ML20206H857

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Forwards Supplemental Responses to NRC Issues on Facility Dcrdr Summary Rept,Per Suppl 1 to NUREG-0737,Generic Ltr 82-33
ML20206H857
Person / Time
Site: Prairie Island  Xcel Energy icon.png
Issue date: 06/12/1986
From: Musolf D
NORTHERN STATES POWER CO.
To:
Office of Nuclear Reactor Regulation
Shared Package
ML20206H861 List:
References
RTR-NUREG-0700, RTR-NUREG-0737, RTR-NUREG-700, RTR-NUREG-737 GL-82-33, NUDOCS 8606260335
Download: ML20206H857 (37)
v • d • e


Text

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W Northern States Power Company 414 Nicollet Mall Minneapolis. Minnesota 55401 Telephone (612) 330-5500 June 12, 1986 Director Office of Nuclear Reactor Regulation US Nuclear Regulatory Commission Washington, DC 20555 PRAIRIE ISLAND NUCLEAR GENERATING PLANT DOCKET NOS. 50-282 LICENSE NOS. DPR-42 50-306 DPR-60 Supplement I to NUREG-0737. Generic Letter 82-33 Supplemental Information In Response to Issues Raised By the NRC Staff on the Prairie Island DCRDR Summary Report The purpose of this letter is to provide, for the informa-tion of the NRC Staff, supplemental responses to questions raised by the NRC Staff during the review of the Prairie island Detailed Control Room Design Review (DCRDR) Summary Report.

The attachment to this letter consists of three items:

Appendix A - This contains our response to the draft Technical Evaluation Report dated February, 1986 and a copy of the draft report keyed to our response.

Appendix B'- This contains our response to a revised draft of the Technical Evaluation Report Conclusion and Recommendations Section and roposed Meeting Agenda transmitted June, 1986.

Appendix C - This contains copies of the documents requested by the NRC Staff.

Because of the bulk and specialized nature of this material, five copies are being submitted. Please contact us if you have any additional questions related to the information we have provided. I

& c:' _O W w s David Musolf Manager Nuclear Support ervices l

c: NRR Project Manager, NRC Resident Inspector, NRC Regional Administrator, Region III, NRC (w/o attachment)

G Charnoff (w/o attachment) 0)

Attachment 8606260335 060612 PDR ADOCK 05000282 p PDR ,

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APPENDIX A RESPONSE TO VIEWS RAISED BY THE STAFF IN THE DRAFT TECHNICAL EVALUATION REPORT '

DATED FEBRUARY 1986 1

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PINGP Comments on the Draft " Technical Evaluation of the Detailed Control Room Design Review for Northern States Power Company's Prairie Island Nuclear Generating Plant, Unit 1 and 2" Dated February 19, 1986 This response is formatted directly from the above Draft for eage of review.

The attached draft is annotated for ease of comparison.

(A) Page 2. 2nd Paragraph of Draft PINGP Response:

NUREG 0800 Page 18.1-A22 allows the utility to do implementation prior to the receipt of a NRC Safety Evaluation Report.  ;

(B) Page 7. 3rd Paragraph of Draft PINGP Response:

The NSP Operating Experience Assessment directive N1ACD 10.3 addresses  ;

the assessment of industry wide reports. The directive specifically 4 requires that the INPO Significant Operating Experience Reports, Signi-ficant Event Reports, and Significant By Others notifications are evaluated, NSP investigative reports for Reportable Events and Signi-ficant Operating Events SAWI 3.6.1 provides for investigating Human Factors Considerations and gives guidance for the investigation of Type and Probable Cause of Human Error.

(C) Page 10. 2nd and 3rd paragraphs of Draft PINGP Response:

During the course of the System Review and Task Analysis (SRTA) at Prairie Island Nuclear Generating Plant, plant-specific information and control characteristics were derived from background documentation of Revision 1 Westinghouse Owner's Group Emergency Response Guidelines (ERGS). These information and control characteristics form the basis of the Prairie Island Emergency Operating Procedures (EOPs) and are reflected in a record of information and control characteristics to tasks and subtasks. The following figures trace the record by infor-mation and control requirements for one example task from the E0Ps: 1 Check Steam Generator Levels.

i The figures are first listed and described in the order in which the data contained therein were developed. Figure 1 shows an example of background ERG materials from the Westinghouse Owner's Group Emergency j Response Guidelines--Background Volume-Low Pressure Version. These i contain the generic information and control requirements applicable to the two ERG steps.

Page 1 i

u J

f Figure 2 contains the example " Step Description Table" for Step 6--

Check SG Levels of the ERGS. The subsections of the " Step Description Tables" entitled ACTIONS, INSTRUMENTATION, and CONTROL / EQUIPMENT describe instrumentation and control characteristics and criteria necessary to accomplish the steps.

Figure 3 shows examples of the " Task Analysis Indications and Controls" worksheets. These were developed at Prairie Island by a Quadrex nuclear operations consultant. They contain a listing and description of the instrumentation required to meet the information and control requirements.

Figure 4 shows examples of the Prairie Island plant-specific " Element Tables" developed from the " Step Description Tables" and the " Task Analysis Indication: and Controls" worksheets. They list the instru-ment identification numbers of the required instrumentation and their criteria of measurement or control.

Figure 5 shows an example of a " Controls Requirements Table" derived from a series of " Element Tables," each containing a specific compo-nent. All the criteria required for operation of this control are listed. Figure 6 shows an example of an " Instrumentation Requirements Table." This is a counterpart of the controls table, listing all the criteria for using the display / indicator.

The figures above, in tne order in which the data were recorded, demonstrate the process by which the information and control needs from background documentation of Revision 1 of the ERG or from plant-specific information were applied to identify each instrument and control for implementing the emergency operating procedures. The documentation comprises a record of instruments and their character-istics which can be traced back to the associated information and control requirements. First, the particular instrument or control is identified in the appropriate " Control Requirements Table" (Figure

5) or " Instrumentation Requirements Table" (Figure 6), respectively.

These tables are indexed by power plant system and control board panel. Then, each of the E0P numbers listed under " Task Requirements" is consulted to obtain the " Element Table" corresponds to a " Step Description Table" (Figure 2) of the ERG materials, and associated generic reference plant description background materials (Figure 1).

Page 2 e _.

FIGURE 1

1. INTRODUCTION .

)

Guideline ES-0.1, REACTOR TRIP RESPONSE, provides the necessary instructions I to stabilize and control the plant following a reactor trip without a safety

, injection. It is entered only from E-0, REACTOR TRIP OR SAFETY INJECTION, step 4 when an SI is neither actuated nor required. Following the stabilization of the plant, ES-0.1 is exited to either a normal plant procedure for startup or cooldown, or to ES-0.2, NATURAL CIRCULATION COOLDOWN, if a natural circulation cooldown is required.

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2. DESCRIPTION A reactor trip is a command to shut down a reactor which is either critical or undergoing startup operation. The command is generated by either an automatic protective action initiated when certain setpoints for plant operating .

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parameters ~are exceeded or by manual initiation by the operator. The N_.9 generation of a protection demand is appropriately indicated at ,the annunciator panel. Several automatic actions aimed at ensuring that the core is shutdown and that there is effective decay heat removal follow the occurrence of a reactor trip.

Following a reactor trip from full power, the reactor coolant temperature is reduced from full power temperature to no-load temperature by automatic operation of the condenser steam dump system. If for any reason condenser steam dump capability cannot be obtained, the steam generator power operated  !. .

relief valves will automatically modulate. If these do not open, the steam h;}

generator code safety valves open to protect the secondary system and by that %y-.

means remove heat from the primary system. The cooldown to no-load shrinks _

the water in the RCS and pressurizer level should stabilize automatically at the no-load programmed level. The drop in level results in a reduction in RCS pressure from the nominal 2235 psig. RCS pressure can be expected to drop to about 2000 psig before starting to increase as a result of operation of the pressurizer heaters. For most reactor trips steam generator water level will remain above the top of the U-tubes although it may shrink out of the narrow range indication. Auxiliary feedwater pumps will start on low-low narrow range SG level to restore SG 1evel into the narrow range. Extensive subcooling of the reactor coolant at the core exit should exist. Forced flow in the RCS will be maintained unless for some reason the reactor coolant pumps (

have tripped, in which case flow will be by natural circulation.

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ES-0.1 ,a 2 LP-Rev. 1  :

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Thestation'electricalbusseswouldnormallybe$nergizedbyoffsitepower.

If for some reason a station " blackout" (loss of offsite power) occurs, the s diesel generators would automatically start and supply power to the blackout loads to stabilize:and control the plant. All critical surveillance, control,

-$ and safeguards ac6uation systems are continously powered from the plant's redundant batteries. All operating e}ements of the safety grade system ~(ECCS pumps, for example) would have power' available from the diesel' generators. A number of operating elements for "non-safety grade" systems and compo'nents may not be automatically powered by the diesel generators. These "non-safety-

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grade" components might include pressurizer heaters and instrument air -

1 compressors,,and should be intentionally repowered as soon as possible since the availability of these components facilitate plant control.

Guideline ES'0.1 deals w;th the. specific actions necessary to stabilize and

4. ,1 control the plant following a reactcv trip. _It also handles _ reactor l trips s.:;[:ya m

combined with either a station blackout or a total loss of forced reactor 973

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coolant flow.

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ES-0.1 ,/ 3 .LP-Rev. 1 0089V FIGUrLE 1 cont'. .

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3. RECOVERY / RESTORATION TECHNIQUE (

The objective of the recovery / restoration technique incorporated into guideline ES-0.1 is to stabilize and control the plant following a reactor trip without a safety injection in operation.

The following subsections provide a summary of the major categor.ies of opertor actions and the key utility decision points for Guideline ES-0.1, REACTOR TRIP RESPONSE.

3.1 Hioh Level Action Summary A high level summary of the actions performed in ES-0.1 is given on the folicwing page in the form of major action categories. These are discussed below in more detail. M 3b A=!

o Ensure the Primary System Stabilizes at No-load Conditions W .

The operator should verify that RCS temperature is reduced to no-load by  :

actuation of steam dump. Adequate shutdown margin is ensured by verifying that all control rods are fully inserted. If two or more rods fail to insert, the relative shutdown reactivity should be made up by baration until shutdown margin is equal to that required by the plant Technical Specification.

Pressurizer level and pressure are checked to verify they are responding as expected following a reactor trip.

o Ensure the Secondary System Stabilizes at No-load Conditions The operator should check the steam dump system and verify that a source of feedwater to the SGs is available. The operator should also control feedwater to maintain SG level. Steam generator level is restored in the narrow range and controlled at that point. i9 ES-0.1 - 4 LP-Rev. 1 0089V FIGURE 1 cont.

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MAJOR ACTION CATEGORIES IN ES-0.1 o Ensure the Primary System Stabilizes at No-load Conditions o Ensure the Secondary System Stabilizes at No-lo'ad Conditions o Ensure Necessary Components Have Power Available

'kh o Maintain / Establish Forced Circulation of-the RCS Y'i..

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. ' .TG o Maintain Plant in a Stable Co$dition 6

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ES-0.1 ii 5 LP-Rev. 1

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o Ensure Necessary Components Have power Available Offsite power should be checked and, if not available, the necessary loads are verified or energized by diesel generators.

o Maintain / Establish Forced Circulation of the RCS f.w -

Natural circulation is verified for the case when RCPs have tripped and one cannot be restarted.  ;

o Maintain Plant in a Stable Condition Once neutron flux decays low enough, the automatic reenergization of the source range detectors is verified. The plant is then maintained in a stable .

Ri condition until the course of action is determined by the operating staff. f 3.2 Key Utility Decision points W'

After the plant is stabilized following a reactor trip, the operating crew would have to determine the next course of action. , Generally, if no components necessary for power operation are out of service, the limiting-conditions for operation in the Technical Specifications are satisfied, and if the cause of the trip is identified and corrected, then a plant startup would be commenced. If a Technical Specification limiting condition for operation is violated and its action statement requires a cooldown, or a cooldown is necessary to repair non-safety grade components needed for operation, then a plant cooldown is commenced. If a cooldown is required, forced circulation of the RCS is always preferred over a natural circulation cooldown in order to .  :

eliminate any concerns about drawing voids in the system and/or incomplete boron mixing. Therefore, attempts should be made to start at least one reactor coolant pump prior to the cooldown, if one is not already running. A natural circulation cooldown should only be performed if absolutely necessary (e.g., if a Technical Specification is violated and requires a cooldown before hl an RCP can be started, a natural circulation cooldown should be performed).

ES-0.1 ' '

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STEP DESCRIPTION TABLE FOR ES-0.1 STEP 6 STEP: Check SG Levels PURPOSE: To ensure adequate feed flow or SG inventory for secondary heat y.,

sink .equirements BASIS:

The minimum feed flow requirement satisfies the feed flow requirement of the g Heat Sink Status Tree until level in at least one SG is restored into the narrow range. Narrow range level is reestablished in all SGs to maintain symmetric cooling of the RCS. The control range ensures adequate inventory with level readings on span.

ACTIONS:

o Determine if SG narrow range level greater than (3)% ".h-o Determine if narrow range level in any SG continues to increase $7 o Maintain total feed flow greater than (2) gpm until narrow range level 4j

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greater than (3)% in at least one SG o Control feed flow to maintain narrow range level between (3)% and 50";

o Stop feed to SG where narrow range level continues to increase INSTRUMENTATION: a o SG narrow range level indication o Total fead flow indication o Feed flow control valves position indication CONTROL /EOUIPMENT:

Feed flow control valve switches KNOWLEDGE:

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FIGURE 4 TASK E01.7 ELEMENT TABLE -

Function Monitor / Regulate Secondary Inventory Task E01.7 Check Steam Generator Levels <

Task Objective e To ensure steam generator levels are restored to and controlled 1

at no-load level.

Task Decision (Criteria) Requirements . y;t-1.

  • See Subtasks iMi' jf.

Task Knowledge Requirements

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  • See Subtasks Task Instrumentation (Criteria) Requirements
  • See Subtasks - ._

Task Action s (Criteria) Requirements e See Subtasks Task Control Capability (Criteria) Requirements

  • See Subtasks Consequences of. Task Error / Omission e See Subtasks 1 -

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SUBTASK E01.7A I ELEMENT TABLE -

Function Monitor / Regulate Secondary Inventory Task E01.7 Check Steam Generator Level Subtask E01.7A Check Level Greater Than 60%

Subtask Objective z.

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Subtask Decision (Criteria) Requirements ,,f

[ e To determine if steam generator levels are greater than 60%.

+ Subtask Knowledge Requirements

  • No special requirements .

Subtask Instrumentation (Criteria) Requirements

  • LR-42064,01,02 Task Action (Criteria) Requirements e If steam generator levels are not greater than 60% wide range ,

level, perform subsequent actions then go to the next subtask.

e Maintain hotal feedwater flow greater than 200 GPM until wide range level is greater than 60%.

Task Control Capability (Criteria) Requirements

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  • None
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SUBTASK E01.7A Cont.

Consequences of Task Error / Omission

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error / omission will delay operator action to throttle AFW in the next subtask.

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SUBTASK E01.7B I ELEMENT TABLE '

Function Monintor/ Regulate Secondary Inventory Task EOl.7 Check Steam Generator Levels Subtask E01.7B Control Feedwater Flow to Maintain Wide Range Level at 62 (60 to 64)%

Subtask Objective A - .%.

  • To ensure feedwater flow is throttled to maintain S/G level. I)!

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  • 42

.y Subtask Decision (Criteria) Requirements i,

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  • To determine that feedwater flow is properly throttled to maintain steam generator level. 4-4 Subtask Knowledge Requirements e AFW system design and means for control of - AFW flow t5 steam ~' "'~ ---- -

generators. .

Subtask Instrumentation (Criteria) Requirements e Main Steam e Steam Generator Wide Range Level (60-64)%

, e LR-42064,01,02 e Main Feedwater and Condensate e Feedwater Flow Control Bypass Valves e HC-4306401 -

e HC-4306402'

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e Auxiliary Feedwater System . . .

e Auxiliary Feedwater Flow (existence of flow) e FI-4122702 Aux FW to 11 Stm Gen Flow e FI-4122802 Aux FW to 12 Stm Gen Flow -

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SUBTASK E01.7B Cont.

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Subtask Instrumentation (Criteria) Requirements Cont.

e. Motor Driven Aux Feedwater Pump (running)
  • ES-46438 11 TD Aux FW Pump Sel e IL-46424,01,02,03 11 TD Aux FW Pump (MV-32264f'
  • IL-46127,01,02 1A Main Stm to 11 Aux (MV-32016) e IL-46128,01,02 1B Main Stm to 11 Aux (MV-32017) e Auxiliary Feedwater Valves (indication of position, open-closed)
  • IL-46314,01,02 11 Aux FW Pump Discharge to 11 S/G e IL-46315,01,02 11 Aux FW Pump Discharge to 12 S/G e IL-46316,01,02 12 Aux FW Pump Discharge to 11 S/G e IL-46317,01,02 12 Aux FW Pump Discharge to 12 S/G e IL-46318,01,02 11/12 Aux FW to 1A Stm Gen (MV-32242)
  • IL-46319,01,02 11/]2 Aux FW to 1B Stm Gen (MV-32243) d?,-

Subtask Action (Criteria) Requirements $f e Control feedwater flow to maintain wide range level at 62% fEh '

(60 to 64)%, go to next task. *

SuStask Control Capability (Criteria) Requirements e Main Feedwater and Condensate e Feedwater-Flow Control Bypass Valves

  • HC-4306401
  • HC-4306402
  • ES-46315 11 Aux FW Pump Discharge to 12 S/G (MV-32239)
  • ES-46316 12 Aux FW Pump Discharge to 11 S/G (MV-32381)
  • ES-46317 12 Aux FW Pump Discharge to 12 S/G (MV-32382) e ES-46318 11/12 Aux FW to 1A Stm Gen (MV-32242)
  • Turbine Driven Aux Feed Pump (start)
  • 46438 11 TD Aux FW Pump Sel e ES-46424 11 TD Aux FW Pump (MV-32264)
  • ES-46127 1A Main Stm to 11 Aux FW Pump (MV-32016) e ES-46128 1B Main Stm to 11 Aux FW Pump (MV-32017) s./

FIGURE 4 cont.

. SUBTASK E01.7B Cont.

Consequences of Subtask Error / Omission

>

  • If steam generator levels are at 62%, task error / omission will delay operator action to throttle AEW flow to control steam '

generator level to no-load level. A delay to throttle AFW flow will aggravate the plant transient by extending RCS cooldown.

  • The consequences of task error / omission are minimized

by the -l CSE status trees.

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FIGURE 5 CONTROLS REQUIREMENTS TABLE SYSTEM - Auxiliary Feedwater System CONTROLS - AFW Flow Control Valve

LOCATION - Control Panel E-1 CRITERIA REQUIREMENTS TASK REQUIREMENTS

  • Control AFW Flow EOO.11 --

E00.23 (E30.7, E31.4, E32.4, 2[i C33.5A) S E01.14A (1) .N*

E01.2 E01.3C E01.7B E02.15 E03.8C E10.3 E30.4 E33.4B~(C31.8B)

ES1.6 C00.3 FHl.2C FHl.11 FHl.18 FC2.8B e Closed to faulted SG E20.4 FS1.11 C00.5

  • Fill ruptured SG E31.6 (E32.9, E33.9, C31.27, C32.21, C33.26) l l
  • Maintain greater than 200 GPM FC1.9A l FC2.8A (C33.5B)

E33.4A (C31.8A, C32.3A)

  • Close valves FPl.1 FH2.6 FH4.3

( FZ1.5

  • Maintain SG level 60 to 75% FC1.9B
  • 120 1

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CONTROLS REQUIREMENTS TABLE i AEW Elow Control Valve (Cont.)

I CRITERIA REQUIREMENTS TASK' REQUIREMENTS l

  • Maintain full flow C00.8A l

1 1 e Control flow at 25 GPM per SG C21.2A EHS.4 ..

EES.5

  • Maintain level less than 75% C21.2B

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FIGURE 5 cont.-

FIGURE 6 INSTRUMENTATION REQUIREMENTS TABLE -

Main Steam System

SYSTEM -

INSTRUMENTATION - Steam Generator Wide Range Level

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  • LR-42064,01,02 s .

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RANGE - 0-100%

LOCATION - Control Board D-1 CRITERIA REQUIREMENTS TASK REQUIREMENTS

  • Greater than 60% E00.20B (E30.20B, C33.7B)

E00.23 (E30.2, E31.4, E32.4,  :.g i.

4 C33.5A) feyf =

E01.2 S

E01.7A .i E10.11D ' a./-

E31.6 (E32.9, E33.9, C31.27 C32.21, C33.26)

A'-

E33.4A (C31.8A)

FC2.8A (C32.3B) _

FPl.1 (EP2.1)

COO.8A -

FHl.25 FC1.9A i e Level 60-64% 'E10.3 (FHl.6, EHl.11)

} E00.11B E01.7

E03.8C C00.9 e Increasing E01.3C E30.1 e At 33% E01.14A (1)

E01.6B e Increasing in an uncontrolled EOA.4A (C33.7C) manner i

e Level equal to 5% narrow E30.3A range l
  • Ruptured SG greater than 60% E31.6 -

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166 .

INSTRUMENTATION REQUIREMENTS TABLE Steam Generator Wide Range Level (Continued)

CRITERIA REQUIREMENTS TASK REQUIREMENTS ~

FC2.9B (C33.5B) j

  • Between 60 and 75%

-- FPl.12 FC1.9B

  • Less than 75% C21.2B C21.18 C21.36B
  • Less than 70% C31.11 FH4.1 '

FH4.4 C33.1 (C33.23B, C33.31B)

  • Less than 60% _ .. _ FHS .1_ . _

FHS.5 FHS.4

  • Greater than 5%

qQi.

  • Stable or decreasing C33.23C (C33.31C) >%ri e

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167 FIGURE 6 cont.

(D) Page 13. 2nd Paragraph of Draft PINGP Response:

The bases for inadequade operator staffing presumes both units are involved in emergency sequences at the same time. This is not part of the Prairie Island Design Basis.

(E) Page 14. Last Paragraph of Draft Page 15. 1st Paragraph of Draft .

PINGP Response:

In the Prairie Island DCRDR, two separate review activities were con-ducted to comprehensively cover all the topics subsumed under control room survey. The first was a component checklist review specific to component design. The checklist materials for this review were de-rived from NUREG-0700 Section 6 and organized according to each unique group of component types. All the checklist items from sub-sections 6.4--Controls and 6.5--Visual Displays were covered.

The second activity was a control room survey covering topics other than specific component design. The following subsections of NUREG- ,

0700 were included in the control room survey checklist in their 4 entirety:

o 6.1 Control Room Workspace o 6.2 Communications o 6.3 Annunciator Warning Systems o 6.6 Labels and Location Aids o 6.8 Panel Layout o 6.9 Control-Display Integration Included in the survey were all of the checklist items from the NUREG-0700 subsections addressing emergency equipment ~(6.1.4),

temperature and humidity (o.l.5.1), ventilation (6.1.5.2), and personal storage (6.1.5.6).

The control room survey did not cover the NUREG-0700 Subsection 6.7--

Process Computer because the Prairie Island process computer is being replaced as part of the Emergency Response Facility Plant Process Computer System (ERF/PPCS) project. A human engineering review of the ERF/PPCS capability is being conducted, as required in the PINGP Uniform Modification Process and the Emergency Response Computer System Verification and Validation Plan.

A concern was raised in the draft Technical Evaluation Report that the "NUTAC Control Room Design Review Survey Development Guidelines" may have been applied to survey development instead of NUREG-0700 (draft Technical Evaluation Report, p. 15). In fact, the component checklist review and the control room survey were based fully on NUREG-0700 and l Page 3

exhaustively treated the topic items contained therein. The NUTAC.

documents produced by INP0 were reviewed early in the DCRDR methodology and served as references for techniques in effectively conducting the surveys, as well as verification and validation activities.

(F) Page 17 Top (2): 6.4.2.1 of Draft

}

PINGP Response:

Item 2. Convention for " TRIP" to left and "CLOSE" to right on breaker switches--This power industry convention will be used consistently

+ throughout the control room. Conventions for other control movements are determined to be in accordance with NUREG-0700 item 6.4.2.1 re-garding population stereotypes, j (G) Page 17 [3]: 6.4.4.5.d(1)(a) of Draft

, PINCP Response:

Item 3. Position indication of rotary selector control setting--

NUREG-0700 does not provide an exhaustive list of acceptable alterna- ,

tives for rotary selector control position indication. The document ,

only cites " desirable alternatives" (p. 6.4-23, item 6.4.4.5.d(1)). [

Two of the desirable alternatives are the engraved line on top and 4 side of the knob, and a pointer shape. Rotary selector-controls at

, Prairie Island are Westinghouse OT-2 switches with an engraved dot l indicating the pointer end of the control. (Two examples of these

! controls are diagrammed in the Prairie Island " Control Board Standards" j on pages 2-15 and 2-17.) These switches have either two positions (10 and 2 o' clock) or three positions (10, 12, and 2 o' clock)--only 4

one end of the pointer can be pointing to one of the settings. The 4

design of these switches fulfills the requirement for position indi-cation unambiguously.

(H) Page 17 [5] 6.4.5.1.d(2)(b) of Draft i PINGP Response:

I Item 5. Specifications for discrete thumbwheel controls--NUREG-0700

. item 6.4.5.1.d.(2)(b) was compared to Prairie Island's conventions specifications because no other items were at all relevant to a particular component type known as star handles. As noted in the 1 rationale statement in the " Evaluation of Design Conventions Speci-

{ fications Against NUREG-0700 Guidelines," the star handle is designed to be grasped by the whole hand--not by the thumb as a thumbwheel would be. (A diagram of a typical star handle control is shown in the Prairie Island " Control Board Standards" on page 2-14.) It would not be appropriate to use a trough distance of 0.45 in. to 0.75 in, for star handles; therefore, this item is not applicable and the Prairie Island convention specification for trough distance of 1 1/8 in. is appropriate.

Page 4 -

(I) Page 18 [9] 6.5.3.1.c(1) of Draft PINGP Response:

Item 9. Indicator illumination for " motor start not recommended"--

The subject of this item is the computer-controlled Large Motor Monitor system and its recommended use is only to limit heat buildup in the motor windings from repeated starts in a short time period.

It is used for normal operation as a reminder to limit deterioration of the insulation. .

l The normally illuminated condition of this indicator light is con-j sidered appropriate by the Control Room Design Review Committee, and the cost / benefit of making a modification to it cannot be justified for the following reasons:

1. It is considered to be a " permissive" indication and not an

" alarm." Permissive lights are lit when the permissive status allows functioning of the equipment.

4 2. The negative impact on operator retraining would be significant .;

1 if this were changed.

5.

3. The rationale for making this change is not appropriate. d (J) Page 18 (11) 6.6.2.4.c of Draft l PINGP Response:

i Item 11. Labels of controls visible during actuation--As noted in the I

rationale statement, the design of controllers is a special case; the convention for positioning of labels is consistent .or all other controls in the control room. There is a deviation from NUREG-0700 item 6.6.2.4.c regarding labels of controls visible during actuation

, of the controls only for one type of controller with 3 position, spring-loaded AUT0/ MANUAL positioner. (An example of this controller i is diagrammed in the Prairie Island " Control Board Standards" on page 2-23.) The AUT0/ MANUAL positioner on this controller has multiple functions--it is moved to left or right to manually close and open the valve, respectively. It is moved downward to initiate automatic valve control. Because ths available settings are indicated unambig-usously by slots cut into t'he faceplate, operators are not confused about the action of the positioner, even if the label "AUT0" is covered by fingers momentarily while grasping the control. It is judged that the design of this controller promotes effective use, and that the Prairie Island convention specification is appropriate.

i Page 5

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-(K) Page 19 [12] 6.6.3.8.a of Draft PINGP Response:

Item 12. Positive identification for all control positions--The subject of this convention is the Westinghouse OT-2 rotary selector controls that have two discrete functional control positions which are labeled and a spring-loaded center position which is unlabeled. (An example of this control is diagrammed in the '_' Control Board Standards" on page 2-17.) For these controls, the center position is not a discrete functional position--it indicates only the absence of an "open" or "close" signal for motor valves. If the valve may be activated auto-matica11y, then the center position is functional. For such valves, the " Control Board Standards" directs that the center position be labeled "AUT0" (e.g., page 2-15). The convention as currently stated in the " Control Board Standards" is appropriate and should not be changed.

(L) Page 19 2nd and 3rd Paragraphs of Draft PINGP Response: -

4, Refer to (E), (F), (G), (H), (I), (J), and (K) responses above, and (M)  ?

responses below. This clarification of conventions and the survey d process, (E) above, should resolve questions about them. Changes or a #

resurvey are considered unnecessary.

(M) Page 21 2nd and 3rd Paragraphs of Draft and Page 24 2nd Paragraph of Draft PINGP Response:

The 128 HEDs identified in Appendix C of the " Detailed Control Room Design Review Summary Report" were separated from the others in the HED assessment process because they were all relevant to topics covered in the " Human Engineering Design Requirements and Conventions Regardini!; Component Design, Labeling, and Abbreviations" now called

" Control Board Standards"--the conventions specification document was developed to serve as a standard for all control room redesign and enhancement. The set of HEDs documented in Appendix C involves prob-lems with component labeling, meter face labeling, color coding,. meter scales, and other topics. It was determined that each of these HEDs would be corrected by the systematic adoption of the Control Board Standards to which Northern States Power has committed. -(Most such corrections involve paint, tape, and labeling enhancements.) Since the HEDs were selected a priori for correction, they were not sub-jected to safety significance rating or priority categorization.

NUREG 0800 Page 18.1-A20 allows for not doing an extensive verifica-tion process for corrective actions that are straight forward.

In the " Evaluation of Design Conventions Against NUREG 0700 Guidelines" all those items Not Corrected by use of the " Control Boards Standards" were marked N/A and were treated in the full review of HEDs.

Page 6 -

The three reports listed under section 2.3.4 of the Summary Report are three different revisions of the draft " Design Requirements and Conventions Specifications" for control room instrumentation at Prairie Island. The current version of the document is the Prairie Island " Control Board Standards," enclosed with this submittal.

This document has been submitted to plant management as a guide for instrumentation modifications and additions.

Three interim reports listed under section 2.3.5 of the Summary Report contain background data and HED assessment results. They.are:

o " Prairie Island Nuclear Generating Plant Control Room Design ,

Review--Human Engineering Discrepancy Assessment Results: HED 1 Summary Report" o " Prairie Island Nuclear Generating Plant Control Room Design Review--Human Engineering Discrepancy Assessment Results: Rating Scores for All Instruments and All HEDs Sorted by Instrument" o " Prairie Island Nuclear Generating Plant Control Room Design Review--Human Engineering Discrepancy Assessment Results: Rating Scores for All Instruments and All HEDs Sorted by HED Code Number"

  • All of the information in the sorted lists comprising these three i interim reports is contained in the " Detailed Control Room Design
  • Review Summary Report"--Appendix D. However, the three reports are included with this submittal as requested.

(N) Page 25 Last Paragraph of Draft and Page 26 1st Paragraph of Draft PINGP Response:

The concerns raised relate to HEDs from annunciators and labeling identified as Appendix A-6 and B-4. Appendix B-4 lists HEDs for which " justification for no corrective action for individual HEDs may not have considered cumulative or interactive effects with other HEDs." These HEDs cover topics of annunciator system design, legend pushbuttons, and labels and location aids. Appendix A-6 lists HEDs for which "the proposed corrective action is not adequate due to the non-IE safety grade classification of the SPDS." The Appendix A-6 HEDs all involve use of the SPDS as a resolution.

The following discussion provides clarification of the process by which the potential interactive and cumulative effects ,were studied.

A review of interactive and cumulative effects among HEDs was con-ducted during the HED assessment process for all HEDs in priority categories 1, 2, 3, 4, and 5. The review process, described in sub-section 4.3.4 of the Summary Report, entailed the following three steps:

Page 7 *

)

1. Review of HED information;
2. Review of interactions during validation walk-through talk-through;
3. Review of instruments with multiple associated HEDs.

The results of these activities are documented in three interim reports:

o Prairie Island Nuclear Generating Plant Control Room Design Review--Human Engineering Discrepancy Compilation and Assessment (Preliminary), Interim Report, Vol. VII, Part 1.

o Prairie Island Nuclear Generating Plant Control Room Design Review--Validation of Control Room Function Interim Report, Vol. VI.

o Prairie Island Nuclear Generating Plant Control Room Design Review--Human Engineering Discrepancy Assessment Results: Rating Scores for All Instruments and All HEDs Sorted by Instrument.

Detailed justification for PINGP's prioritization of HED/ instrument .

combinations is described i'n the Summary Report in subsections 4.3.3--

  • Human Engineering Discrepancy Priority Categories. The three steps performed were- ,
1. Determine weighting of criticality and importance of each item on the HED rating form and compute weighted scores for each of the four rating sections.
2. Factor the weighted scores to create assessment scales for public and plant safety consequences.
3. Determine distribution of assessment scales and classify priority of HED/ instrument combinations.

The corrective action and final resolution determined for each HED/

instrument combination are described fully in Appendix D of the Summary Report.

Although SPDS is not 1-E qualified, it is an acceptable alternative for informational needs as indicated in Generic Letter 82-33 ? age 4 Paragraph 3.1:

"3. COORDINATION AND INTEGRATION OF INITIATIVES 3.1 The design of the Safety Parameter Display System (SPDS),

design of instrument displays based on Regulatory Guide 1.97 guidance, control room design review, development of function oriented emergency operating procedures, and operating staff training should be integrated with -

respect to the overall enhancement of operator ability Page 8

1 to comprehend plant conditions and cope with emergencies.

Assessment of information needs and display formats and locations should be performed by individual licensee.

The SPDS could affect other control room improvements that licensees may consider. In some cases, a good SPDS may obviate the need for large-scale control room modifications. Installation of the SPDS should not be delayed by slower progress on other initiatives, and should not be contingent on completion of the control room design review. Nor should other initiatives, such as upgraded emergency operating procedures, be impacted by delays in SPDS procurement. While the NRC does not plan to impose additional requirements on licensees regarding SPDS, the NRC will work with the industry to assure the development of appropriate industry standards for SPDS systems."

(0) Page 29 1st, 2nd and 3rd Paragraphs of Draft PINGP Response:

The comprehensive integrated plan was submitted in response to Generic

  • Letter 82-33 in April 1983. A copy of our latest Control Room Design ,

Review Proposed modifications schedule is attached. Training is a s requirement in Northern States Power's Uniform Modification Process; N1AWI 5.1.10 Future Needs requires training to be identified and N1AWI 5.1.16 Turnover for Operations requires that training be com-pleted before a modification is turned over to operations. Please note in our attachment that the schedule has been developed to ensure that the simulator has been upgraded to facilitate operator training prior to operation on the modified plant control board. The SPDS training package is being developed at this time and is required by the Emergency Response Computer System Verification and Validation Plan.

(P) Page 30 2nd and 3rd Paragraphs of Draft PINGP Response:

The implementation schedule supplied in (0) provides for the correction of the identified HED's. NSP has proposed a schedule that will effec-tively allocate human and financial resources, integrate the modifica-tions with other requirements such as refueling outages, 1.97 activities, SPDS computer installation, and the plant process computer system installation. The schedule also provides for adequate time to cover training on each modification. Making wholesale changes on the board without proper training could have a negative impact on operator per-formance.

(M) response above (N)

(0)

Page 9

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i The draft Technical Evaluation Report cites a concern that a total of 2216 HEDs were identified in the DCRDR but that only 128 HEDs and 391 HEDs are described in the " Detailed Control Room Design Review Summary Report" in Appendices C and D, respectively. This concern is unfounded--

the 519 HEDs describec in Appendices C and D comprise the full set of HEDs identified during the DCRDR process. Most of the HEDs involve more than one instrument. In the Summary Report, Subsection 4.3--Significance Rating of Human Engineering Discrepancies describes how each instrument associated with each HED was rated for safety significance. There are a I

total of 2216 HED/ instrument combinations and these were all subjected

, to safety significance rating. A set of rating scores and a priority category is computed for each instrument of each HED. These are all listed in Appendix D of the Summary Report.

i-(Q) Page 31 2nd Paragraph of Draft PINGP Response:

4 t

i (N) response above.

(R) Page 32 A-3 of Draft q

i PINGP Response:

  • Refer to " Control Board Standards" page 4-9.

Page 32 A-4 of Draft PINGP Response:

l 4

j The HED in question is code number 004-R and concerns the reset of j diesel generator lockout. The Summary Report cited training as the

! resolution for this HED, typically consisting of oral instruction and l walk-through. When the Prairie Island simulator became operational i

in January 1984, training on lockout reset has become an actual hands-i on operalion. This type of training is much more effective because j reset and consequences of improper reset can be readily demonstrated.

Additionally, two other improvements are being implemented to mitigate problems of diesel generator lockout--operating procedures and enhance-ments. The new Emergency Response Procedures specifically address lockout reset following Safety Injection. Label changes are being considered for the reset switch in compliance with convention specifi-cations stated in the Prairie Island " Control Board Standards."

i Page 32 A-5 of Draft PINGP Response:

New types of recorders and/or new computer readouts are being installed or planned. As indicated in the " Control Board Standards" Pages 1-7

and 1-8.

j Page 10 '

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,--,-------...,,.n - -----.-,----n.. , . _ _ , . , . - - . , , - . , , . , - , . - . -

- . - . , - - - , - , , , . . -,---..n., - - , - , - - , , , - - - , - , . , , - . , - - - . , - ,

Page 32 and 33 A-6 of Draft PINGP Response (N) Response above (S) Page 33 B-2 of Draft PINGP-Response: .

Color coding is used (" Control Board Standards" page 3-17) for face plates on Reactor Trip, Turbine Trip and Safety Injection switches, Safeguards Train labels are also color coded. Additional color coding was tried on our control board mock-up and as stated it did create confusion and the meaningfulness of the coding became insignificant because of the profusion of colors and the fact that so many of the controls may or may not have a safety significance depending on the mode of operation e.g. Residual Heat Removal, Containment Fan Coils, and Auxiliary Feedwater.

Page 34 B-3 of Draft ',

PINGP Response: '

Control Board Standards enclosed.

Page 34 B-4 of Draft PINGP Response:

As indicated in the " Summary Report" 4.3.4 Review of Interactive end Cumulative effects was considered. Reorganization of the annunciator panels is planned in accordance with our schedule (attached), system relationships and priority were considered in the planned reorgani-zation.

Page 34 B-5 of Draft PINGP Response:

This study has been completed and no reasonable solution to this issue is available. A computer-controlled annunciator system with plant specific software developed for it would be needed. Based on the severity of this HED, and the control room operators' present ability to cope with it effectively, the cost / benefit is considered excessive and not warranted. A partial and acceptable solution is the planned use of time delays as indicated on pages 27 and 30 of the " Proposed Modifications."

Page 11

  • Page 35 B-7 of Draft PINGP Response:

As indicated in the Summary Report no correction to the meter scales i is required because in addition to the reasons given we consider dual I

range meters subject to misinterpretation and to be avoided where pessible During normal operation they properly provide the required information. They are used as backup to light indication for verifica--

tion of function in the procedures used t o derive HED 034-y.

Page 35 B-8 of Draft PINGP Response:

(D) Response above i

I Page 35 B-9 of Draft PINGP Response:

l l We are required by the NRC to maintain the power supply breakers for )

i the needed valves in a padlocked open position during normal opera- '

tion to prevent mispositioning. In consequence they cannot be repo-sitioned from the control room without out plant reconfiguration.

With this constraint the time for removing the padlocks and placing

, the breakers in the operate position must be taken.

i Page 36 B-10 of Draft i

PINGP Response:

Distinct audible signals are planned to be incorporated during the annunciator modifications. The environmental and noise survey showed that the acoustical limits cited in NUREG 0700 Guidelines were not i exceeded.

i (T) Page 36 and 37 1. System Review and Task Analysis of Draft

]

PINGP Response:

i

] (C) Response above i

i

)

s s

i Page 12 '

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Page 37 2. of Draft PINGP Response:

(D) Response above (N)

Page 38 3. of Draft PINGP Response:

(E) Response above (F)

(G)

(H)

(I)

(J)

(K)

Page 38 4. of Draft PINGP Response: .

(M) Response above Page 39 5. of Draft PINGP Response:

(N) Response above Page 39 6. of Draft PINGP Response:

(0) Response above Page 39 7. of Draft PINGP Response:

(P) Response above and the discussion that follows in (U) provides clari-fication of some of the open items of Appendix A cnd B of the draft Technical Evaluation Report. i l

Page 13 r

1 i

(U) Page 45 A-3 of Draft PINGP Response:

" Control Board Standards" enclosed.

Page 45 A-4 of Draft PINGP Response: ,

(R) Response above Page 45 A-5 of Draft PINGP-Response:

We cannot address these HED's until SAI provides their reasons of why our resolutions are not acceptable.

Page 46 A-6 of Draft  ;

PINGP Response:

(N) Response above Page 49 B-2 of Draft PINGP Response:

We cannot address these HED's until SAI provides their reasons of why our resolutions are not acceptable.

Page 49 B-3 of Draft PINGP Response:

" Control Board Standards" enclosed.

Page 50 B-4 of Draft PINGP Response:

(N) Response above I

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Page 50 B-5 of Dr. aft l

PINGP-Response:

i:

Appendix B-5 HEDsundergoingaddItionalstudy--EachofthethreeHEDs s

~

j cited in this appendix is discussed below.

o HED 029-I
Nuisance alarms, especially during a trip or during startup, distract attention and p.ask cut the most important (high priority) alarms, e.g., waste dispesal.

l .

, . Resolution: No reasonable solution.to this issue is available. A 4

computer-controlled annunciator system with plant specific software j' developed for it would be needed. Based on the severity of this HED, and the control room operators' present ability to cope with

,, it effectively, the cost / benefit is considered excessive ano not warranted. A partial and acceptable solution'is the planned use of time delays as indicated on pages 27 and 30 of the " Proposed l Modificutions."

o HED 022-S: During shutdown, many annunciator tiles remain lighted q.

! and indicate normal conditions. At various reactor power levels some annunciators on the reactor panel indicate normal operation, j Resol. tion: No complete solution to this issue is available. A computar-controlled' annunciator system with plant specific software developed for it would be needed. Based on the severity of this HED, and the control room operators' present ability to cope with

it effectively, the cost / benefit is considered excessive and not

! warranted. A partial and acceptable solution is the planned use of the symbol on page 3-16 of the " Control Board Standards."

o HED 040-X: Auditory signals shouldsbe distinct from, but should not interfere with other control room noises.

f Resolution: Distinct audible signals are planned to be incorporated i during the annunciator modifications.

2 In conclusion, reorganization of the. annunciator panels is planned in accordance 42.th the integrate 1 schedule for control room improvements (attached). System interrelationships.and alarm priorities were con-4 sidered in the planned reorganization. PINGP considers this Appendix

(

B-5 a closed item in compliance with NRC requirements, i Page 52 B-7 of Draft j PINGP Response:

i 2

We cannot address these HED's until SAI provides their reasons of why j our resolutions are not acceptable.

l i

Page 15 l

Page 52 B-8 of Draft PINGP Response:

o 043-I HED

Description:

Information about status of shared equipment is not always well communicated.

Resolution

Description:

Status boards are provided as well as Shift Supervisor and Lead Reactor Operator turnover sheets.

4 TheabovestatusboardsarelocatedonbothUnitOneanddnitTwoand i are required to be updated as needed. Additionally, the turnover sheets

are required and list all equipment status affecting Unit operation. A separate turnover sheet is filled out by each of the Shift Supervisors and a separate one by each of the Lead Reactor Operators. The Reactor Operator has to acknowledge the Lead Reactor Operator turnover sheet to indicate he is aware of plant status, i o 005-R HED

Description:

Diesel 1 and diesel 2 are mirror-image unlike most other panels in the control room which are " cookie cuttered",

within subsystem. Also, controls for the exciter and governor are ,.

not well grouped or associated with the volt meter and watt meter, '

respectively, e

Resolution

Description:

D1 and D2 should be considered as a system.

! The current layout of the panel follows the system layout in the l plant. This appears to be the most logical layout. Also, the volt

meter and watt meter are well labeled.

Additionally the complexity of this safeguards electrical system was- *

considered in the original design and the system is layed out as a mimic board to avoid configuration. ,

f a

o 015-X HED

Description:

Operator movement during a task sequence i

should be minimal.

Resolution

Description:

The control channels are selected, so it seems unlikely that components can be arranged with recorders in close proximity to all the associated displays and controls. Some panel separation is unavoidable.

This HED relates to pressurizer level control indication (on the Reactor Coolant System control panel) thru use of the charging system controls (on the CVCS makeup control panel). A physical separation of six feet exists between control and level indication. The indication can be seen from the charging controls and while certainly not ideal it is 1 considered acceptable based on frequency of use, ability to satisfy

control needs, redundancy requirements for control and indication, and i other automatic control functicas associated with other systems on the Reactor Coolant System panel in addition to charging and letdown control. ,

l 1

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o 034-X HED

Description:

Personnel availability should be consistent with task requirements.

Resolution

Description:

This HED refers to the component status auto-action guide. A control room operator from the non-affected unit would be used to perform this operation.

This is appropriate use of available control room personnel and does ,

not reduce the non-affected unit manning requirements below the minimum.

Page 52 B-9 of Draft PINGP Response:

i We cannot address these HED's until SAI provides their reasons of why our resolutions are not acceptable.

Page 53 B-10 Ve cannot address these HED's until SAI provides their reasons of why our resolutions are not acceptable: .

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