posted as a Radiation Area or Contaminated Area.

b. Standing RWP - For routine or repetitive work functions.

c. Specific RWP - For performance of a job in locations where the work may affect or change the radiological conditions and any work, or any other condition beyond the scope of a Standing RWP, as determined by RP.

3.1.2 Depending on the planned scope of work, qualifications of personnel performing the work, and radiological conditions of the work area, RP may specify the use of a General, Standing or Specific RWP.

3.2 Emergency Response Radiation Work Permit 3.2.1 To prevent delays during an emergency, RWP processing may be modified as directed by the Station Shift Supervisor (SSS) or Supervisor RP Operations, or designee, provided:

a. Required work is continuously monitored by RP technicians.

b. At the conclusion of the emergency condition, a RWP, Radiation Survey Log Sheet(s), RWP Sign-In Logs, and other documentation are initiated and processed.

c. A post-job ALARA review is issued per GAP-ALA-01 to evaluate actions taken and resultant personnel exposure.

d. Generation of a DER to document the event is considered.

3.3 Use of General Radiation Work Permit 3.3.1 Personnel shall adhere to the following limitations for General RWPs:

a. Access to posted Radiation Areas is permitted for passage and short duration inspection/observation activities only.

Loitering is prohibited.

b. Entry into areas requiring a specific RWP is prohibited without signing or logging in on an appropriate specific RWP.

c. The daily exposure guide specified on the RWP shall not be exceeded.

Page 2 GAP-RPP-02 Rev 05

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION UNIT 2 EMERGENCY OPERATING PROCEDURE N2-EOP-6 REVISION 05 NMP2 EOP SUPPORT PROCEDURE ITECHNICAL SPECIFICATION REQUIREDl Approved by:

D. P. Bosnic 12 /2/I?8 Manager Operations - Unit 2 Date THIS IS A FULL REVISION Effective Date: 12/31/1998 PERIODIC REVIEW DUE DATE DECEMBER, 22000

C. PRECAUTIONS AND LIMITATIONS (Cont) 4.0 When using the Attachments, the operator shall opposite each step as it is completed. place a "check" 5.0 Changes to these attachments should not be numbering) except in an emergency, without made (including step Coordinator and Manager-Unit 2 Operations or review by the EOP Operations, as required per N2-ODP-PRO-0301. General Supervisor-Unit 2 6.0 If a procedure step can not be performed as shall be notified immediately. written, the EOP Director 7.0 The Restoration section of an Attachment shall directed by the SSS/EOP Director. be performed only when 8.0 All tools, materials, keys, etc. that are required Attachment will listed in Section 2 of each to perform the attachment.

9.0 An i notation in the left margin adjacent indicates that a tool or material is requiredto a step number or note for performance.

10.0 Common tools (screwdrivers, tape etc.)

procedure step. Only special tools or will not be specified in the situations result will have a particular tool specified where confusion may in a step or note.

11.0 Independent verification is required in the restoring temporary alterations or returning Restoration section when to normal status. This verification may be permanent plant equipment conditions still exist, and it is imperative delayed if emergency completed immediately. The EOP Director/SSS that restoration be delay independent verification. permission is required to 12.0 During plant conditions which require implementation procedures, environmental conditions may be of these (temperature, radiation, water levels). potentially extreme In many cases this will require coordination Where access is required in areas of elevated and support from the OSC.

dictates protective equipment be used and temperatures, prudency precautions times and activity levels should be minimized. taken. Stay Consultation with the Safety Department Or Site Hygienist is recommended when possible. Above 1350 F personnel significantly hampered. access may be When it is anticipated or known that radiation radiation protection assistance should be levels are elevated, require utilization of emergency exposure sought. Some evolutions may dosimetry in accordance with EPP-15. guidelines or emergency Page 3 N2-EOP-6 Rev 05

NIAGARA.MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION RADIATION PROTECTION ADMINISTRATIVE PROCEDURE

-~ S-RAP-ALA-0102 REVISION 04 ALARA REVIEWS Approved by:

V. Schuman /YKl, Manage on Protection - Unit 1 Date Approved by:

D. W. Barcomb /-

/5- 99 M ger Radiation Protection - Unit 2 Date THIS IS A FULL REVISION Effective Date: .02/02/99

3.5 Post-Job ALARA Review 3.5.1 Post job ALARA reviews should be conducted:

a. On jobs where actual exposure is greater than 5 man-rem when a pre job review has been waived for an emergency or condition.

b. When determined necessary by the job supervisor or supervision. RP 3.5.2 Post-job reviews should consist of the following:

a. A comparison of the estimated and actual man-hours man-rem for the job. and

b. Identification of the successes and problems encountered during the performance of the job.

c. Identification of improvements which can be incorporated into future work.

d. An evaluation of the workers and RP personnel comments the job using the ALARA Post-Job Questionnaire, Attachmenton 9, or obtained during personnel interviews.

e. An evaluation of airborne radioactivity/internal dose.

3.5.3 The completed post-job review should be submitted for approval based on the man-rem for the job. Suggested review and is listed in Attachment 1. criteria 3.5.4 The Post-job review should be maintained in the job history files.

3.6 Revising ALARA Reviews 3.6.1 ALARA reviews should be revised when new tasks are added RWP or ALARA requirements have changed. to the NOTE: The Unit ALARA Lead/Designee will determine when a change(s) to a pre-job ALARA review requires:

- A new rev number to be assigned

- Rerouting for signature approvals Page 5 S-RAP-ALA-0102 Rev 04

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION NUCLEAR INTERFACE PROCEDURE NIP-ECA-O1 REVISION 16 DEVIATIONIEYENT REPORT

.TECHNICAL SPECIFICATION REQUIRED Approved by:

iration D'ate THIS PROCEDURE SUPERSEDES QAP-ECA-15.02 AND QAP-ECA-16.20 Effective Date: 04/30/1 999

1.0 PURPOSE To prescribe the method for processing Deviation/Event for the identification, documentation, notification, Reports (DERs) correction, prevention, trending, and reporting evaluation, activities, and concerns that have the potential of conditions, events, and reliable operation of the Nuclear Stations for affecting the safe at Nine Mile Point.

1. 1 APDlicabilitv (Cl)

This procedure applies to Nuclear SBU personnel conditions, or activities adverse to quality thataddressing events, Point including: may impact Nine Mile 1.1.1 Conditions or abnormal occurrences having an adverse potentially adverse effect on activities important or safety, industrial safety, plant reliability, or to nuclear performance, including, but not limited to: human

a. Hardware failures other than normal wear and tear

b. Hardware or component malfunctions resulting manufacturing deviations or defects from design or

c. Out-of-calibration measuring and test equipment have adversely or potentially adversely affected known to equipment other plant

d. Non-compliances having nuclear safety significance

e. Adverse personnel performance such as failure to follow procedures or violations of personnel safety rules practices or

f. Radiation Protection deviations

g. Preventive maintenance activities not completed date or deferred date before late

h. Recurring corrective maintenance/hardware structures systems or components exceeding failures, their or criteria described in the Maintenance Rule Program. performance

i. Human performance problems/issues

j. Inadequate corrective actions

k. Test failures R. Deviations from design document requirements (other than normal wear and tear) including station configuration discrepancies, such as USAR discrepancies Page 1 NIP-ECA-O1 Rev 16

Ckdr A n outlminb Conss; Refer e 00n7---e OperatingTsNubrCt""et2 Examination Level Ca "" es Administrative Topic A.3 Subject

Description:

Radiation Monitoring Question Number: 2 Question: -

While at 100% power, a failure of the Digital Control System to the Digital Radiation Monitoring System (DRMS) results communication link in the loss of all control room annunciation associated with DRMS. NO liquid radwaste discharge is in progress.

What are the Technical Specification restrictions on plant operation?

With their control room alarm function lost, the following radiation monitors are inoperable:

(1) 2CWS-CAB157, T.S. 3.3.7.9-1, Function 2.c, Action 130 (2) 2LWS-CAB206, T.S. 3.3.3.9-1, Function 1, Action 128 (3) 20FG-CAB13A/123B, T.S. 3.3.7.10-1, Function 1.a, Action 135 Cooling tower blowdown line effluent:

. Since a release is inprogress, the release may continue provided that grab samples are collected and analyzed at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

Liquid radwaste effluent:

. Since no release is in progress, prohibit any release via this pathway until the monitor is restored to OPERABLE.

Offgas system effluent:

Since a releaseis in proress, the release may continue provided grab samples are taken at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and the samples are analyzed for gross activity within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

ion Outline C ross Reference Cat "A"Test 2 SRO A.3 Radiation Monitorin 2

lTechnical Referencess N2-OP-79, Section H.2 T.S. 3.3.7.9-1, F2.c, Action 130 T.S. 3.3.3.9-1, Fl, Action 128 T.S. 3.3.7.10-1, Fl.a, Action 135

NIAGARA MOHAWK POWER CORPORATION NINE MILE POINT NUCLEAR STATION UNIT 2 OPERATING PROCEDURE N2-OP-79 REVISION 07 RADIATION MONITORING TECHNICAL SPECIFICATION REQUIRED Approved by:

R. G. Smith / / 2 Manager Operations - Unit 2 Date

';I THIS IS A FULL REVISION PERIODIC REVIEW, 03/05/99, NO CHANGE Effective Date: 03/20/97 PERIODIC REVIEW DUE DATE MARCH 2001

H. OFF-NORMAL PROCEDURE 1.0 DRMS ALARM RESPONSE NOTE: Use of the DRMS Console SET ALARM OFF pushbutton silence existing console alarms and any other consolewill until the ACK OLDEST ALARM pushbutton is depressed, alarms could result in missed alarms and unknown degradation this plant conditions. of 1.1 DRMS console alarms are to be acknowledged by use OLDEST ALARM ACK button only. of the 1.2 DRMS alarm response is the responsibility of the Control Room Operator. All unexpected alarms will be acknowledged from the Control Room.

1.3 Day to day operation AND maintenance of the system responsibility of the Radiation Protection Department. is the Routine expected alarms may be acknowledged by Radiation Protection Technicians.

2.0 Loss of DCS/Loss of Communication with the DCS NOTES: 1. If the Digital Control System communication link is lost, there will be no control room annunciation associated with DRMS. Safety related monitors (1-E monitors), equipment failure and alarm status will only be available at 2CEC*PNL880A, B, C and D or each individual monitors' microprocessor. All at isolation functions will occur independent of DCS trip/

communication.

1-E Monitors: 2CMS*RE1OA 2HVC*RE18A 2SWP*RE146A 2CMS*RE1OB 2HVC*RE18B 2SWP*RE146B 2HVR*RE14A 2HVC*RE18C 2RMS*RE1A 2HVR*RE14B 2HVC*RE18D 2RMS*RE1B 2HVR*RE32A 2SWP*RE23A 2RMS*RE1C 2HVR*RE32B 2SWP*RE23B 2RMS*RE1D

2. The following radiation monitors are considered inoperable due to loss of Control Room alarm functions:

2CWS-CAB157 - Technical Specification 3.3.7..9-1 2.c ACTION 130 2LWS-CAB206 - Technical Specification 3.3.7..9-1 1.

ACTION 128 20FG-CAB13A/13B- Technical Specification 3.3.7.10-1 1.a ACTION 135 Page 35 N2-OP-79 Rev 07

INSTRUMENTATION MONITORING INSTRUMENTATION RADIOACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION LIMITING CONDITIONS FOR OPERATION 3.3.7.9 The radioactive liquid effluent monitoring instrumentation shown in Table 3.3.7.9-1 shall be OPERABLE with their Alarm/Trip channels to ensure that the limits of Specification 3.11.1.1 are Setpoints set Alarm/Trip Setpoints of these channels shall be determined not exceeded. The accordance with the methodology and parameters in the OFFSITE and adjusted in MANUAL (ODCM). DOSE CALCULATION APPLICABILITY: During releases via this pathway.

ACTION:

a. With a radioactive liquid effluent monitoring instrumentation Alarm/Trip Setpoint less conservative than required by channel the cation, immediately suspend the release of radioactive liquid above specifi-monitored by the affected channel, or declare the channel effluents change the setpoint so it is acceptably conservative. inoperable, or

b. With the number of channels OPERABLE less than the Minimum ABLE requirement, take the ACTION shown in Table Channels OPER-3.3.7.9-1. Restore the instruments to OPERABLE status within 30 days and, if unsuccessful, explain in the next Semiannual Radioactive Effluent Release the inoperability was not corrected in a timely manner. Report why

c. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.3.7.9 Each radioactive liquid effluent monitoring instrumentation shall be demonstrated OPERABLE by performance of the CHANNEL channel CHECK, CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST at CHECK, SOURCE in Table 4.3.7.9-1. the frequencies shown NINE MILE POINT - UNIT 2 3/4 3-92

TABLE 3.3.7.9-1 RADIOACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION MINIMUM INSTRUMENT CHANNELS OPERABLE ACTION

1. Radioactivity Monitors Providing Alarm and Automatic Termination of Release Liquid Radwaste Effluent Line 1 128

2. Radioactivity Monitors Providing Alarm But Not Providing Automatic Termination of Release

a. Service Water Effluent Line A 1 130

b. Service Water Effluent Line B 1 130

c. Cooling Tower Blowdown Line 1 130

3. Flow Rate Measurement Devices

a. Liquid Radwaste Effluent Line 1 131

b. Service Water Effluent Line A 1 131

c. Service Water Effluent Line B 1 131

d. Cooling Tower Blowdown Line 1 131

4. Tank Level Indicating Devices*

1 132-

Tanks included in this specification are those outdoor tanks that surrounded by liners, dikes, or walls capable of holding the tank are not contents do not have tank overflows and surrounding area drains connected to and radwaste treatment system, such as temporary tanks. the liquid NINE MILE POINT - UNIT 2 3/4 3-93

TABLE 3.3.7.9-1 (Continued)

RADIOACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION TABLE NOTATIONS ACTION 128 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, effluent. releases may continue provided that before initiating a release:

a. At least two independent samples are analyzed in accordance with Specification 4.11.1.1.1, and

b. At least two technically qualified members of the facility staff independently verify the release rate calculations and discharge line valving; Otherwise, suspend release of radioactive effluents via this pathway.

ACTION 129 - Not used.

ACTION 130 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue provided that, at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , grab samples are collected and analyzed for radioac-tivity at a limit of detection of at least 5 x 10-7 microcuries/ml.

ACTION 131 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue, provided the flow rate is estimated at least once per 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months during actual releases. Pump per-formance curves generated in place may be used to estimate flow.

ACTION 132 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, Tiquid additions to this tank may continue provided the tank liquid level is estimated during all liquid additions to the tank.

NINE MILE POINT - UNIT 2 3/4 3-94

( ( C TABLE 413.7.9-1 z

z RADIOACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS M CHANNEL r-m CHANNEL CHANNEL SOURCE CHANNEL FUNCTIONAL

-3 INSTRUMENT CHECK CHECK CALIBRATION TEST

'-4 1. Radioactivity Monitors Providing Alarm

-A and Automatic Termination of Release Liquid Radwaste Effluent Line D P R(c) M(a)(b)

2. Radioactivity Monitors Providing Alarm But Not Providing Automatic Termination of Release

a. Service Water Effluent Line A D M R(c) SA(b)

b. Service Water Effluent Line B D M R(c) SA(b) 4.0

c. Cooling Tower Blowdown Line D M R(c) SA(b)

D

3. Flow Rate Measurement Devices

a. Liquid Radwaste Effluent Line D(d) NA R Q

b. Service Water Effluent Line A D(d) NA R Q

c. Service Water Effluent Line B D(d) NA R Q

d. Cooling Tower Blowdown Line D(d) NA R Q

4. Tank Level Indicating Devices* D** NA R Q

Tanks included in this specification are those outdoor tanks that are not surrounded by liners, dikes, or wall capable of holding the tank contents and do not have tank overflows and surrounding area drains connected to the liquid radwaste treatment system, such as temporary tanks.

- During liquid additions to the tank.

TABLE 4.3.7.9-1 (Continued)

RADIOACTIVE LIOUID EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS TABLE NOTATIONS (a) The CHANNEL FUNCTIONAL TEST shall also demonstrate that automatic isolation of this pathway and control room alarm annunciation occurs if the instrument indicates measured levels above the Alarm/Trip Setpoint.

(b) The CHANNEL FUNCTIONAL TEST shall also demonstrate that control room alarm annunciation occurs if any of the following conditions exists:

(1) Instrument indicates measured levels above the Alarm Setpoint, or (2) Circuit failure, or (3) Instrument indicates a downscale failure, or (4) Instrument controls not set in operate mode.

(c) The initial CHANNEL CALIBRATION shall be performed using one or more of the reference standards certified by the National Bureau of Standards, standards that are traceable to the National Bureau of Standards, or using actual samples of liquid effluents that have been analyzed on a system that has been calibrated with National Bureau of Standards able sources. These standards shall permit calibrating the system trace-over its intended range of energy and measurement. For subsequent CHANNEL CALIBRATION, sources that have been related to the initial calibration may be used.

(d) CHANNEL CHECK shall consist of verifying indication of flow during of release. CHANNEL CHECK shall be made at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months periods days on which continuous, periodic, or batch releases are made. on NINE MILE POINT - UNIT 2 3/4 3-96

INSTRUMENTATION MONITORING INSTRUMENTATION RADIOACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION LIMITING CONDITIONS FOR OPERATION 3.3.7.10 The radioactive gaseous effluent monitoring instrumentation channels shown in Table 3.3.7.10-1 shall be OPERABLE with their Alarm/Trip Setpoints set to ensure that the limits of Specification 3.11.2.1 are not exceeded. The Alarm/Trip Setpoints of these channels shall be determined and adjusted in accordance with the methodology and parameters in the ODCM.

APPLICABILITY: As shown in Table 3.3.7.10-1.

ACTION:

a. With a radioactive gaseous effluent monitoring instrumentation channel Alarm/Trip Setpoint less conservative than required by the above spec-ification, immediately suspend the release of radioactive gaseous ef-fluents monitored by the affected channel, or declare the channel in-operable, or change the setpoint so it is acceptably conservative.

b. With the number of channels OPERABLE less than the Minimum Channels OPERABLE requirement, take the ACTION shown in Table 3.3.7.10-1. Restore the instruments to OPERABLE status within 30 days and, if unsuccessful, explain in the next Semiannual Radioactive Effluent Release Report why the inoperability was not corrected in a timely manner.

c. The provisions of Specifications 3.0.3 and 3.0.4 are not applicable.

SURVEILLANCE REQUIREMENTS 4.3.7.10 Each radioactive gaseous effluent monitoring instrumentation channel shall be demonstrated OPERABLE by performance of the CHANNEL CHECK, SOURCE CHECK, CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST operations at the fre-quencies shown in Table 4.3.7.10-1.

NINE MILE POINT - UNIT 2 3/4 3-97

TABLE 3.3.7. 7-l RADIOACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION MINIMUM INSTRUMENT CHANNELS APPLICA-OPERABLE BILITY ACTION

1. Offgas System

a. Noble Gas Activity Monitor -

Providing Alarm and Automatic Termination of Release 2 135

b. System Flow-Rate Measuring Device 1

136

c. Sample Flow-Rate Measuring Device 2

136

2. Offgas System Explosive Gas Monitoring System**

a. Hydrogen Monitor Train A (Instrument 20FG-AT-16A or

137 20FG-AT-115)

b. Hydrogen Monitor Train B (Instrument 20FG-AT-168 or

137 2OFG-AT-l 15)

3. Radwaste/Reactor Building Vent Effluent System

a. Noble Gas Activity Monitort tit 139

b. Iodine Sampler tt 138

c. Particulate Sampler tt 138

d. Flow-Rate Monitor tt 136

e. Sample Flow-Rate Monitor

t 136

4. Main Stack Effluent

a. Noble Gas Activity Monitort 1 at 139

b. Iodine Sampler I -f-i 138

c. Particulate Sampler I tt 138

d. Flow-Rate Monitor It 1 136

e. Sample Flow-Rate Monitor tt I 136 NINE MILE POINT - UNIT 2 3/5 3-98 Amendment No. 30

TABLE 3.3.7.10-1 (Continued)

RADIOACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION TABLE NOTATIONS During offgas system operation.

- Only one train required to be in operation.

t Includes high range noble gas monitoring capability.

tt At all times.

ACTIONS ACTION 135 a. With the number of OPERABLE channels one less than required the Minimum Channels OPERABLE by this pathway may continue provided requirement, effluent releases via placed in the tripped condition the inoperable channel is within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b. With the number of OPERABLE channels two less than required the Minimum Channels OPERABLE this pathway may continue provided requirement, effluent releases by via least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and these grab samples are taken at activity within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . samples are analyzed for gross ACTION 136 - With the number of channels OPERABLE Minimum Channels OPERABLE requirement,less than required by the pathway may continue provided effluent releases via the flow rate for the inoperablethis channel(s) Is estimated at least -

once per 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

ACTION 137 - With the number of channels OPERABLE less than required Minimum Channels OPERABLE requirement, by the may continue provided grab samples operation of the offgas hours and analyzed within the are collected at least once system following 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . per 4 ACTION 138 - With the number of channels OPERABLE Minimum Channels OPERABLE requirement,less than required by the pathway may continue provided effluent releases via this samples are continuously collected starting within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months of discovery, equipment as required in Table using auxiliary sampling 4.11.2-1.

ACTION 139 - a. With the number of channels OPERABLE Minimum Channels OPERABLE requirement,less than required by the pathway may continue provided effluent releases via this once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and these samplesgrab samples are taken at least activity within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for are analyzed for gross a radioactivity limit of detection of at least 1 x 10-4 microcurie/ml.

b. Restore the inoperable channel(s) hours or in lieu of another report to OPERABLE status within 72 6.9.1, prepare and submit a Special required by Specification pursuant to Specification 6.9.2 Report to the Commission event outlining the action taken, within 14 days following the and the schedule for restoring the cause of the inoperability the system to OPERABLE status.

NINE MILE POINT - UNIT 2 3/4 3-99 3Aendment No. 30

( I tABLE TABLE /.IO-1

~( 1. 10-(. kC RADIOACTIVE GASEOUS EFFLUENT MONITORING INSTRUMEMTATION SURVEILLANCE REQUIREMENTS

__ CHANNFI L&

I n )DES IN NHICH INSTRUMENT L"ANNtL SOURCE CHANNEL FUNCTIONAL CHECK St IRVEILLANCE CHECK CALIBRATION TEST RI EQUIRED

1. Offgas System

a. Noble Gas Activity Monitor -

Providing Alarm and Automatic D NA R(ae) M(b, c) A A

Termination of Release

b. System Flow-Rate Measuring Device D NA R Q

c. Sample Flow-Rate Measuring Device NA R Q AA

2. Offgas System Explosive Gas Monitoring System

a. Hydrogen Monitor Train A D NA Q(d) M

b. Hydrogen Monitor Train B D NA Q(d) M AA

3. Radwaste/Reactor Building Vent Effluent System

a. Noble Gas Activity Monitor t D M R(a) Q(c) A

b. Iodine Sampler D NA NA NA I?

rt

c. Particulate Sampler

d. Flow-Rate Monitor 0

NA NA NA R

NA At A

Q A

e. Sample Flow-Rate Monitor 0 D NA R Q A I

a\ TABLE 4.3.).1 (Continued)

RADIOACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS (

CHANNEL M )DES IN WHICH CHANNEL SOURCE CHANNEL FUNCTIONAL INSTRUMENT CHECK StJRVEILLANCE CHECK CA.LIBRATION TEST REIQUIRED

14. Main Stack Effluent

a. Noble Gas Activity Monitor t D M R(a) Q(c) A4

b. Iodine Sampler NA NA NA A

c. Particulate Sampler NA NA NA A.

d. Flow-Rate Monitor 0 NA R Q

e. Sample Flow-Rate Monitor 0 NA R Q I

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5.0 REFERENCES

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