ML20153F030

Comments on Reactor Operator & Senior Reactor Operator Written Exams Administered at Plant on 880314,per NUREG-1021,Section ES-201.Related Info Encl

ML20153F030
Person / Time
Site:	Surry
Issue date:	03/18/1988
From:	Mccallum H VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.)
To:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
Shared Package
ML18151A338	List: ML18151A337 ML20153F030
References
RTR-NUREG-1021 NUDOCS 8805100216
Download: ML20153F030 (38)

Text

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ENCLOSURE 3 ciVED

8 MM " A i' : 2 9 March 18,1988

...u0R0!iII ATLA!1TA, GA.

Regional Administrator Region II U. S. Nuclear Regulatory Commission Docket Nos.

50-280 101 Marietta Street 50-281 Suite 2900 License Nos.

DPR-32 Atlanta, Georgia 30323 DPR-37 Gentlemen:

l VIRGINIA ELECTRIC AND POWER COMPANY SURRY POWER STATION UNITS 1 AND 2 WRITTEN LICENSE EXAMINATION COMMEhTS In accordance with NUREG-1021, Section ES-201, the following comments are submitted concerning the Reactor Operator and Senior Reactor Operator written examinations administered at Surry on March 14, 1988.

REACTOR OPERATOR EXAMINATION QUESTION 2.11 (b)

List 'IVO instances when an operator may want to initiate flow through the RHR Letdown Valve (HCV-1142).

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ANSWER:

1) To cleanup the coolant and/or for chemistry control when on RHR cooling.

2) For RCS solid plant pressure control.

Reference:

Surry ND-88.2-LP-1, pg. 1.15 Surry ND-88.2-LP-2, pg. 2.5 4

1 Surry ND-88.2-LP-2, pg. 2.18 COMMENTS:

)

Add to answer key as alternate acceptable answers:

RHR System heatup Boron concentration equalization a

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8805100216 880504 2

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s c Regional Administrator Page 2

Reference:

1-0P-14.1, pp. 7 and 8 For the caution prior to step 5.19 of OP-14.1, the method to equalize boron concentration is to flow RCS through the RHR System and into the CVCS Letdown System via HCV-1142 during the RHR System heatup.

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QUESTION 3.05 (a)

List the FOUR signals that will automatically start the Motor Driven Auxiliary Feedwater Pumps. Include logic, setpoints not required.

ANSWER:

1) S/G Lo-Lo level (any S/G)

2) Both main feed pumps tripped

3) Any SI Signal (af ter 50 sec. T.D. )

4) Loss of voltage on 2 of 3 RSS Transformer 9uses

Reference:

Surry ND-89.3-LP-4, pp. 4.5, 4.9, and 4.10 COMMENTS:

Accept as acceptabic answer "loss of voltage on 2/2 RSS Transformer Buses for affected unit."

nis is synonymous with the answer key response of "loss of voltage on 2/3 RSS Transformer Buses."

Ret'erence:

Unit 1 Station Electrical Distribution System Drawing QUESTION 3.16 List the WO conditions that will AUTOMATICALLY close the CVCS orifice isolation valves (HCV-1200A, B,

C) if the selector switch is in the REMOTE position.

ANSWER:

1) Valves will auto close on SI T ain A.

2) Valves will auto close if NO Charging Pumps are running.

Reference:

Surry ND-88.3-LP-2, pg. 2.18 COMMENTS:

Remove from the answer key the "TRAIN A" requirement of SI as trainees are generally not required to differentiate between Train A or B actions.

Also, for future reference, modify the question's reference to the "local / remote" function of the HCV-1200 valves as this capability has been removed.

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Regional Administrator Page 3

Reference:

ND-91-LP-3, SI Operations Handout ND-91/H-3.8, pg. 2 i

Operator Training Bulletin #230, referencing EWR-85-551 QUESTION 4.10 l

For certain LOCA's, it is required to trip the RCP if the trip criteria are met.

If forced flw through the core promotes cooling, why are the RCPs tripped?

i ANSWER:

Better decay heat removal rate is achieved since stopping the RCPs i

results in a faster transition to having only steam flowing out the

]

break instead of two phase (water / steam mixture) flow escaping out the break.

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Reference:

Surry ND-95. 3-LP-7, pg. 7. 8 f

l COMMENTS:

s 4

Replace answer key answer with the following from the trainee lesson plan j

handout dealing with RCP Trip Criteria:

The reason for purposely tripping the RCPs during accident conditions 1

is to prevent excessive depletion of RCS water inventory through a small break in the RCS which might lead to severe core uncovery if the RCPs were tripped for some reason later in the accident.

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Reference:

ND-95.2-LP-7, OBJ-E, pp. 7.49 - 7.55 j

Statement from trainee handout ND-95.2/H-7.23, pg. 31 I

QUESTION 4.13 j

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EP-4.00, "Steam Generator Tube Rupture," directs the operator to adjust the uptured SG PORV controller setpoint to 1035 psig (pot setting 7.5).

l Txplain why the ruptured SG PORV setpoint is INCREASED to 1035 psig.

i ANSWER:

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Increasing the SG PORV setpoint above normal provides a method of isol-i ating the ruptured SG while the setpoint is low enough to prevent chal-l l

1enges to the code safety valves.

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Reference:

Surry ND-95.3-LP-13, pg. 13. 71 1

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Regional Administrator Page 4 COMMENTS:

Recommend removing from answer key the statement of "Increasing the SG PORV setpoint above normal." This is because the normal setpoint of the SG PORV is 1035 and therefore, no "lacrease" of setpoint occurs.

Reference:

ND-95. 3-LP-13, pg. 13. 71 i

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Regional Administrator Page 5 SENIOR REACTOR OPERATOR EXAMINATION QUESTION 5.13 Select the statement below which most correctly describes the effect of ignoring blowdown flow on a secondary calorimetric, a) The calculated reactor power will be the SAME as actual reactor power since main steam enthalpy is approximately equal to blowdown fluid enthalpy.

b) The calculated reactor power will be LESS than the actual reactor power since the heat used to increase the enthalpy of the blowdown fluid is not accounted for.

c) The calculated reactor power will be GREATER than the actual reactor power since the enthalpy of the blowdown fluid would be assumed to have increased to the enthalpy of the main steam.

d) The calculated reactor power will be GREATER than the actual reactor power since the heat used to increase the enthalpy of the blowdowr.

fluid is not accounted for.

ANSWER:

c) The calculated reactor power will be GREATER than the actual reactor power since the enthalpy of the blowdown fluid would be assumed to have increased to the enthalpy of the main steam.

Reference:

S0 ND-93.2-LP-4D ND-93. 2-LP-4, pp. 9 - 18 COMMENTS:

Answers "b" and "c" are both correct responses depending upon which cal-orimetric is used (i.e., feedwater flow or steam flow).

Reference:

ND-93. 2-LP-4, pp. 4.15 - 4.17 ND-93.2/T-4.3 ND-93.2/T-4.7

Regional Administrator "age 6 QUESTION 6.05 (b)

State the purpose of the design features of the following components with respect to the consequences of a main steam line break.

b) TDAFW pump steam supply line check valve ANSWER:

b) Prevents the loss of steam supply to the TDAPW pump (prevents loss of TDAFW pump).

Reference:

SO ND-89.1-LP-2C ND-89.1-LP-2, pp. 5, 7, 8, and 11 COMMENTS:

Add to answer key that it also "prevents blowdown of all three S/Gs in the event of a break in any one."

Reference:

ND-89.1-LP-2, pg. 2.7 ND-89.1/T-2.1 QUESTION 6.08 Two signals which cause a turbine runback are high OT Delta T and high OP Delta T signals.

State two additional signals which cause a turbine runback. Include any applicable setpoints and coincidences.

ANSWER:

a) NIS rod drop signal 1 of 4 NIS channels, and 5% decrease in Rx power in 2 sec b) RPI rod bottom signal 2 of 2 impulse pressure channels

• 70% turbine load, and 1 of 4 NIS channels indicate a 5% decrease in Rx pwr in 2 sec.

OR Any rod bottom signal is received f rom RPI.

Reference:

SO ND-89.2-LP-8G ND-89.2-LP-8, pp. 19 - 22

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Regional Administrator I

l Page 7 COMMENTS:

Answer key answer for b) is incorrect. Suggested. rewording as follows:

1 of 48 IRPIs less than 20 steps from bottom.

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Reference:

ND-89. 2-LP-1, pp. 8.19 - 8.21 -

j ND-93. 3-LP-4, pg. 4. 7 i

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QUESTION 6.11 (c)

Consider the following plant evolutions separately with the Steam Dumps j

aligned normally for the specified condition.

State the Steam Dump l

ALTr0MATIC RESPONSE (s)

(i.e., arm, actuate, or none), and state the final plant conditions (i.e.,

temperature and pressure values) specifying the reference parameter used for controller input (e.g., auctioneered Tave).

c) Flant Tave at 550F, NO LOAD conditions.

l ANSWER:

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c) Steam dumps are armed in the Steam Pressure mode and will actuate.

Steam pressure will be controlled at the normal controller setpoint

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of 1005 psig.

Reference:

SO ND-93.3-LP-9E F i

ND-93.3-LP-9, pp.11 - 16

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ND-93. 3-LP-1, pg. 6, T-1. 2 COMMENTS:

Answer key refers to the Controller setpoint of 1005.

The automatic function of this controller has been removed and is now manual only.

Reference:

ND-93.3-LP-9, pp. 9.10 and 9.15 QUESTION 6.15 (a) i For the following NIS permissive signals, state the SOURCE, SETP01hT, LOGIC (i.e.,

2 of 4), and FUNCTIONS (blocks) for each.

List THREE functions for b.

I a)

P-8 permissive

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Regional Administrator Page 8 ANSWER:

a) Source - Power Range NI Setpoint

' 35%

Logic - 2/4 Function - automatically blocks RCS low flow trip (2/3 loops)

Reference:

SO ND-93.2-LP-4C, L ND-93. 2-LP-4, pg. 7 ND-93.2-LP-3, pp. E and 11 COMMENTS:

Modify answer key function to read:

"automatically blocks RCS low flow (or RCP breakers open) trip (2/3 loops)."

Reference:

ND-93.3/Il-11.1 QUESTION 7.07 Unit 1 is operating at 100% power. You are the shift supervisor on shift and you observe the following uncontrolled and unexplained symptoms:

a) Excessive makeup b) Pressurizer level decreasing c) Pressurizer pressure decreasing d) Containment pressure increasing WHAT are FIVE required immediate actions?

ANSWER:

1)

Isolate letdown

2) Control charging flow to maintain pzr level j

3) Verify adequate charging /SI pump suction flow

4) Stop containment sump pumps

5) Check if SI is not required

Reference:

AP-16, pp. I and 2 COMMENTS.

l Add to answer key as one of the immediate actions:

Verify leak greater than 25 gpm.

Reference:

Revision 0.01 to AP-16

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Regional Administrator I

Page 9 QUESTION 7.16 In accordance with the foldout page for EP-2 series procedures, STATE the SI Reinitiation Criteria. (Assume no adverse containment)

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i ANSWER:

Manually operate SI pumps as necessary if EITHER condition listed _ below occurs:

a) RCS subcooling based on core exit TCs - less then 30F.

b) Przr level - cannot be maintained greater than 13*..

Reference:

SO ND-95.3-LP-8B ND-95.3-LP-8, pp. 5, 8, and 19 i

COMMENTS:

Question asks for the "criteria" for SI Reinitiation and not how the reinitiation is performed.

Recommend removal from answer key of l

"manually operate SI pumps as necessary."

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Reference:

Foldout Page for EP-2 Series Procedures QUESTION 8.05 (c) i j

Who authorizes temporary procedure changes to operating procedures that 4

change the intent of an approved procedure?

ANSWER:

1 Superintendent of Operations 1.

Reference:

SO ND-95.5-LP-2D, I ND-95.5-LP-2, pp. 2 and 11 SO ND-100-LP-2C ND-100-LP-8, pp. 5 - 7 SUADM-ADM-02, pg. 5 SUADM-ADM-21, pg. 21 l

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SUADM-0-12, pp. 4 and 5, Appendix A d

SEP, pg. 5. 7 COMMENTS:

l Modify answer key to read:

I Superintendent of Operations with concurrence of SNSCC.

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o Regional Administrator Page 10

Reference:

Memorandum from D. Benson (Station Manager) to all Super-visors, January 26, 1988 (

Subject:

Procedure Deviations)

QUESTION 8.11 As stated in the Technical Specifications, WHAT are the THREE (3) conditions in which a control rod would be considered INOPERABLE?

ANSWER:

1) Rod cannot be moved by the CRDM.

2) Rod misaligned from its bank by more than 12 steps.

3) Rod exceeds its rod drop time limit of 1.8 seconds.

Reference:

SO ND-93.3-LP-3M ND-93. 3-LP-3, pg. 31 COMMENTS:

Modify answer key answer number 3 to be 2.4 seconds versus 1.8 seconds

Reference:

Tech Spec Change #116, pg. 3.12-8 Very truly yours,

u n --_

D. L. Benson H. F. McCallum Station Manager Supervisor, Training - PS0 Enclosure cc (w/o enclosure):

Mr. W. E. Holland NRC Senior Resident Inspectcr Surry Power Station bc (w/o enclosure):

Mr. W. L. Stewart - OJRP5 Mr. J. L. Wilson - OJRPS Ms. N. E. Hardwick - OJRPS Mr. G. L. Pannell - OJRP5 Mr. D. A. Sommers - OJRP5 Mr. H. L. Miller - SPS Dr. T. M. Williams - RPIE Superintendent Nuclear Training - Surry GOV 02-54B NOD Tech. Library (bc original)

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1-0P-14.1 Page 7 of 9

.TIALS 5.0 Procedure [ continued)

PLACING THE RHR SYSTEM IN SERVICE [ continued)

RHR SYSTEM HEAT-UP NOTE:

1.

Heat-up is., accomplished by slowly floving coolant ; from : the '

RCS through the RHR System to the letdown line, controlling; the flow' rate'with HCV-1142. An increase in flow of approxi-mately 20 gpm on (FI-1-150) after opening MOV-1700 and 1701 will give a controlled heat-up.

2.

There is a delay of a number of minutes before the heat-up will be seen on the recorder "RHR TEMP" (TR-1-604).

3.

Minor adjustments to HCV-1758 and/or HCV-1142 may be required for precise heat-up control.

5.11 Monitor letdown line flow and pressure and simultaneously open MOV-1700 and 1701.

(check) a MOV-1700 MOV-1701 1

5.12 Set HCV-1142 to control the letdown line flow at approximate-ly 20 gpm greater than the indicated fiow in step 5.10.2.

5.13 Test MOV-1700 and 1701 IAW 1-PT-30.2.

5.14 MOV-1700 is open.

5.15 MOV-1701 is open.

5.16 Lock the breaker open for MOV-1700.

VERIFIED 5.17 Lock the breaker open for MOV-1701.

VERIFIED 5.18 Control the heat-up rate < 150'F/hr as indicated on (TR 604).

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J 1-0P-14.1 Page 8 of 9 M

6 1986

)_fIALS 5.0 Procedure [ continued)

PLACING THE RHR SYSTEM IN SERVICE [ continued)

RHR FLOW TO RCS CAUTION:,THF L RHR SYSTEM C, MUST BE > THE RCS C IOR TO OPENEG; B

MOV-1720A OR 1720E'.

5.19 When the RHR and RCS temperatures are near equal or "RHR HX OUTLET TEMP" (TR-2-604) has reached its maximum attainable value:

5.19.1 Sample both systems for.C.

3 RHR C Ppa RCS C ppm B

B CAUTION: ENSURE SUFFICIENT SW FLOW THROUGH THE CC HEAT EXCHANCERS PRIOR,TO OPENING EITHER MOV-1720A OR 1720B.

m 5.20 Set the controller for FCV-1605 at 30% open in "MAN".

..)

5.21 Monitor the "RHR HX BYP TLOW" (FI-1-605) and simultaneously I

open MOV-1720A and 1720B.

(check)

MOV-1720A MOV-17205 5.22 Place Atv-1605 in "AUT0" (FI-1-605 approximately 4000 gpm).

5.23 Monitor a stable temperature < 120'F on "RHR HX A CC OUTLT HDR A" (TI-CC-109A).

5.24 Slowly open HCV-1142 to 100%.

]

5.25 Adjust the letdown pressure (PCV-1145 in "AUT0") to establish maximum letdown purification flow.

5.26 Using HCV-1758 continue to maintain RCS temperature at approximately 345'F.

5.27 "CC RETURN HDR TEMP, HDR A" (TI-CC-110A) < 120'F.

T 5.28 Test MOV-1720A and 1720B IAW 1-PT-30.2.

.j 5.29 MOV-1720A is open.

5.30 MOV-17205 is open.

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QJGS7~/Dd S. Ofe 0 230 Kw SMD 23cKv 34.5 Kw BUS 5 34.5 Kv BUS 6 TRA ORhKR bE

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SS TRANSFORh4ER 4

4180 501 15E1 15F 1 15A2 f)

Q15A1 D

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> TO UNIT 2 SS E

GENERATOR 1582Q h1581 I

15 15CF 6c 1 8 H8 25J8 15He{}

15H1 1H IJ 2H h

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h15H3 15J7h h15J3 h

1. 1EDG 1

1. 3EDG

1. 3EDG STUB BUS STUB BUS O L*

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LTG 1H 1H1 IJ1 IJ tyg I

At C2 B1 A2 C1 82 iH12 i

1.n.1 1.n.2

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UNIT 1 STATION i

ELECTRICAL DISTRIBUTION SYSTEM i

1. ^"'*' " "

Sys -zs spr~

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8 go.91/H-3.8 Page 1 of 4 ACTIONS ON'SI INITIATION 1.

Reactor Trip 2.

Turbine Trip

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3.

EDGs start - Do not come on the bus unless UV condition, exists on the emergency bus.

4.

Closes Main Feed Reg. Valves and Bypass Valves and Trips MFPs.

5.

Starts Motor-driven Auxiliary Feed Pumps af ter 50 second time delay.

6.

Starts LHSI Pumps.

i 7.

Starts HHSI Pumps.

8.

Auxiliary Feed MOVs receive "open" signal for 45 seconds.

B 9.

Containment Vacuum Pumps Trip, t

10.

Control Room Ventilation is isolated and Aux. Vent System re-aligns as necessary.

t 11.

Energizes H Analyzer Heat Tracing (if SI signal remains in for 8 1

minutes).

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12. The following valves receive signals to open:

MOV-867C Old Boron Injection Tank Outlet

' s Lineup HHSI to T.

g MOV-867D Old Boron Injection Tank Outlet j

MOV-862A RWST to Lo Hd SI Pump Suction N/0 j

l Insure LHSI lined i

MOV-862B RWST to Lo Hd SI Pump Suction N/0 up, MOV-115B RWST to Chg. Pump Suction i

Line up RWST to NOV-115D RWST to Chg. Pump Suction gggy pp3, i

MOV-865A Accumulator Discharge (1A) N/0 Insure ACCs lined

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MOV-865B Accumulator Discharge (IB) N/0 up.

MOV-865C Accumulator Discharge (10) N/0 i

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,i/H-3.8 PG 2 of 4 13.

The following valves receive a signal to closei i

VCT to Chg. Pump Suction MOV-115C VCT to Chg. Pump Suction MOV-115E Normal Charging Heade'r MOV-289A i

Normal Charging Header MOV 289B 1

MOV-381 Seal Water Return Letdown Orifice IsolatioC HCV-200A i

HCV-200B..

Letdown Orifice Isolation HCV 200C Letdown Orifice Isolation 4

i TV-SI-101A Accumulator N: Relief.Line 5

W-SI-101B Accumulator N Relief Line TV-SI-100 Accumulator N Supply Line TV-VG-109A Primary Drain Xfer Tank Vent -

W-VG-1098 Primary Drain Xfer Tank Vent j

W-VG-108A Primary Drain Xfer Pump Disch.

TV-VG-108B Primary Drain Xfer Pump Disch.

TV-CC-109A Component Cooling From RHRS I

TV-CC-109B Component Cooling Froc RHRS

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TV-SS-100A Pressurizer Liquid Sample i

I W-SS-100B Pressurizer Liquid Sample l

TV-SS-101A Pressurizer vapor Sample 4

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TV-SS-101B Pressurizer Vapor Sample i

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W-SS - 103 RHRS Sample

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1 TV-SS-106A Reactor Coolant Hot Leg Sample W-SS-106B Reactor Coolant Hot Leg Sample Reactor Coolant Cold Leg Sample W-SS-102A 1

W-S S-102B Reactor Coolant Cold Leg Sample l

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Qvo4e n n ic w erei.ow l

MEMORANDUM To Operations Department October 14,1986 FRW D. A. Christian Surry Power Station OTB #230 EWR'S VARIOUS EWR 85-551 EWR 85-551 is the removal of local / remote switches for SOV's 1200 A, B, and C, and 2200 A, B, and C. These switches are located in containment and are not environmentally qualified. During the Fall, 1986 outage, Unit 2 containment work will be done. The EWR will be completed after the outage by removing associated wiring outside the containments.

EWR 86-235D Earlier EWR's modified 1-hts-HCV-104 and 2-hts-HCV-104 resulting in their actuators being increased from Fisher Controls size 45 to size 70. This EWR directs the adjustment of existing spring hangers and the installation of new spring cans to account for the heavier actuators.

EWR 86-260 This EWR directs the replacement of failed RTD TE-2432D, TC protection in the 'C' loop.

EWR 86-264 Presently installed, Unit 2 Steam Generator wide range local level indicators are not environmentally qualified. It is possible a failure of the localindicators 1

could feed back and disrupt control room (remote) indications. Therefore, local steam generator wide range level indicators will be disconnected. This allows the steam generator wide range level transmitter loops to comply with Regulatory Guide 1.97.

EWR 86-325 EWR 86-325 directs an environmental qualification inspection of Unit 2 htOV's.

Based on the results of the inspection /walkdown corrective action will be taken as required.

\\bk D.' A. Christian DAC/htW/dhe

. Q JCSt~/0N % /0 Prolonged RCP operation and the resultant additional liquid mass depletion can greatly affect the degree and duration of core uncovery, i

Depending on plant type and break size, a range of RCP trip times may t

yield PCTs greater than the FSAR case result. The effect of RCP trip time on calculated PCTs is illustrated on handout H-7.22.

1 If RCPs remain operational throughout the transient (Case H on figure r

1) depletion of primary liquid mass is maximized. Nevertheless, PCTs l

remain well below FSAR case results due to enhanced core cooling caused by the high core steam flow rates indicative of RCP operation.

I However, cc,nt inuous operation of the RCPs during a LOCA cannot be j

guaranteed since tripping of the RCPs would occur upon a loss of of f-site power or other essential support conditions which can be l

postulated to occur at any time. :The --reason for-purposely trippias f

the RCPs during accident conditions is to; prevent excessive depletion; f

of RCS water inventory through a small; break in the RCS which might ;

I lead to severe core uncovery if the RCPs were tripped for some reason

[

ilater in the accident. The RCPs should be tripped before RCS liquid l

inventory is depleted to the point where tripping of the pumps would

[

cause the break to immediately uncover.

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In most non-LOCA accidents, it is advantageous to have the RCPs in i

operation. This provides either additional margin to safety criteria J

j limits or makes operator actions during recovery easier.

However, I

whether or not the RCPs remain in operatioa or are tripped, safety criteria must be met and plant operators are provided with guidance to mitigate and to recover from the accident.

For accidents involving l

loss of secondary coolant, control of RCS pressure, RCS temperature, and pressurizer level are the major concerns, rather than core cool-ing. For the various types of SGTR events (either single or multiple 1

4 ruptures) control of the leak rate, RCS pressure, RCS temperature, and pressurizer level are important. In all cases, RCP operation provides 7

i enhanced core heat removal and makes RCS pressure control by the operator a more straight forward matter.

In general, for non-LOCA i

l accidents, it is desirable to have the RCPs in operation throughout the event.

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99 99 z H '?,23 Mi 3/

QJESr/DN Y. / 8 l

The fact that the S/G may overfill due to leakage,-

thus making a water hammer likely if steamed

• I Increased threat of radioactive release to the i

public.

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-For Faulted S/Gs f

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i The sine and location of the break must be consi-i dered.

The break, if in containment, may cause instrument errors, or reliability problems.

If located outside containment, personnel hazards may I

be the paramount concern.

-In both cases if the break is large enough to cause a challenge to the Integrity orange or red path, it should not be used for cooldown.

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Summarise the method of ruptured S/G isolation given in the text of EP-4.00.

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Adjust PORY to 1035#,

Close ruptured S/G MSTV & bypass valve, t

Isolate af fected steam supply to TDAW pump, Verify affected S/G BD TVs closed i

Verify feed isolated af ter level reaches 9% NR.

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Explain why the ruptured S/G PORY is set to a pot setting of 7.3.

The PORY should be set up to open at a value above the --

normal operating pressure but before the first. safety ;

l valve setpoint is reached.

The pot setting of ' 7.3 l

corresponda to a pressure setpoint of 1035 pais. This,

allows the PORY to open and prevent challenges to the j

code safeties which begin opealms at 1945 pais.

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10-13 87/ Revision 1 Emergency Response Guidelines Page 13.71

Q UG5floM fe / 3 WRITE on chalkboard:

h, steam enthalpy

-h blowdown enthalpy bd

= telta he (2) The enthalpy of the blowdown is determined by taking the data point for steam pressure and using the enthalpy for saturated liquid curve in the curve book.

This calorimetric is based on feed flow. -Not alli of - the feed ' flow ' is converted to steam; some of. it is lost to blowdown.

For this

reason, the h

is g

subtracted from h,.

WRITE on chalkboard a x delta h Q

= m x delta h 3jg g

2

'1 (3) The heat input for each loop is calculated by calculating the mass flow rate of feedwater, multiplied by the delta h and subtracting the g

quantity of the blowdown mass flow rate multiplied by delta h '

2 The m is calculated by taking the B/D meter g

indication (gpm),

and through a series of conversion f actors, converting it to Lbm/Hr.

(4) This solves for the heat transferred in the S/G for one loop. This calculation is performed for each loop and the Q for all the loops are added together.

06-08-87/ Revision 1 Nuclear Instrumentation Systems Page 4.15 I

'T DISPLAY ND-93.2/T-4.4 and 4.5.

1 WRITS on chalkboard:

l see total

• 0S/G A S/G B S/G C

+O

+Q Orx " (NS/G A + OS/G B + OS/G C)

Par heat - RCP heat 1

DISPIAY ND 93.2/T-4.6.

(5) The pressurizer heat input is converted from Kw to BTU /hr by mult. plying it by 3413.

The RCP heat input as shown on this sheet is 36 x 10' BTV/hr.

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The reactor heat output is now converted to W h by dividing Q by 3413000.

g The reactor *. power is calculated by dividing the W value by 2441 (licensed power limit) th and multiplying that by 100.

8.

Steam Flow Program - PT-35.2 a.

The steam flow program is performed the same as the feed flow program except steam flow is used as the multiplier of delta h instead of feed flow, b.

The only other major difference is in the blowdown' calculation.

Since steam flow is used for the calculation, the blowdown flow that is removed from the S/G is not sensed in the total S/G flow.

(It was in the feed flow calculation.)

i I

4 Page 4.16 Nuclear Instrumentation Systems 06-08-87/ Revision 1 l

I f

4 i

WRITE on chalkboard:

h blowdown enthalpy - h, feedwater enthalpy = delta hs bd g

DISPLAY ND-93.2/T-4.7.

Since blowdown flow is not taken into account in the-steam flow, the heat added to the blowdown must be

added to the delta h calculated across the S/G.

c.

Other than the differences stated above, the steam flow calorimetric is performed the same as the feed flow calorimetric.

9.

Feed Flow Calorimetric Manual Data Collection PT-35.1 a.

This method of performing a calorimetric is used

-)

when the computer is unavailable.

b.

The methodology of pstforming the calorimetric is the same as for feed flow with the computer; just the method of obtaining the data is different.

(1) S/G pressures and blowdown flow are obtained

\\

from meters in the control room as specified in Appendix B of PT-35.1.

)

(2) Feedwater temperature is obtained from an RTD in l

each feedwater line downstream of the FRV as specified in PT-35.1.

(3) Feedwater differential pressure is obtained from the feed flow nozzle delta p gage (Barton) every five minutes.

3 06-08-87/ Revision 1 Nuclear Instrumentation Systems Page 4.17

4.

• a 4

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DATA SHEET A j

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S Y N E U U M ULA T/o M

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g _n_y,2 Data Sheet A Page 1 of 4 A 1DOP rarm1AT10MS y}75 corrected s/c l Enthalpy stees sic Preee re Line Lose and m (sn/1he) g (pelg)

PSI A costverelosi Pressure (PSIA){

e e

1 27.0 l

Y Feeduster Esthelpy N 8

3 a

temperature *P

+

r i

,I,

, e et sity 1 Enthalpy SD MI

-M

-N Malneteam Flow M x au i

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(SW/lba)

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syserelce Facte Enthalpy N s (en/In.)

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(STU/HR) l 4

Dates I.T-93.2-T-4.T

F

&dG57/* 0$

b05b s.

One decay heat release valve - each S/G has a line that feeds a common header to the decay heat release valve.

U b.

Provides a flow path for long term decay heat release to the atmosphere.

c.

Capacity - can release stesa at a sufficient rate to remove 100*. of the decay heat about 30 minutes af ter shutdown from full power, i

d.

Location - Upper level safeguards, steasside. The line taps off the safety valve header which-taps of f upstream of the trip valve.

e.

-- A non-return valve is provided in 'each-line connecting the main steam lines to the common p

M decay ~ heat release header to prevent reverse flow

)

[

of steam in case of a steam line break.

4 4.

Turbine Driven Aux Teod Water Pump (TDAWP)

J 4

l a.

Each steam line feeds a common header for steam l

supply to the TDAWP.

l 1

I ASK: What is the purpose of TDANPt ANSWER: To provide Aux Feedwater in the event of a station blackout.

3 t

b.

A check valve in each line prevents. the loss of l

steen to the TDAWP in the event of a MSLB.

1 l

12-08-87/ Revision 1 Steam Systems Page 2.7

To Atmosphere To Gland d

n Steam Safety Valves U

n

= To Aux. Steam J

NRV ower Red. Valve > 150 psi

/

OP Relief 30" f

14" alv

/ X

= To Reheaters

/

/

Trip F

F Valve 28"

/

6-b 7, N "A"

To Main S/G

~s' To From

> Turbine

\\

/

Atmosphere "C" S/G 30" 36 Stop From n

'~~'

alves Other HCV 28" D

S/G's He t th r v#

20" S/G's PCV To Reheaters 3I3I

\\

From -

. To Steam fr, "B" S/G ~ 30" Dumps PCV v

Turbine Driven Auxiliary Feed Pump MAIN STEAM SYSTEM ONE-LINE DIAGRAM ND-89.1/T-2.1

~-

..<l QvrSnow'

4. of l,

• s s

3.

Physically, pushing the latch pushbutton causes the following to occur:

Auto Stop 011 Reset Overspeed Trip Roset Vacuum Trip Roset 33 R0 Reset Opens: Stop Valves Reheat Valves Intercept Valves Close signal to governor valves Positions air pilot valves Resets steam dumps G.

Turbine Runback 1.

In the event of an approach to overpower AT, overtem-perature AT, or dropped rod conditions, the Turbine Runback Subsystem provides a signal to the AGVC and the O

MGVC to automatically reduce turbine load at a safo yet i

rapid rate, to a level which maintains safe margins in the reactor core. One series of runbacks is initiated if the following conditions are met:

i Two of the three overtemperature AT channels indicate greater than 2 percent below the OTAT trip I

setpoint, or l

Two of the three overpower AT channels indicate j

greater than 2 percent below the OPAT trip setpoint, f

or t

1~ ^ One of. the four NIS rod drop. signals indicate a 5 l

percent decrease in reactor power in 2 seconds.

l

]

10-21-87/ Revision 2 Main Turbine and Support Systes Page 8.19 1

a 2.

h* hen the conditions are met, the following events occur:

(n) v a.

The reference counter, the MGVC, and the setter counter (which controls the SE' ITER display) are pulsed at a very rapid rate.

If an OTAT or OPAT condition initiates the

runback, the reference counter is pulsed so that, for every 1.5 seconds out of every 30 seconds, the turbine load is reduced at a rate of h percent / minute. The pulsing continues until the runback condition clears.

If an NIS dropped rod signal initiates the runback, the same devices are pulsed at the 200 percent / minute rate for one 9-second period.

b.

The OVERPOVER AT TURBINE RUNBACK AND ROD STOP CH I alarm (window 1G-F4), the OVERTEMPERAR'RE AT TL*RBINE RUNBACK AND ROD STOP CH I alarm (window 1G-F3), or the NIS DROPPED ROD STOP AND TL'RBINE RUNBACK alarm g"]

(window 1G-H1) annunciates.

Channels II and III O

have similar alarms, All automatic and manual rod withdrawal signals are c.

blocked, d.

The RUNBACK OPERATOR indicator light on the operator panel illuminates.

3.

There is another type of runback which operates to reduce turbine load by use of the valve position limit circuits.

This runback provides a maximum open signal I

to the governor valve servo mechanism.

The load limit runback is initiated under the following conditions:

I L

j 1

Page 8.20 Main Turbine and Support System 10-21-87/ Revision 2

1 l

e l

Both channels of impulse. pressure (PT-MS1446 and O

-1447) indicate turbine load is above 70 percent, and Either of the following:

a5 One ' of ' four N18' rod drop' channels 1 indicate a 5 percent decrease. in reactor power in '2 seconds, or b.

< Any rod botton signal is - received from the - rod I

position indicator (RPI).circuitst With the conditions satisfied, the runback circuits I

decrease the valve position limit circuits at 120 l

percent per minute until one impulse pressure channel indicates less than 70 percent.

The load limit runback is annunciated by the NIS DROPPED O

ROD STOP AND TURBINE RUNBACK alars (window IG-M1) or the RPI ROD BOTTOM STOP AND TURBINE RUNBACK alarm (window 1G-H2)-.

The RPI-initiated runback can be defeated i

within the Rod Control System; however, such action i

annunciates the RPI 'IVRBINE RUNBACK DEFEATID alara f

(window 1G-CS).

1 After the runback, the condition must be reset before the valves can be repositioned.

H.

Overspeed Protection Controller (OPC) l called the "auxiliary governor" 1.

The OPC circuit accomplishes the following:

0 10-21-87/ Revision 2 Main Turbine and Support System Page 8.21

r:

QOttkgn LO) 6.

The output is then directed to the main control board position indicators.

These indicators, one for each full length rod, give the actual position indicated by the LVDT.

It receives the rod position DC analog signal as adjusted from the signal conditioning module.

7.

The plant P-250 computer also receives the individual

' rod position signals.

8.

The next component to which the signal is supplied is the Rod Bottom Bistable.

This bistable is a simple level detector which receives its input signal from the signal conditioning module.

The bistable output is used to operate a control relay which ~generatesi ther

RPI ROD BOTTOM ROD STOP AND TURRINE RUNBACK ' alarm and' light the rod botton-indicating light; The rod botton' alarm actuates whan any rod drops below 20 steps; 9.

The RPI rod bottom rod stop, the turbine runback, and the rod bottom alarm can be automatically overridden by 1

control banks B, C, and/or D step counters being less l

than 35 steps. For example, if all rod banks, with the i

exception of CBD were above 35 steps, the annunciator would not be activated by a control bank D rod dropping below 20 steps.

However, should a rod in any bank other than CBD drop to less than 20 steps, the alarm would occur.

In other words, the

• alarm will not actuate when any rod in control banks B.

C, or D is less than 20

steps, provided the associated step

'l counter for the rod bank is less than 35 stens.

DISPLAY transparency T-4.3, RBB/SCM, and point out pertinent items of interest and the fact that this is from the IRPI cabinet.

Process Protection and Control Page 4.7

Q llfS7"/OU $. // C I

1 WRITE on chalkboardt 4

I a

Removes load reject arming signal. Spring RESET return to T,y position.

i T,y

- Allows dumps to operate with arming signal from either the load reject or the turbine trip circuits.

4 STEAM PRESSURE Allows steam dump operation with signals from the steam header pressure controller in i

manual only. The automatic circuitry has been removed.

E.

Steam Dump Arming i

1.

Steam Dump "arming" means that instrument air has been i

made available to operate the dump valves when a demand

)

signal is generated.

l 4

1 DISPIAY ND 93.3/T 9.5, Steam Dump Arming Circuit.

r i

DISTRIBUTE ND-93.3/H-9.5, Steam Dump Arming Circuit Work-sheet.

i 1

d 2.

There are three interlocks which must be satisfied in order to arm the dumps when an arming signal is act-4 4

ivated. Those are the "condenser available" interlock, the "condenser cooling" interlock, and the RCS temper-ature interlock.

l i

a.

The condenser available interlock is satisfied by 2/2 condenser pressure transmitters sensing condenser vacuum at > 26 inches Ha for Unit 1 (condenser pressure chart recorder on vertical 4

1 a

Page 9.10 Process Protection and Control 12 12 87/ Revision 2

- - l

p g3

=

I i

c.

The error sisnal also goes to high and high-high O

j error bistables which operate similar to those discussed earlier, h setpoints of these bi-I f

s t a* oles are different than those of the Load Reject mode.

The hish error setpoint is 10' and the high-higt: error setpoint is 20*.

d.

h turbine trip arming sisnal is reset when the l

main turbine is re-latched following the trip.

RE DISPIAY ND 93.3/T-9.6, steam Dump Modulating Circuit.

~

7 ne steam Pressure Mode of operation arms the dumps

[

whenever the Steam Dump Mode Select Switch is placed-in the "Steam Pressure" position and all the interlocks are met, t

a.

This mode of control is used for plant cooldown i

and for maintaining the RCS temperature while at Hot Standby conditions.

['

I b.

The dump demand signal is developed from the steam header pressure controller, h

MANUAL /AITTO control station for this controller is located on I

benchboard 1-2 above and slightly to the right of the Steam Dump Control Select Switch.

I i

i c.

The steam header pressure controller operates only in manual.

N deemed. signal - is controlled by using the "increase" and "decrease" pushbuttees on.

s the centro 11er, EXPIAIN ND 93.3/T.9.6 as necessary to verify trainee under.

standing.

12-12-87/ Revision 2 Process Protection and Control Page 9.15

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1. O '7 8

No. 978 87210 es NUMBER PROCEDURE TITI.E REVISION AP-16.00 00.01 EXCESSIVE RCS LEAKAGE FACE 2 of 7 g

STEP ACTION / EXPECTED RESPONSE RESPONSE NOT OBTAINED

[1]

VERIFY LEAK - GREATER THAN 25 GPM GO TO Step 8.

[2]

ISOLATE LETDOWN:

Close LCV-( )460 A and B Close RHR isolation valve HCV-( )142

[3]

CONTROL CHARGING FLOW TO MAINTAIN PRZR LEVEL:

Control FCV-( 1122

()

manually

[4]

VERIFY ADEQUATE CHG/SI Align CHG/SI pump suction PUMP SUCTION FLOW:

to RWST:

VCT level being a)

OPEN MOV-LCV-115 B and D, maintained by blender b)

Close MOV-LCV-115 C and E.

i (5]

STOP CONTAINMENT SUMP PUMPS:

( )-DA-P-4A and B

[61 CHECK SI - NOT REQUIRED Initiate SI.

GO TO EP-1.00, Reactor Trip / Safety Injection.

a)

PRZR Level - STABLE or INCREASING AND PRZR Pressure - STABLE or INCREASING b

\\s /

b)

RCS leakage - LESS TRAN 150 GPM i

N

Q UE5770/0 9* l h FOLDOUT FOP EP-2 SERIES PROCEDURES 1.

SI REINITIATION CRITERIA Manually operate SI pumps as necessary if EITHER condition listed below occurs:

RCS subcooling. based on' core exit TCs - LESS TRAN 30-[80]'T PR2R level - CANNOT BE MAINTAINED GREATER THAN 13 [49]%

2.

RED PATH

SUMMARY

a.

SUBCRITICALITT - Nuclear power greater than 5%

b.

CORE COOLING - Core exit TCs greater than 1200*F e

n

- q.

Core exit TCs greater than 700*F AND RVLIS full range less than 42% with no RCPs running HEAT SINK - Narrow range level in all SGs less than 32% AND total feed-c.

water flow less than 350 [492) GPM d.

INTEGRITY - Cold leg temperature decrease greater than 100'F in last 60 minutes AND RCS cold leg temperature less than 285'F CONTAINMENT - Containment pressure greater'than 60 PSIA e.

3.

SECONDARY INTEGRITY CRITERIA Go to EP-3.00, Faulted Steam Generator Isolation, Step 1, if any SG pressure is decreasing in an uncontrolled manner or has completely depressurized, and has not been isolated.

4.

EP-4.00', TRANSITION CRITERIA Go to EP-4.00, Steam Generator Tube Rupture, Step 1, if any SG 1 eve:

increas-es in an uncontrolled manner or any SG has abnormal radiation.

5.

COLD LEC RECIRCULATION SWITCHOVER CRITERION k

i Go to EP-2.03. Transfer to Cold Leg Recirculation, Step 1 if RUST level decreases to less than 22%.

) j 6.

AFW SUPPLY SWITCHOVER CRITERION Switch to alternate AFW water supply if CST level decreases to less than 20%.

...,i.:mua mgm,o g, m

,., 4 l

i MEMORANDUM TO All Supervisors January 26, 1988 FROM D. L. Benson Surry Power Station PROCEDURE DEVIATIONS As a result of our efforts to upgrade our 10CFR50.59 review process and to minimize the probability of deviating approved procedures without the proper review, we have changed the procedure deviation approval process outlined in SUADM-ADM-21.

Supervisors should discuss these changes with your respective groups. All procedure deviations initiated on or after February 2,1988, must use the new procedure and the revised deviation form.

The major changes are:

1.

All procedure deviations will be screcned by the cognizant supervisor for 1) a change to the intent of the procedure and 2) the necessity for a safety enalysis and 50.59 review.

The i'

cognizapt supervisor for the respective procedures is identified in Table 5.4.1 of the' procedure. The procedure revision now requires j

supervisory titled personnel to do the screening.

2.

A deviation which changes the procedure intent has been defined as, at a minimum, one which changes the procedure 1) title, 2) initial conditions, 3) precautions or limitations or 4) purpose.

3.

If the supervisor's screening determines : hat the deviation 3

requires a safety analysis /10CFR50.59 review, 3NSOC must approve it prior to implementation.

4.

Two paths are available when the supervisor's screening determines that a safety analysis /10CFR50.59 review is not required.

a.

If the intent is not changed, the deviation can be approved by the cognizant supervisor identified in Table 5.4.1 and a licensed SRO (Shift Supervisor or Superintendent of Operations).

~

b.

If the intent is changed, the deviation must be approved by the cognizant supervisor (in most cases the superintendent level) shown in Table 5.4.2 and the-SNSOC ' prior to implementation.

Shift Supe rvisor or Superintendent of Operations approval is also required prior to actually using the deviated procedure.

5.

The cognizant supervisor signing the deviation is responsible for the intent and safety analysis /50.59 review screening and the technical adequacy of the deviation.

The Shift Supervisor signature indicates that the appropriate approvals have been obtained and that the work can be safety integrated with other ongoing shift activities.

2

]

I.

[.,,. ',

f;E *

• vs.

t I

i l

D. L. Benson Memo to All Supervisors January 26, 1988

{

Page 2 Although this strengthening of our method of controlling plant changes will undoubtedly result in some delays initially, it is necessary to ensure the excellence in station activities that we are all working towards. To prevent the continuing need for a large number of procedure deviations, we need to initiate permanent procedure changes when the deviation is identified.

SNSOC review will stress identification of procedural improvements in order to reduce the need for continuing or repetitive procedure deviations.

It is important for all employees to understand that full ccmpliance with procedures is required and expected.

If a procedure as written 2 including initial conditions, cannot be followed, a properly approved procedure deviation is required before work can continue.

N 1. hemson.

D. L. Benson DLB/pss copy:

Mr.'H. L. Miller Mr. E. S. Grecheck Mr. H. H. Blake Mr. P. W. Tucker Dr. A. E. Friedman o

6

TV Q ve3T/M f. //

..- ii.

TS 3.12-8 01-06-88 AT and Overtemperature AT trip settings shall be reduced by l s

the equivalent of 2* power for every 17. quadrant to average power tilt.

C.

Inoperable Control Reds 1.

A control rod assembly shall be considered inoperable if the assembly cannot be moved by the drive mechanism or the assembly remains misaligned from its group step demand position by more than 212 steps. Additionally, a full-length control rod shall be considered inoperable if its rod drop time is greater than 2,4' seconds to' dashpot entry.

J 2.

No more than one inoperable control rod assembly shall be J

permitted when the reactor is critical.

3.

If more than one control rod assembly in a given bank is out of service because of a single failure external to the individual rod drive mechanism, (i.e. programing circuitry),

l the provisions of Specifications 3.12.C.1 and 3.12.C.2 shall not apply and the reactor may remain critical for a period not to exceed two hours provided immediate attention is directed toward making the necessary repairs.

In the event the affected assemblies cannot be returned to service within this specified period, the reactor will be brought to hot shutdown l

conditions.

4.

The provisions of Specifications 3.12.C.1 and 3.12.C.2 shall not apply during physics tests in which the assemblies are intentionally afsaligned.

5.

Power operation may continue with one rod inoperable provided that within one hour either:

a.

the rod is no lor.ger inoperable as defined in Specification 3.12.C.1, or l

Amendment flos.116 and 116 1

i ENCLOSURE 4 SIMULATION FACILITY FIDELITY REPORT Facility Licensee:

Virginia Electric and Power Company Facility Licensee Docket No.:

50-280 and 50-281 Facility Licensee No.:

DPR-32 and DPR-37 Operating Tests administered at:

Surry Power Station Operating Tests Given On:

March 15-16, 1988 During the conduct of the simulator portion of the operating tests identified i

above, no significant performance and/or human factors discrepancies were observed.

I e