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Forwards Final Response to TMI-related Requirements, Addressing All Requirements of NUREG-0737 & Answering NRC 810220 Request for Info.One Oversized Drawing Encl
	ML20003C860
Person / Time
Site:	Susquehanna
Issue date:	03/16/1981
From:	Curtis N; PENNSYLVANIA POWER & LIGHT CO.
To:	Youngblood B; Office of Nuclear Reactor Regulation
References
	RTR-NUREG-0737, RTR-NUREG-737 ER-100450, PLA-659, NUDOCS 8103180594
	Download: ML20003C860 (150)
	v • d • e

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PPat TWO NORTH NINTH STREET, ALLENTOWN, PA.18101 PHONE, (215) 770 5151 NORMAN W. CUATi$

Vice President Engineenng & Construction. Nuclear 770 5381 March 16, 1981 Mr. B. J. Youngblood, Chief Licensing Branch No. 1 Division of Licensing U.S. Nuclear Regulatory Commission \

N (

Washington, D.C. 20555 g

[67 N U AR j 7 f SUSQUEHANNA STEAM ELECTRIC STATION M AC UPDATED RESPONSE TO TMI RELATED REQUIREMENTc %'#'% r $3 ER 100450 FILE 841-12 PLA-659 O

Dear.Mr. Youngblood:

This letter transmits final responses to items 4 (final TMI responses) and 11 (low power testing) as requested in a 17tter from R. L. Tedesco to N. W. Curtis on February 20, 1981. Attached are forty (40) copies of the. updated response to TMI related requirements for Susquehanna Steam Electric Station Unit 1.

This response addresses all requirements in NUREG 0737 which includes item I.G.1, low power testing.

Attached to each response is'a collection of FSAR sections, technical specifications, nuclear department instructions, and procedures. This information is not to be considered as pa?.t of the response itself, but is provided solely as a con.enience to expedite NRC review. Although some of this information is provided in draft form, the intent with respect to meeting the requirements of NUREG 0737 will not change.

If you have any coments, please' call me.

Very truly yours,

.N.

MCW. Curtis Vice President-Engineering & Construction-Nuclear DPM/mks g P ENN SY LV ANI A POWER & LIG H T COMPANY 180

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X. RESPONSES TO TMI RELATED REQUIREMENTS TABLE OF CONTENTS PAGE X.0 ORGANIZATION X.0-1 X.1 RESPONSE TO REQUIREMENTS IN NUREG 0737 X.1-1 X.1.1 Shift Technical Advisor (I.A.l.1) X.1-1 X.1.2 Shift Supervisor Responsibilities (I.A.l.2) X.1-3 X.1.3 Shift Manning (I.A.l.3) X.1-3 X.1.4 Immediate Upgrading Of Reactor Operator And X.1-6 Senior Reactor Operator Training And Qualifications (I.A.2.1)

X.l.5 Administration Of Training Programs (I.A.2.3) X.1-8 X.1.6 Revise Scope And Criteria For Licensing X.1-8 Examinations (I.A.3.1)

X.1.7 Evaluation Of Organization And hanagement (I.B.1.2) X.1-9 X.1.8 Short-Term Accident And Procedure Review (I.C.1) X.1-ll X 1.9 Shift Relief And Turnover Procedures (I.C.2) X.1-14 X.1.10 Shift Supervisor Responsibility (I.C.3) X.1-14 X.1.ll Control Room Access (I.C.4) X.1-14 X.1.12 Feedback Of Operating Experience (I.C.5) X.1-15

'X.1.13 Verify Correct Performance Of Operating X.1-17

\ctivities (I.C.6)

X.1.14 .SSS Vendor Review Of Procedures (I.C.7) X.1-17 4

'.1.15 Pilot Monitoring Of Selected Emergency Procedures X.1-18 For Near Term Operating Licenses (I.C.8)

X.1.16 Control Room Design Review (I.D.1) X.1-18 X.1.17 Plant Safety Parameter Display Console (I.D.2) X.1-19 X.1.18 Training During Low-Power Testing (I.G.1) X.1-19 X.1.19 Reactor Coolant System Vents (I.B.1) X.1-19 X.1.20 Plant Shielding (II.B.2) X.1-21 i

X.1.21 Post-Accident Sampling (II.B.3) X.1-50 l X.1.22 Training For Mitigating Core Damage (II.B.4) X.1-53 X.1.23 Relief And Safety Valve Test Requirements (II.D.1) X.1-58 X.1.24 Safety / Relief Valve Position Indication (II.D.3) X.1-59 X.1.25 Auxiliary Feedwater System Evaluation (II.E.1.1) X.1-61 X.1.26 Auxiliary Feedwater System Initiation And Flow X.1-61 (II.E.1.2)

X.1.27 Emergency Power For Pressurizer Heaters (II.E.3.1) X.1-61 X.1.28 Dedicated Hydrogen Penetrations (II.E.4.1) X.1-61 X.1.29 Containment Isolation Dependability (II.E.4.2) X.1-62 X.1.30 Accident-Monitoring Instrumentation (II.F.1) X.1-79 X.1.31 Instrument For Detection Of Inadequate X.1-88 i

Core Cooling (II.F.2) l X.1.32 Emergency Power For Pressurizer Equipment (II.G.1) X.1-87

[ X.1.33 Review ESF Valves (II.K.l.5) X.1-88 X.1.34 Operability Status (II.K.l.10) X.1-88 l X.1.35 Trip Pressurizer Low-Level Coincident X.1-88 Signal Bistables (II.K.l.17) l I

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Table of Contents (cont'd)

PAGE X.1.36 Operator Training For Prompt Manual Reactor X.1-88 Trip (II.K.1.20)

X.1.37 Automatic Safety Grade Anticipatory X.1-88 Reactor Trip (II.K.l.21)

X.1.38 Auxiliary Heat Removal System Procedures (II.K.1.22) X.1-88 X.1.39 Reactor Vessel Level Procedures (II.K.1.23) X.1-88 X.1.40 Commission Orders On Babcock And Wilcox X.1-88 Plants (II.K.2)

X.1.41 Automatic Power-Operated Relief Valve X.1-88 Isolation System (II.K.3.1)

X.1.42 Report On Power-Operated Relief Valve Failures X.1-8$i (II.K.3.2)

X.1.43 Reporting Safety / Relief Valve Failures And X.1-89 Challenges (II.K.3.3)

X.1.44 Automatic Trip Of Reactor Coolant Pumps During A X.1-89 LOCA (II.K.3.5)

X.1.45 Evaluation Of Power-Operated Relief Valve Opening X.1-89 Probability (II.K.3.7)

X.1.46 Proportional Integral Derivative Controller X.1-89 Modification (II.K.3.9)

X.1.47 Proposed Anticipatory Trip Modification (II.K.3.10) X.1-89 X.1.48 Power-Operated Relief Valve Failure Rate (II.K.3.11) X.1-89 X.1.49 Anticipatory Reactor Trip On Turbine Trip (II.K.3.12) X.1-89 X.1.50 Separation Of High Pressure Coolant Injection And X.1-89 Reactor Cooling Isclation Cooling System Initiation Levels (II.K.3.13)

X.1.51 Modify Break-Detection Logic To Prevent Spurious Isolation X.1-9#1 Of High Pressure Coolant Injection And Reactor Core Isolation Cooling (II.K.3.15)

X.1.52 Reduction Of Challenges And Failures Of Relief X.1-93 Valves (II.K.3.16)

X.1.53 Report On Outages Of Emergency Core Cooling X.1-94 Systems (II.K.3.17)

X.1.54 Modification Of Automatic Depressurization System X.1-94 Logic (II.K.3.18)

X.1.55 Restart Of Core Spray And Low Pressure Coolant X.1-95 Injection Systems (II.K.3.21)

X.1.56 Automatic Switchover Of Reactor Core Isolation X.1-96 Cooling System Suction (II.K.3.22)

X.1.57 Confirm Adequacy Of Space Cooling For High Pressure X.1-97 Coolant Injection And Reactor Core Isolation Cooling Systems (II.K.3.24)

X.1.58 Effect Of Loss Of Alternating-Current Power On X.1-977 Recirculation Pump Seals (II.K.3.25)

X.1.59 Provide A Common Reference Level For Vessel Level X.1-98 Instrumentation (II.K.3.27)

X.1.60 Verify Qualification Of Accumulators On Automatic X.1-98 Depressurization System Valves (II.K.3.28)

Table of Contents (cont'd)

PAGE X.1.61 Revised Small-Break Loss Of Coolant Accident X.1-# KIT 7 Methods (II.K.3.30)

X.1.62 Plant-Specific Calculations To Show Compliance X.1-L&% lol With 10CFR Part 50.46 (II.K.3.31)

X.1.63 Evaluation Of Anticipated Transients With Single Failure X.1-LGr t o l To Verify No Fuel Cladding Failure (II.K.3.44)

X.1.64 Evaluation Of Depressurization With Other Than The X.1-JOStot Automatic Depressurization System (II.K.3.45)

X.1.65 Michelsen Concerns (II.K.3.46) X.1.LOS' to2.

X.1.66 Emergency Preparedness - Short Term (III.A.l.1) X.1-J,04 to3 X.1.67 Upgrade Emergency Support Facilities (III.A.1,2) X.1-JG4 t od X.1.68 Emergency Preparedness - Long Term (III.A.2) X.1-144"to3 X.1.69 Integrity Of Systems Outside Containment Likely X.1-109 t oB To Contain Radioactive Material (III.D.l.1)

X.1.70 Inplant Iodine Radiation Monitoring (III.D.3.3) X.1-lli X.1.71 Control Room Habitability Requirements (III.D.3.4) X.1- W l82

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Table of Contents (Cont'd)

PAGE X.2 RESPONSE TO REQUIREMENTS IN NUREG 0694 X.2-1 X.2.1 Shift Technical Advisor (I.A.l.1) X.2-1 X.2.2 Shift Supervisor Administrative Duties (I.A.1.2) X.2-1 X.2.3 Shif t Mancing (I. A.l.3) X.2-1 X.2.4 Immediate Upgrading Of Operator And Senior X.2-1 Operator Training And Qualifications (I.A.2.1)

X.2.5 Revise Scope And Criteria For Licensing Examinations X.2-2 (I.A.3.1)

X.2.6 Evaluation Of Organization And Management Improvements X.2-2 Of Near-Term Operating License Applicants (I.B.l.2)

X.2.7 Short Term Accident Analysis And Procedure X.2-2 Revision (I.C.1)

X.2.8 Shift Relief And Turnover Procedures (I.C.2) X.2-2 X.2.9 Shift Supervisor Responsibilities (I.C.3) X.2-3 X.2.10 Control Room Access (I.C.4) X.2-3 X.2.ll Procedures For Feedback Of Operating Experience To X.2-4 Plant Staff (I.C.5)

X.2.12 NSSS Vendor Review Of Procedures (I.C.7) X.2-4 X.2.13 Pilot Monitoring Of Selected Emergency Procedures X.2-4 For Near-Term Operating License Applicants (I.C.8)

X.2.14 Control Room Design (I.D.1) X.2-5 X.2.15 Training During Low Power Testing (I.G.1) X.2-5 X.2.16 Reactor Coolant System Vents (II.B.1) X.2-10 X.2.17 Plant Shielding (II.B.2) X.2-10 X.2.18 Post-Accident Sempling (II.B.3) X.2-10 X.2.19 Training For Mitigating Core Damage (II.B.4) X.2-10 X.2.20 Relief And Safety Valve Test Requirements (II.D.1) X.2-10 X.2.21 Relief And Safety Valve Position Indication (II.D.3) X.2-10 X.2.22 Containment Isolation Dependability (II.E.4.2) X.2-10 X.2.23 Additional Accident Monitoring Instrumentation (II.F.1) X.2-10 X.2.24 Inadequate Core Cooling Instruments (II.F.2) X.2-10 X.2.25 Assurance Of Proper ESF Functioning (II.K.l.5) X.2-Il X.2.26 Safety Related System Operability Status (II.K.l.10) X.2-ll X.2.27 Trip Pressurizer Low-Level Coincident Signal X.2-12 Bistables (II.K.l.17)

X.2.28 Operator Training For Prompt Manual Reactor X.2-12 Trip (II.K.l.20)

X.2.29 Automatic Safety Grade Anticipatory Trip X.2-12 (II.K.l.21)

X.2.30 Auxiliary Heat Removal Systems Operating X.2-12 Procedures (II.K.1.22)

X.2.31 Reactor Level Instrumentation (II.K.l.23) X.2-12 X.2.32 Commission Orders On Babcock And Wilcox Plants (II.K.2) X.2-13 X.2.33 Reporting Requirements For Safety / Relief Valve Failure X.2-13 Or Challenges (II.K.3.3)

X.2.34_ Proportional Integral Derivative Controller (II.K.3.9) X.2-14 X.2.35 Anticipatory Reacter Trip Modification (II.K.3.10) X.2-14 X.2.36 Power Operated Relief Valve Failure Rate (II.K.3.11) X.2-14

Table of Contents (Cont'd)

PAGE X.2.37 Anticipatory Reactor Trip On Turbine Trip (II.K.3.12) X.2*14 X.2.38 Emergency Preparedness-Short Ter:s (III.A.l.1) X.2-14 X.2.39 Upgrade Emergency Support Facilities (III.A.l.2) X.2-15 X.2.40 Primary Coolant Sources Outside Contain=ent (III.D.1.1) X.2-15 X.2.41 Inplant Radiation Monitori;.g (III.D.3.3) X.2-15 X.2.42 Control Room Habitability (III.D.3.4) X.2-15 22D/ad

I 1 . assPosags To T31_331,ATED_E!20Y RE333Ili 1

ThDLD2 Table Nasber Title X.1.3-1 Interia Required Shift Staffing X.1.20-1 Initial Core Isotopic Inventory X.1.20-2 Radiation Zone Classification X.1.20-3 Vital Areas X.1.20-4 Principle Dose Rate Contributors In Plant Area X.1.22-1 Training Criteria For Mitigating Core Damage X.1.22-2 Operations With Dograded Core Conditions-Course Outline X.1.29-1 Containment Isolation Actuation Pro vision X.1.29-2 Essential /No n-Essen tial Penetration Classification Basis X.1.29-3 Actuation / Isolation Signal Codes &

Corresponding Actuating Switches X.2.15-1 Testing Prograa Outline 6

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Is. RE3193 S E S TQ_I3 I _3_E13I EDD_332U I P 8933IS FIGUEES Piqure Numhgg IMe X 1.20-1 Radiation Levels For The Site Plan X.1.20-2 Elevations 646'-0", 645'0", And 656'-0" X.1.20-3 Radiation Levels For Elevations 670'-0" And 676'-0" X.1.20-4 Radiation Levels For Elevations 683'-0", 699'-0",

714'-0" And 716'-0"

f. 1.20-5 Radiation Levels For Elevations 719'-1" And 729'-0" X.1.20-6 Radiation Levels For Elevations 74 9 '-1", 7 5 4 '- 0", 7628-0" 771'-0", And 7 8 3'-0" X.1.20-7 Radiation Levels For Elevations 779'-1", 7998-1", And 806'-0" X.1.20-8 Radiation Levels For Elevations 818'-1" And 8728-4 1/2" X .1. 2 0- 9 Ratio Of Total Energy Emission Rate At Time (t) To Total Energy Emission Rate At One Hour For Sources A, B And C X.1.20-10 Ratio Of Total Energy Emission Rate At Time [t) To Total Energy Emission Rate At One Day for Sources A, 2 And C X.1.51-1 Typical HPCI/RCIC Steamline Break Detection Logic 4

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I.0 OEGAN3IAI1OE This chapter contains a response for each T3I-related requirement. The chapter is divided into secticas, containing the responses to all requirements for applicants for operating licenses issued in a single document. Consult the table of contents to identify what section provides the responses for a given document.

Each section addresses all the requirements in its corresponding document. A response is only given to the most recent in the series of requirements which contains an explanatory text. For example, if an explanatory text of requirement I.A.l.1 appears on both NUREG 0737 and NUBEG 0694, a response is provided to NUREG 0737 since it supersedes all previous requirements. If requirement I. A.l.2 appears in both NU32Gs 0737 and 0694, but the only explanatory test is in NUBEG 0694, the response is provided to NUREG 0694 utilizing the implementation da tes of NUREG 0737.

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X.0-1

L,.l__E31PJ22H_ID_2122]REMjIS IN Nif 3EG 0737 X.1.l_ fH1fI TECHEI{_AL ADV!SO2 (I.A.l.ll X.1.1.1 Statement of_Roguirement Each licensee shall provide an on-shif t technical advisor to the shift supervisor. The shift technical advisor (STA) may serva more than ene unit at a multianit site if qualified to perfors the advisor f unction for the various units.

The STA shall have a bachelor's degree or equivaleat in a scientific or engineering discipline and have received specific training in the response and analysis of the plant for trtnsients and accidents. The STA shall also receive training in plant design and layout, including the capabilities of instrumentation and controls in the control room. The licensee shall assign normal duties to the STAS that pertain to the engineering aspects of assuring safe op cations of the plant, including the review and evaluation of operating experience.

The need for the STA position may be eliminated when the qualifications of the shift supervisors and senior operators have been upgraded and the man-machine interface in the control room has been acceptably upgraded. !!owever, until those long-tera improvements are attained, the need for an STA prog ra m will continue.

The staff has not yet established the wetailed elements of the acadamic and training requirements of the STA beyond the guidance given in the Vassallo letter on November 9, 1979. Nor has the staff made a decision on the level of upgrading required for licensed operating personnel and the man-machine interface in the control room that would be acceptable for eliminating the need of an STA. Until these requirements for eliminating the STA position have been established, the staff continues to require that, in addition to the staf fing requirement specified in subsection I.l.3, an STA be available for duty on each operating shift when a plant is being operated in Modes 1-3 for a BWR. At other times, an STA is not required to be on duty.

Since the November 9, 1979 letter was issued, several efforts have been made to establish, for the longer ters, the minimum level of experience, education, and training for STAS. These efforts include work on the revision to ANS-3.1, work by the l

Institute. of Nuclear Power Operations (INPO), and internal staff i

efforts.

INPO has made available a document entitled " Nuclear Power Plant Shift Technical Advisor--Hecommendations for Position Description, Qualifications, Education and Training." Sections 5 and 6 of the INPO. document describe the educatica, training, and experience requirements for STAS. The NRC staff finds that the I.1-1 l

L

dercriptions as set forth in Sections 5 and 6 of Revision o to the INPO dccument are an acceptable approach for the selection and training of personnel to staff the STA positions. (Note:

This should not be interpreted to mean that this is an NRC requirement at this time. The intent is to refer to the INPO document as acceptable for interim guidance for a utility in planning its ST!. program over the long term (i.e., beyond the January 1, 1981 requirement to have STAS in place in accordance with the qualification requirements specified in the staff's November 9, 1979 letter) .)

Applicanta for operating licenses shall provide a description of their STA training and requalification program in their application, or amendments thereto, on a schedule consistent with the NRC licensing review schedule.

Applicants for operating licenses shall provide a description of their long-term STA program, including qualification, selection criteria, training, and possible phaseout. The description shall be provided in the application, or amendments thereto, on a schedule consistent with the NRC licensing review schedule. The description shall include a comparison of the long-term program with the a bove mentioned INPO document, 1 1.1.2 Interpretation Develop a training program in compliance with the November 9, 1979 letter and submit a description to the NBC. Provide STA coverage for all operating shifts. Candidates will complete a training program and pass a certification examination prior to assumption of duties. Develop a long-term program to maintain or phaseout STAS.

I.1,lg] Statement of Response The program for the selection and training of STA's is detailed in the Nuclear Department Instruction NDI-Q A-4. 2. 2, Selection, Training and Certification of Shif t Technical Advisors".

STA coverage will be provided on operating shif ts in accordance with subsection 6.?.2 of the Technical Specifications. STA's will perform the duties and have the responsibilities outlined in plant procedure AD-00-101, " Shift Technical Advisors - Duties and Responsibilities".

STAS.will meet the qualification requirements of the Vassallo letter of November 9, 1979. All STA training will be completed and STAS will' be ready for shift assig n me nt prior to fuel load.

The long term STA program is identical to the short term program.

X.1-2 w - _m

Ldz2 SEFT SUEXHIggE_ggfg2!S IBVt.HHS _ (I&lt2L No requirement stated in NUREG 0737. Refer to Subsection X.2.2 which containc the response to the requirement stated in NUREG 0694.

X .1. 3 SHIFT MANNING (I. A. I. 3L Izis.lzl__ 5111SE2H1_of Reqgiremeat Applicants for operating licenses shall include in their administrative procedures (required by license Conditions) provisions governing required shif t staf fing and sovement of key individuals about the plant. These provisiona are required to assure that qualified plant personnal to man the operational shifts are readily available in the event of an abnormal or emergency situation. Interim requirements for shift staffing are given in Table I.1.3-1.

These administrative procedures shall also set forth a policy.

The objective of this policy should be to operate the plant with the required staff and develop working schedules such that use of overtime is avoided, to the extent practicable, for the plant staff who perform saf ety-related fractions (e.g. , senior reactor operators, reactor operators, health physicists, auxiliary operators, ISC technicians and key maintenance personnel) .

The staff recognizes that there are diverse opinions on the amount of overtime that would be considered permissible and that there is a lack of hard data on the effects of overtime beyond the generally recognized normal 8-hour working day, the effects of shift rotation, and other factors. NRC has initiated studies in this area. Until a firmer basis is developed on working hours, the administrative procedures shall include as an interia measure the following guidance, which generally follows that of IE Circular No. 80-02.

In the event that overtime must be used (excluding extended periods of shutdown for refueling, major maintenance or major plant modifica tions) , the following overtime restrictions should be followed:

(1) An individual should not be permitted to work more than 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months straight (not including shif t turnover time).

(2) There should be a break of at least 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (which can include shift turnover time) between all work periods.

(3) An individual should not work more than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months in any 7-day period.

(4) An individual should not be required to work more thau 14 consecutive days without having 2 consecutive days off.

I.1-3 j _

Howsver, recognizing that circusstances ay arise requiring deviation from the above restrictions, such deviation shall be authorizcd by the plant manager or his deputy, er higher levels of management in accordance with published procedures and with appropriate documentation of the cause.

If a reactor operator or senior reactor operator has been working more than I? hours during periods of extended shutdown (e. g. , at duties awa y from the control board) , such individuals shall not be assigned shift duty in the control roos without at least a 12-hour break preceding such an assignsent.

NRC encourages the development of a staffing policy that would permit the licensed reactor operators and senior reactor operators to be periodically assigned to other duties away from the control board during their normal tours of duty.

If a reactor operator is required to work in excess of 8 continuous hours, he shall be periodically relieved of primary duties at the control board, such that periods of duty at the board do not exceed about 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months a t a time.

The guidelines on overtise do not apply to the shif t technical advisor provided he or she is provided sleeping accommodations and a 10-minute availability is assured.

Operating license applicants shall complete these ad:inistrative procedures before f uel load.

X.l.3 2 2 Interpretation None required.

I.l.3.3 State 3ent_of Response The f acility staffing requirements are presented in Subsection 6.2.2 of the Technical Specifications. These requirements are consistent with those given in Table I. l.3-1.

The plant policy on operations personnel working hours is discussed in administrative procedure AD-00-026, " Conduct of Operations," and is specifically defined in Operation s Instruction OP-0I-001, " Shift Manning."

I.1-4

TABLE X.1.3-1 INTERIM REQUIRED SHIFT STAFFING One Unit, Two Units Two Units Three Units One Control One Control Two Control Two Ccntrol Operating Status Room Room Rooms Rooms One Unit Operating

1 SS (SRO) 1 SS (SRO) 1 SS (SRO) 1 SS (SRO) 1 SRO 1 SRO 1 SRO 1 SRO 2 RO 3 RO 3 RO 4 R0 2 A0 3 A0 3 A0 4 A0 Two Units Operating

NA 1 SS-(SRO) 1 SS (SRO) 1 SS (SRO) 1 SRO 2 SRO 2 SRO ) Only 1 SRO & 4 R0s required 3 R0 4 RO 5 R0 ) if both units are operated 3 A0 4 A0 ) from one control room 5 A0

.M t e dn All . Units'0perating* NA 1 SS (SRO) 1 SS (SRO) 1 SS (SRO) 1 SR0 2 SR0 2 SRO 3 R0 4 RO 5 R0 3 A0 4 A0 5 A0 All Units Shut Down 1 SS (SRO) 1 SS (SRO) 1 SS (SRO) 1 SS (SRO) 1 R0 2 RO 2 RO 3 R0 1 A0 3 A0 3 A0 5 A0 SS - shif t supervisor RO - licensed reactor operator SRO - licensed senior reactor operator AO - auxiliary operator NOTE: (1) In order to operate or supervise the operation of more than one unit, an operator (SRO or RO) must hold an appropriate, current license for each such unit.

(2) In addition to the staffing requirements indicated in the table, a licensed senior operator will be required to directly supervise any core alteration activity.

(3) See it em I. A.I.1 for shif t technical advisor requirements.

Modes 1 through 3.

44K/cak

X.1.4 IMMEDIATE UPGR ADING OF R EACTOR OPER ATOR AND SENIOR REACTOR CPERATOR TRAINING A ND QU ALIFIC ATIONS_jI. A. 2.1) 12124.1 St at eneg1_o f Requirement Applicants

for senior operator licenses shall have 4 years of responsiDie power plant experience. Responsible powe r plant experience should be that obtained as a control room operator (fossil or nuclear) or as a power plant staff engineer involved in the day-to-day activities of the facility, cc:soncing with the final year of construction. A maxisus of 2 years power plant experience nay be fulfilled by academic or related technical training, en a one-for-one time basis. Two years shall be nuclear power plant experience. At least 6 mon ths of the nuclear power plant experience shall be at the plant for which he seeks a license. Effective date: Applications received on or af ter May 1, 1980.

Applicants for senior operator licenses shall have held an operator's license for 1 year. Effective Date: Applications received a f ter December 1,1980. The NRC has not imposed the 1-year experience requirement on cold applicants for SRO licenses.

Cold applicants are to work on a facility not yet in operation; their training programs are designed to supply the equivalent of the experience not available to them.

Senior operator *: Applicants shall have 3 months of shift training as an extra man on shift.

Control room operator *: Applicants shall have 3 months training on shif t as an extra person in the control room. Effective date:

Applications received after August 1, 1980.

Training programs shall be modified, as necessary, to provide:

1) Training in heat transfer, fluid flow and thermodynamics.

2) Training in the use of installed plant systems to control or sitigate an accident in which the core is severely damaged.

3) Increased emphasis on reactor and plant transients.

Effective date: Present programs have been modified in I

response to Bulletins and Orders. Revised programs should be submitted for OLB review by August 1, 1980.

Precritical applicants will be required to meet unique

' qualifications designed to accommodate the fact that their l

facility has not yet been in operation.

I.1-6 L

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Content of the licensed operator requalificatica programe shall l be modified to include instruction in heat transfer, fluid flow, thermodynamics, and mitigation of accidents invclving a degraded core. Effective date: May 1, 1980 The criteria for requiring a licensed individual to participate in accelerated requalification shall be modified to be consistent with the new passing grade for issuance of a license; 80% overall and 7 0% each category. Effective date: Concurrent with the next f acility a dministered annual requalification examination af ter the issue date of this letter.

Programs should be modified to require the control manipulations listed in Enclosure 4 of NUSEG 0737, item I.A.2.1. Normal control manipulations, such as plant reactor startups, must be performed. Control manipulations during abnormal or emergency operations must be walked through with, and evaluated by, a member of the training staff at a mini mu m. An appropriate simulator may be used to satisfy the requirements for control manipulations. Ef fective date: Programs modified by August 1, 1980. Renewal applications received af ter November 1, 1980 must reflect compliance with the program.

Certifications completed pursuant to Sections 55.10 (a) (6) and 55.33a (4) and (5) of 10 CFR Part 55 shall be signed by the highest level of corporate management f or plant operation (for example, Vice President for Operations). Effective date:

Applications received on or af ter May 1, 1980.

X.1.4.2 _Inteparetation None required.

X.1.4.3 Statement of Response A program is established to assure that all reactor operator and senior reactor operator license candidates (beyond the initial compliment required to startup Units 1 & 2) have the prescribed experience, qualifications, and training. Candidates will be prepared and certified in accordance with Nuclear Department Instruction NDI-QA-4.2.1. Administrative procedure AD-00-103,

" Selection Process for Operations Personnel," details the process by which the qualifications of candidates for operations positions will be evaluated in the future.

The initial startup crews will have completed extensive training devised in part to recognize the non-operational ' status of the units. This program includes real time training on the SSES simulator which duplicates the actual unit and thus in many respects equates to the experience requirements. S ubsection 13.1.3 describes the qualifications commitments for the existing plant staff.

I.1-7

X .1. 5 ADMINISTRATION OF ZE AINING PROGRANS z(I A.2.3L X.1.5.1 Statement of Requiremen_t Pending accreditation of training institutions, licensees and applicants for operating licenses will assure that training center and facility instructors who teach systems, integrated responses, transient, and simulator courses descastrate senior reactor operator (SRO) qualifica tions and be enrolled in appropriate requalification programs.

Iraining center and facility instructors who teach systems, integrated responses, transient and simulator courses shall demonstrate their competence to NRC by successful completion of a senior operator examination. Effective date: Applications should be submitted to later than August 1, 1980 for individuals who do not already hold a senior operator license.

Instructors shall be enrolled in appropriate regualification programs to assure they are cognizant of current operating history, problems, and changes to procedures and administrative limitations. Effective date: Prograss should be initiated May 1, 1980. Programs should be submitted to CLB f or review by August 1, 1980.

X.1.5 2 Interpretation The " instructors" referenced in this requirement are those individuals who teach systems specific to BWRs, in tegrated responses, transients, and simulator courses to licensed operators or licensee candidates.

X.l z 5.3 Statement of Response certification of instructors is described in Nuclear Department

~ Instruction NDI-QA-4.1.4. This procedure delineates which instructors are required to pass the examination for senior reactor operators (SHO) . Three instructors have passed an URC administered SRO exam (taken the week of October 27, 1980). Two additional instructors are scheduled to take the SRO exam in March 1981.

l l I.l.6 _ REVISE SCOPE AND CRITERI A FOR _ LICENSING EX A M IN A TIONS 7 [I.A.3.ll X3 1 6.1 Statement of Requirement A new categori shall be added to the operator written exanination entitled, " Principles of Heat Transfer and Fluid Mechanics."

A new category shall be added to the senior operator written examination entitled,_" Theory of Fluids and Thermodynamics."

I.1-8 m

Tims limits shall be imposed for completion of the uritten examinations:

1. Operator: 9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months .

2. Senior Operator: 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months .

The passing grade for the written examination shall be 80%

overall and 70% in each category.

All applicants for senior operator licenses shall be required to be administered an operating test as well as the written examination. 2ffective date: Examinations administered on or after May 1, 1980.

Applicants will grant permission to NRC to inf orm their f acility management regarding the results of the examinations for purposes of enrollment in requalification programs. Applications received on or after May 1, 1980.

Simulator examinations will be included as part of the licensing examinations.

X.1.6.2 Interpretation None required.

X.1.6 2 3 State, ment of Response The reactor operator and senior reactor operator training program has been upgraded to include the subject material described in this requirement. Refer to Subsection I.l.4.3 for the response to requirement I. A.2.1, "Imm6diate Upgrading of Reactor Operator and Senior Reactor Operator Training and Qualifications."

Candidates will be prepared and certified in accordance with Nuclear Department Instruction NDI-QA-4.2.1. The SSES simulator is available for the simulator portion of exams. Application packages will include a release which permits the NRC to inform PPSL management of exam results.

X.1.7 EVALUATION OF ORG ANIZ ATION AND M AN AGEMENT (I. B. l. 2)

I.l.7.1 Statement of Requirement Sach applicant for an operating license shall establish an onsite independent safety engineering group (ISEG) to perform independent reviews of plant operations.

The principal f unction of the ISEG is to examine plant operating characteristics, NHC issuances, Licensing Information Service advisories, and other appropriate sources of plant design and operating experience information that may indicate areas for I .1- 9

i: proving plant safety. The ISEG is to perform independent review and audits of plant activities including maintenance, modifications, operational problems, and operational analysis, and aid in the establishment of prograssatic requirements for plant activities. Where usef ul improve:ents can be achieved, it is expected that this group will develop and present detailed recommenda tions to corporate sanagement f or such things as revised precedures or equipment modifications.

Another function of the ISEG is to maintain surveillance of plant operations and maintenance activities to provide independent verification that these activities are performed correctly and that human errors are reduced au far as practicable. The IS EG will then be in a position to advise utility management on the overall quality and safety of operations. The ISZG need not perfors detailed audits of plant operations and shall not be responsible for sign-of f functions such that it becomes involved in he operating organization.

The new ISEG shall not replace the plant operations review committee (PORC) and the utility's independent review and audit group as specified by current staff guidelines (3tandard Review Plan, Regulatory Guide 1.33, Standard Technical Specifications) .

Rather, it is an additional independent group of a minisus of five dedicated, f ull-time engineers, loca ted onsite, but reporting offsite to a corporate official who holds a high-level, technically oriented position that is not in the management chain for power production. The ISEG will increase the available technical expertise 1ccated onsite and will provide continuing, systematic, and independent assessment of plant activities.

Integrating the shift technical advisors (STAS) in to the ISEG in some way would be desirable in that it could enhance the group's contact with and knowledge of day-to-day plant operations and provide additional expertise. However, the STA on shift is necessarily a member of the operating staff and cat:not be independent of it.

It .is expected that the ISEG may interface with the quality assurance (QA) organization, but preferably should not be an integral part of the QA organization.

The f uncticas of the ISEG require daily contact with the operating personnel and continued access to plant f acilities and '

records. The ISEG review functions can, therefore, best be carried out by a group physically located onsite. However, for utiliiics with multiple sites, it may be possible to perform portions of the independent safety assessment function in a centralized location for all the utility's plants. In such cases, an casite group still is required, but it may be slightly smaller than would be the case if it were performing the entire independent safety assessment function. Such cases will be reviewed on a case-by-case basis.

This requirement shall be implemented prior to issuance o f an operating license.

I.1-10

Refer to Subsection X.2.6 for the response to additional requirements contained in NUBEG 0694.

X.1.7.2 Interpretation I

None required.

X.1.7.3 Statement of ansponse The functicas of the ISEG will be performed by the Nuclear Safety Assessment Group (NSAG). PPSL's commitment to the NS AG is addressed in a letter from N. W. Curtis to B. J. Youngblood on December 8, 1980 (P L A-5 85) and are further addre.ssed in Nuclear Department Instruction NDI-9.1.1. NSAG will be functional by fuel load.

X.1.8 SHORT-TERM ACCIDENT AND PROCEDURE R EVIEW.II.C ll 121 8.1 Statement _of Requirement Reanalysis of small break LOCAs, transients, accidents, and inadequate core cooling and preparation of guidelines for development of emergency procedures should be completed and submitted to the NBC for review by January 1, 1981. The NRC staff will review the analyses and guidelines and determine their acceptability by July 1,1981, and will issue guidance to licensees on preparing emergency procedures from the guidelines.

Following'NHC approval of the guidelines, licensees and applicants for operating licenses issued prior to January 1, 1982, should revise and implement their emergency procedures at the first refueling outage after January 1, 1982. Applicants for operating licenses issued after January 1, 1982 should implement the procedures prior to operation. This schedule supersedes the

. iaplementa tion schedule included in NUREG-0578, Recommendation 2.1.9 for item I.C.l(a) 3, Heanalysis of Transients and Accidents.

For those licensees and/or owners groups that will have difficulty in attaining the January 1, 1981 due date for submittal of guidelines, a comprehensive program plan, proposed schedule, and a f atailed justification for all delays and problems.shall be submitted in lieu of the guidelines.

I.l.8.2 Interpretation The BWR Owners' Group guidelines may be utilized to develop emergency procedures for accidents and transients.

X.l.8.3 Statement _of Response In the Clarification of the NUREG-0737 requirement "for reanalysis of transients and accidents and inadequate core X.1- 11

cooling and preparation of guidelines for development of emergency procedures," NUREG-0737 states:

Owners' group or vendor submittals may be referenced as appropriate to support this reanalysis. If owners' group or ,

vendor submittals have already been forwarded to the staff '

for review, a brief description of the submittals and justification cf their adequacy to support guideline development is all that is required.

PP&L has participated, and will continue ts participate, in the BWR Owners' Group program to develop Emergency Procedure Guidelines for General Electric Soiling Water Reactors.

Following are a brief description of the submittals to date, and a justification of their adequacy to support guideline development.

A. gescrigtion of Submittals (1) NEDO-24708, " Additional Information Required for NBC Staff Generic Report on Boiling Water Reactors,"

August, 1979; including additional sections submitted in pre-publication form since August, 1979.

(a) Section 3.1.1 (Small Break LOCA) .

Description and analysis of small break loss-of-coolant events, considering a range of break sizes, location, and conditions, including equipment failures and operator errors; description and justification of analysis methods.

(b) Section 3.2.1 (Loss of Feedwater) - revised and resubmitted in prepublication form March 31, 1980.

Description and analysis of loss of feedwater events, including cases involving stuck-open relief valves, and including equipment failures and operator errors; description and justification of analysis methods.

I (c) Section 3.2.2 (Other Operational Transients) -

submitted in prepublication form March 31, 1980; revised and resubmitted in prepublication form August 22, 1980.

Description and analysis of each FSAR Chapter 15 event resulting in a reactor system transient; demonstration of applicability of analyses of Sections 3.1.1, 3.2.1, and 3.5.2.1 to each event; demonstration of applicability of Emergency Procedure Guidelines to each event.

(d) Section 3.3 (BWR Natural and Forced Circulation)

I.1-12

Description of natural and forced circulation cooling; factors influencing natural circulation, including noncondensibles; reestablishment of forced circulation under transient and accident conditions.

i (e) Sec tio n 3. 5. 2.1 (Analyses to Demonstrate Adequate core Cooling) - submitted in prepublication form November 30, 1979; revised and resubmitted in prep ublication form September 16, 1980.

Description and analysis of loss-of-coolan t events, loss of feedwater events, and stuck-open relief valve events, including severe multiple equipment failures and operator errors which, if not mitiga ted, could result in conditions of inadequate core cooling.

(f) Section 3.5.2.3 (Diverse Methods of Detecing Adequate Core Cooling) - submitted in

. prepublication form December 28, 1979.

Description of indications available to the BWR operator for the detection of adequate core cooling (detailed instrument rsponses are described in Sections 3.1.1, 3. 2.1, an d 3. 5. 2.1) .

(g) Section 3.5.2.4 (Justification of Analysis Me thods) -

submitted in prepublication form September 16, 1930.

Description and justification of analysis methods for extremely degraded cases treated in Section 3.5.2.1.

(2) BWR Emergency Procedure Guidelines (Revision 0) -

submitted in prepublication form June 30, 1980.

Guidelines for BWR Energency Procedures based on identification and response to plant symptoms; including a range of equipment failures and operator errors; including severe multiple equipment failures and operator errors which, if not mitigated, would result in conditions of inadequate core cooling; including conditions when core cooling status is uncertain or' unknown.

B. Adequacy of Submittals 1

The submittals described in paragraph A have been discussed and reviewed extensively among the BWR Owners' Group, the General Electric Company, and the NRC staff. The NRC staff has found (N U REG-0737, page I.C.1-3) that "the analysis and guidelines submitted by the General Electric Company (GE)

Owners' Group... comply with the requirements (of the NUREG-X.1-13 P "

0737 clarification) . " In Reference 1, the Director of the Division of Licensing states, "we find the Emergency Procedure Guidelines acceptable f or trial implementation (on six plants with applications for operating licenses pending) . "

PPSL believes that in view of these findings, no further detailed justification of the analyses or guidelines is necessary at this time. Reference 1 f urther sta tes,

" (during the course of implementation de may identif y areas that require modification o r f urther analysis and justification." The enclosure to Reference 1 identifies several such areas. PPSL will work with the BWR Owners' Group in responding to such requests.

By our com:itment to work with the Owners' Group on such requests, on schedules mutually agreed to by the NBC and the owners' Group, and by reference to the BWR Owners' Group analyses and guidelines already submitted, our response to the NUREG-0737 requirement "for reanalyses of transients and accidents and inadequate core cooling and preparation of guidelines for development of emergency procedures" by January 1, 1981, is complete.

Emergency procedures based on those guidelines have been developed and are currently in trial use on the Susquehanna SES Sisulator. These procedures have been submitted for NRC review in a letter.from N. W. Curtis to B. J. Youngblood on March 4, 19 81 (PLA-650) .

References (1) Letter, D. G. Eisenhut (NRC) to S.T. Rogers (BWR Owners' Group) , regarding Emergency Procedure Guidelines, October 21, 1980.

I.l.9 jHIFT RELIEF AND TURNOVjR PROCEDURES (I.C.2L No requirement stated in NUREG 0737. Refer to Subsection X.2.8 which contains the response to the requirement in NUREG 0694 I . l .10 SHIFT SUPERVISOR RESEONSIBILITY (I . C. _31 No requirement stated in NUREG 0737. Refer to subsection X.2.9 which contains the response to the requirement in NUREG 0694 I.1.11 CONTROL BCOM ACCESS (I.C.41 No requirement stated in NUREG 0737. Refer to Subsection I.2.10 which contains the response to the requirement in NUREG 0694 I.1-14

_ u

X .1.12 __PEEDBACK OF OPERATING EX P ER I E NC E (I C.5L I . l .12.1 Statement of Requirement Applicants for an operating license shall prepa re procedures to assure that information pertinent to plant safety originating inside or cutside the utility organization is continually supplied to operators and other personnel and is incorporated into training and retraining programs. These procedures shall:

(1) Clearly identify organizational responsibilities for review of operating experience, the feedback of pertinent information to operators and other personnel, and the incorporation of such information into training and rettaining prograss; (2) Identify the adninistrative and technical review steps necessary in translating recommendatiens by the operating experience assessment group into plant actions (e.g., changes to procedures, operating crde rs) ;

(3) Identify the recipients of various categories of inforration f rom operating experience (i. e. ,

supervisory personnel, shift technical advisors, operators, maintenance personnel, health physics technicians) or otherwise provide means through which such information can be readily related to the job functions of the recipients; (4) provide means to assure that affected personnel become aware of and understand information of sufficient importance that should not wait for emphasis through routine training and retraining prog rams; (5) Assure that plant personnel do not routinely receive extraneous and unimportant information on operating experience in such volume that it would obscure priority information or otherwise detract from overall job perf ormance and -proficiency; (6) provide suitable checks to assure that conflicting or contradictory information is not conveyed to operators and other personnel until resolution is reached; and,

(7) Provide periodic internal audit to assure that the feedback progran functions effectively at all levels.

This requirement shall be implemented prior to issuance of an operating license.

X.1.12.2 Interpretation None required.

I.1-15

X.1.12.3 113eenent of_Rosconse PPSL has developed a comprehensive program for feedback of operating experience. Components of the program are as follows.

Operating experience from other utilities and other industry sources is initially reviewed and dispositioned by the Industry Events Review Program (IERP). The IEEP is designed to assure plant personnel do not routinely receive extraneous and unimportant information, that information is not contradictory or conflicting, that information is resolved prior to dissemination and that important information is rapidly routed to the appropriate personnel. A description of the organiration, responsibilities and procedures of the IIRP can be found in Nuclear Department Instruction NDI-6.2.2.

The Shift Technical Adviser (STA) as part of the Operations Assessment Function will be the focal point for dissemination of operating experience information to appropriate plant personnel.

This will include:

o Feedback of pertinent information to operators and other station personnel and transmittal of inf orma tion to the Nuclear Training Group for incorporation into appropriate training programs.

o . Initiating, when required, plant procedure changes and/or plant modification requests.

o Discussing with shift personnel operating experience information of sufficient importance that it cannot be deferred to the retraining program.

o Editing information provided to plant personnel to minimize excessive or conflicting information and distributing information to appropriate functional units.

Procedures are being developed to further define this f unction and the interfaces among the STAS and the Nuclear Safety Assessment Group, Nuclear Training, Operations and the Industry Events Beview Program.

General information from the nuclear industry and information of general interest from inside the company will be disseminated to appropriate personnel. The details of this program are described in Nuclear Department Instruction NDI-6.2.1.

The NQA organization will audit selected portions of the feedback program to assure it functions ef fectively at all levels.

I.1-16

X.1.13 7ERIFY COERECT PERFORM ANCE OF OPER ATING ACTIVITIES (I. C. 6 )

I.l.13.1 statement of_ Requirement Licensees' procedures shall be reviewed and revised, as necessary, to assure that an effective system of verif ying the correct performance of operating activities is provided as a means of reducing human errors and improving the quality of normal operations. This will reduce the frequency of occurrence of situations that could result in or contribute to accidents.

Such a verification systes may include automatic systes status

=onitoriag, human verification of operations and maintenance activities independent of the people performing the activity (see NUREG-0585, Recommendation 5), or both.

Implementa tion of autcmatic status monitoring if reIuired will reduce the extent of human verification of operations and maintenance activities but will not eliminate the need for such verification in all instances. The procedures adopted by the licensees may consist of two phases--one before and one af ter installatica of automatic status monitoring equipment, if required, in accordance with ites I.D.3.

Procedures must be reviewed and revised prior to fuel load.

X2 1 13.2 Interpretation None required.

I.l.13.3 Statement of Response Administrative controls have been identified which will provide verificatien of correct performance of surveillance and maintenance activities. Implementation is being developed in the form of an Operations Instruction. Status verification will utilize control room indications presently available, operability testing where appropriate, or independent verification by a second qua lified person. The Instruction will define circumstances when independent human verification is required.

The Instruction will also incorporate the requirements of item II.K.l.10 (see Subsection X.2.26) for the removal from and restoration to service of safety related systems and components during normal operations and maintenance activities.

X .1.14 NSSS 7ENDOR REVIEW OF PROCEDURES (I. C. 7)

No requirement stated in NUREG 0737. Refer to subsection X.2.12 which contains the response to the requirement in NUREG 0694.

X .1.15 PILOT MONITORING OF SELECTED EMERGENCY PROCEDURES FOR NEAR TERM OPERATING _ LICENSES (I. C. 8) i X.1-17

No requirement stated in NUREG 0737. Refer to Subsection X.2.13 which contains the response to the requirement in NUZEG 0694 I.l.16 CONTROL RccM DESIGN REVIEW (I.D.1L X.1.16.1 Statement of Requirement All licensees and applicants for operating licenses will be required to conduct a detailed control-room design review to identify and correct design deficiencies. This detailed control-room design review is expected to take about a year. Therefore, the Office of Nuclear Reactor Regulation (N R R) requires that those applicants for operating licenses who are unable to complete this review prior to issuance of a license make preliminary assessments of their control rooms to identify significant human f actors and instrumentation problems and establish a schedule (to be approved by NBC) for correcting deficiencies. These applicants will be required to complete the more detailed control room reviews on the same schedule as licensees with operating plants.

Applicants will find it of value to refer to the draft document NUREG/CR-1580, " Human Engineering Guide to Control Room Evaluation," in performing the preliminary assessment. NRR will evaluate the applicants preliminary assessments including the performance by NRR of onsite review / audit. The NRR onsite review / audit will be on a schedule consistent with licensing needs.

1his requirement shall be met prior to fuel load.

1.1.16.'2 Int e rpre ta t _ ion Applicants for operating licenses are required to pe rf orm a preliminary control room design assessment which should be based on NUREG/CR-1580. This assessment will be reviewed by the NRC, who will subsequently recommend changes for correcting deficiences. Applicants must submit f or NRC approval a schedule for correcting these deficiencies.

Applicants will be required to perform a detailed control room design assessment following NUREG 0700 issuance. This assessment is not required to be completed prior to issuance of an operating license.

X.1.16.3 statement of_gesponse A detailed control room review to identify significant human f actors . problems was conducted b y PP&L with assistance from experienced human factors personnel from General Physics Corporation. This review was based on the criteria given in draft NUREG/CR-1580.

X.1-18

During the usek of October 27, 1980, the NRC performed an onsite l review of the Susquehanna contrcl room. The results of this review were formally transmitted to PPSL on January 31, 1981. A meeting was held on February 3, 1981 in Bethesda to discuss and clarify the NRC findings. On February 27, 1981 PPSL submitted a formal response to all NRC findings (ref e r to PL A-648) . This response included a schedule for implementing the findings addressed in the NRC report.

X.1.17 PIANT SAFETY PARAMETER DISPtAY CONSOLE (I. D. 2L X.l.17.1 Statement of Reguirement Each applicant and licensee shall install a safety parameter display system (SPDS) that will display to operating personnel a minimum set of parameters which define the safety sta tus of the plant. This can be attained through continuous indication of direct and derived variables as necessary to assess plant safety status.

The implementation date will be announced with the issuance of NUREG-0696.

X.1.17.2 In terpre ta tion None required.

X.l.17.3 Statement of Response The response to this requirement will be incorporated into Appendix I of -the Emergency Plan following issuance of NUREG 0696.

X.1.18 TRAINING DURING LOW-POWEB_ TESTING (I. zG ll No requirement stated in NUREG 0737. Refer to Subsection X.2.15 which contains the response to the requirement in NUREG 0694.

X.1.19 REACTOR COOLANT SYSTEM VENTS (II.B.ll I.1.19.1 Statement of Requirement Each applicant and licensee shall install reactor coolant system (RCS) and reactor pressure vessel (RPV) head high point vents remotely operated from the control room. Although the purpose of the system is to vent noncondensible gases from the RCS which may inhibit core cooling during natural circulation, the vents must not ' lead to an unacceptable increase in the probability of a loss-of-coolant accident (LOCA) or a challenge to containment integrity. Since these vents form a part of the reactor coolant pressure boundary, the design of the events shall conform to the X.1-19

rejuiroments of Appendix A to 10 CFR Part 50, " General Design Cr.teria." The vent system shall be designed with suf ficient redundancy that assures a low probability of inadvertent or irreversible actuation.

Each licensee shall provide the following inf or:ation concerning the design and operation of the high point vent system:

(1) Subsit a description of the design, loca tion , size, and power supply for the vent syste: along with results of analyses for loss-of-coolant accidents initiated by a break in the vent pipe. The results cf the analyses should demonstrate co:pliance with the acceptance criteria of 10 CFR 50.46. -

(2) Submit procedures and supporting analysis for operator use of the vents that also include the information available to the operator for initt.ating or ter=inating vent usage.

Documentation shall be submitted by July 1, 1981. Modifications shall be completed by 1, 1982.

I.1.19.2 Intern;etation Ncne required.

I.1.19.3 Statement of Response The present design of reactor coolant and reactor vessel vent systems meet these requirements.

The RPV is equipped with various means to vent the reactor during all modes of operation. All the valves involved are safety grade, powered by essential busses and are capable of remote sanual operation from the control room.

The largest portion of non-condensables are vented through sixteen (16) safety relief valves (PSV 141F013A-S) mounted on the main steam lines. These power operated relief valves satisfy the intent of the NRC position. Information regarding the design, qualification, power source of these valves has been provided in Sections 5.1, 5.2.2, 6.2, 6.3, 7.3 and 15.

In addition to power operated relief valves, the RPV is equipped with various other means of high point venting. These are:

1. Normally closed RP7 head vent valves (HV141-F001 and F002) , operable from control room which discharges to drywell equipment drain tank. (subsection 5.1 and Figure 5.1-3a) .

I.1-20

2. Normally open reactor head vent line 2 D3A-ll2 which discharges to main steas line "A". (Subsection 5.1 and Figure 5.1-Ja) .

3. Main steam driven ECIC and HPCI systes turbines, operable from the control roos which exhaust to suppressica pool. (Subsections 5.3, 6.3 and Figures 5.4-94, 6.3-la).

Although t he power operated relief valves f ully satisf y the intent of the NRC requirement these other :eans also provide protection against accusulation of non-condensables in the BPV.

The design of the RCS and HP7 vent systems is in agree ent with the generic capabilities proposed by the 372 Owners' G ro u p , with the exception of isclation condensers. SSES is not equipped with isolation condensers. The BWR Owners' Group position is su=sarized in NEDO-24782.

Operation of the equipment described above during abnormal operating conditions is controlled by the Energency operating Procedures. While these procedures do not specifically address venting of non-condensable gases, they do address proper utilization of equipment to recover from undesirable conditions presented by the presence of non-condensables or by other circusstances.

~ The BCS an d RPV vent systems are part of the original SSES design basis. A pipe break in either of these systems would be the case as a small mainsteam line break. A complete mainsteam line break is within the design basis ,see subsections 6.2.1.1.3.3.2 and 6.3.3). Smaller size breaks have been shown to be of lesser severity (see Subsections 6. 2.1.1. 3. 3. 5 a nd 6. 3. 3. 7. 3) .

Therefore, no new supporting analysis is necessary in response to NUREG 0737. In addition, no new 10CF350.46 conformance calculations or containment combustible gas concentration calculations are necessary. Non-condensable gas releases due to a vent line break would be no more severe than the releases associated with a mainsteam line break. Mainsteam line break

' analyses included continuous venting of non-condensable gases with high hydrogen concentrations. These analyses demonstrate confo rmance to 10CFH50.46.

I.l.20 Plant Shielding (II. B. 2)

I.1.20.1 Statement of Hequirement With the assumption of a postaccident release of radioactivity equivalent to that described in Regulatory Guides 1.3 and 1.4 (i.e., the equivalent of 50% of the core radioicdine, 100% of the core noble gas inventory, and 1% of the core solids are contained in the primary coolant), each licensee shall perfors a radiation and shielding-design review of the spaces around systems that may, as a result of an accident, contain highly radioactive saterials. The design review shculd identif y the location of I.1-21

vital areas and equipmento such as the control roos, radwaste control stations, emergency powe r supplies, sotor con trol centers, a nd instr :ent areas, in which personnel occupancy say be unduly limited or safety equipment say be unduly degraded by the radiation fields during postaccident operaticas of these syste=s.

Each licensee shall provide for adequate access to vital areas and protection of safety equipment by design changes, increased permanent or temporary shielding, or postaccident procedural controls. The design review shall determine which types of corrective actions are needed for vital areas thorughout the facility.

X.1.20.1.1 _ Documentat ion Requ ired for Vital _ Area Access For vital area access, operating license applicants need to provide a sussary of the shielding design review, a description of the review results, and a description of the sodifications made or to be sade to i=plesent the result of the review. Also to be providad by the licensee:

(1) Source ter=s used including ti e after shutdown that was assumed for source teras in systess.

(2) Systems assumed to contain high levels of act. Tity in a post-accident situation and jusitification for excluding any of those given in the " Clarification" of NOREG 0737.

(3) Areas assumed vital for post-accident operations including justification for exclusion of any of those given in the

" Clarification" of NUHZG 0737.

(4) Projected doses to individuals for necessary occupancy times in vital areas and a dose rate map for potentially occupied areas.

I.1.20.1.2 Documentation Required for Equipment Ou ali fica t ion II.B.2 states, " Provide the information requested by the Commission Memorandum and Order on equipment qualification (CLI-8 0-21) . " This memorandum, with regard to equipment q ualifica tion, requests information on environsental qualification _ of safety related electrical equipment.

I.1.20.2 In te rpreta t ion '

4.1.20.2.l__ source Terms The source ters for recirculated depressurized coolant need not be assumed to contain noble gases, therefore the RH3 shutdown cooling systes which may initiate at low reactor pressure only X.1-22

will be assumed to contain solely halogens and particulates. The HPCI and LPCI systems do not recircula te reactor coolant but, rather, su ppression pool water. They will also be essentially void of noble gases.

Leakage from systems outside of containment need not be considered as potential sources. Also, containment and equipment leakage (f rom systems outside containment) need not be considered as potential airborne sources within the reactor building. It follows that airborne sources and any other uncontained sources in the reactor building do not need be considered in this shielding review.

f.l.20.2.2 _ Post-Accident Systems The standby gas treatment system, or equivalent, is given as a system which may contain high levels of radioactivity af ter an accident. Airborne activity from leakage of equipment outside containment has been clearly established as being outside the review requirements. Drywell leakage must then provide the activity processed by the SGTS. This review will assume the drywell does indeed leak to the reactor building to provide a source within the SGTS. However, this airborne source will not be evalutted any further in the review.

X .1. _2 0. 2. 3 Equipment Oualification

-Provide a description of the environmental qualification program and results for safety related electrical equipment both inside and outside of containment. It is our understanding that radiation qualification of non-electrical safety related equipment need not be reported.

X.lz 20.3 Statement of Response The required post-accident study is divided inte two parts; one dealing with a summary of the shielding design review plus vital l

area access, another dealing with equipment qualification. A summary of the shielding design review, results, and methodology used to determine radiation doses is presented below. The results of the equipment qualification program are scheduled to be submitted in April 1981 in revision 2 of the SSES Environmental Qualification Report for Class lE Equipment.

The results of the shielding review of contained sources are that l all vital areas are accessible post-accident and no shielding modifications are necessary to comply to NUREG 0737.

I.l.20.1.1 Introduction X.1-23

If an accident is postulated in which large amounts of activity are released from the reactor core, then pathways exist which can transfer this activity to various areas of the reactor building.

These large radiation source terms present a hazard regarding potentially high doses to personnel. In order to deal with this probles it has become necessary to quantify these source terms, trace their presence and determine their ef fects on the ef ficient perforsance of post-accident recovery operations. To this ead, the plant shielding of the Susquehanna Steam Electric Station, Units 1 and 2, has been reviewed for post-accident adequacy.

This summary presents the analytical bases by which the review was carried out. Systems required or postulated to process primary reactor coolant outside the containment during post-accident conditions were selected for evaluation. La rge radiation sources beyond the original selected systems. Radiation levels in adjacent plant areas due to contained sources in piping and equipment of these systems were then estimated to yield the desired information. Also included herein is a discussion of radiation exposure guidelines for plant personnel, identification of areas vital to post-accident operations and availability of access to these areas.

As a byproduct of this review, several radiation mone maps and associated curves have been produced. The ma ps will allow operations personnel to identify potential high exposure vital areas of the plant should an accident occur which contaminates the systes considered in this study. The curves will allow them to estimate radiation levels in these areas at varicas tines following an accident.

I.l.20.3.2_ Design Review Bases X.1.20.3.2.1 Sva cess Selected for_Shieldino Review A review was made to determine which systems could be required to operate and/or be expected to contain highly radioactive materials following a postulated accident where substantial core damage has occurred. The documentation governing the approach to the shielding review is NUREG-0737.

A review of containment isolation provisions was conducted in accordance with ites II.E.4.2. This was done to assure isolation of non-essential systems penetrating the containment boundary.

Thus, systems other than those identified as having a specified function fcilowing an accident are assumed not to contais post-accident activity and da not need to be considered in the shielding review.

X.1.20.3.2.1.1 Core Spray, HPCI, RCIC and_HHR_(LPCI model The core Spray, HHH (IPCI mode) , HPCI (water side) and RCIC (water side) systems would contain suppression pool water being I.1-24

injected into the reactor coolant system. Although the HPCI and RCIC systems could also draw from the condensate storage tank, suppression pool water is assumed to be their only source of water for injection. The steam sides of the HPCI and RCIC systems would operate on reactor steam and would not be required when the reactor is depressurized. However, as a first estimate for equipment qualification, it is assumed tha t these systems should also be available until one year post-accident.

I.l.20.1.2.1.2 RER (Shutdown Coolin2_jodel The RHR system recirculates reactor waste when it operates in the shutdown cooling mode. O peration in this modo requires that the reactor be in depressurized condition. Depressurization is expected to remove substantially all of the noble gases released into the reactor coolant whether it be by direct venting to the drywell or by quenching reactor steam in the suppression pool.

Another consideration is, following a postulated serious accident, the HPCI, RCIC, RHH (LPCI Mode) and/or Core Spray systems would inject a substantial amount of water into the reactor coolant system. This shielding review will assume that there are no noble gases in the reactor water in the RHR system from the shutdown cooling mode. However, since the exact amount of dilution of the reactor water is dif ficult to determine, no dilution in addition to the reactor coolant volume is assumed.

_1.1.20.3 2.1.3 RHR (Supprossion_ Pool Cooling Model The RHR system in this modo circulates and removes heat f rom suppression pool water to prevent pon1 boiling. This assures availability of suppression pool wa ter as a source for cooling the reactor and increases the efficiency of a given cooling operation with this source.

I.l.20.3.2.1.4 RHR (Containment Spray Model Under post-accident conditions, water pumped tram the suppression pool through the RHR heat excnanger may be diverted to spray header system loops located high in the drywell and above the suppression pool. This mode of operation provides the ability to reduce dryvell pressure by condensing atmospheric steam while cooling the suppression pool water. No credit is taken for spray removal of iodines.

I.l.20.3.2.1.5 CRD Hydraulic System The operation of the CBD system was reviewed to determine if the scram discharge headers will contain highly radioactive water following a postulated accident. Prior to a scram the CRD housings contain condensate water delivered by the CRD pumps.

When a scram occurs some of this condensate water f rom the CRD is I.1-25

discharged to the scran discharge header. After the scras, some condensate and reactor water flows to the scras discharge header which fills in a matter of a few seconds.

Since the vents and drains in the scras discharge headers are isolated by the scras, all discharge flow then stops. Since it is not reasonable to assume that significant core damage occurs in the first few seconds following a scras, the scras discharge header will initially contain only a mixture of condensate and pre-accident reactor water following this postulated accident.

After the reactor scram, the scras discharge a nd instruseat volumes will contain about 700 gallons of pre-accident water, isolated by a single drain valve leak tested to 20 cc/hr. If the initial scras closed the drain valve, then this leakage is insignificant campared to the scram discharge volume and insignificant as a post-accident concern. If the drain valve f ails to close, operator action is required to reset the scras and close the sof t-seated scras discharge valve. If this action is not taken or fails to close the valve, then post-accident sources can enter the liquid radwaste systes by leaking past the CED seals. The CRD withdraw line does not directly cossunicate with the reactor coolant.

In light of the anticipated small leak rates and the lack of single f ailure criteria consideration requirements, the scran discharge drain valve was assumed to remain cloced and any leakage was disregarded.

I.1.20.3.2.1.6 RWCU Systes For a major accident with resulting core damage, the R9CU system would automatically isolate on a low reactor coolant level signal and would contain no highly radioactive materials beyond the second isolation valve. Since the cleaning capacity for this system is small, it would be impractical to use it for TMI type accident recovery and it is excluded from this shielding review.

12 1 20.3.2.1.7 Liquid _ Radwaste Systes Equipment drains and compartment floor drains servicing ECCS systems are isolated from the reactor building sump. All piping that may contain high activity post-accident water is also isolated from the reactor building sump and radwaste systess.

CBD system isolation is discussed in Section I.1.20.3.3.1.5.

Since no significant amounts of post-accident activity can reach the liquid radwaste system, it is excluded fros this shielding review.

l I.l.20.3 221z9 MSIV_ Leakage _ Control System Subsequent to a postulated accident, system operation may begin upon actua tion of the manual Evitches in the control room. Th is l

l X.1-26

systen may only be activated upon a permissive reactor pressure signal (35 psig). The method used to depressurize the reactor to this level has a large effect on the amount of activity potentially available f or passage through this system. For example, the HPCI system can deplete the reactor steam activity considerably with only a f ew min utes opera tion. Whichever depressuriza tion me thod is chosen, the MSIV-LCS system remains as one that must be included in the shielding review.

_X.1. 2 0. 3. 2 .1. 9 Sampling Systess Systems required or desired for post-accident use include the existing Reactor Sampling System, the Containment Atmosphere Monitoring System, and Post- Accident Sa mple Sta tion. Each of these systems / stations may contain post-accident sources and are ,

included in the shielding review. The post-accident sampling station location is still under study. (When this siting is finalized, the appropriate subset of Figures X.1.20-1 to 8 will be updated to indicate location and local area dose rates) .

131 20.3.231.10 Standby __Gac_ Treatment Syste3 The Beactor Building Hecirculation system is used af ter an accident. This disperses airborne activity throughout the reactor building and refueling floor. The SGTS system collects airborne activity, concentrating halogens within the charcoal filters while releasing noble gases outside the secondary co nta in men t. The charcoal filter is considered to be a source of contained activity and is included in this shielding review. The assumptions used in determining this contained source are:

1) Drywell leakeage at 1% per day.

2) SGTS process rate of 1 reactor building / refueling floor volume per day.

3) 99% charcoal filter efficiency for halogens. 0% charcoal filtet efficiency for noble gases.

i X.1.20,3.2.2 Radioactive Source Release Fractions The following release fractions were used as a tasis for determining the concentrations for the shielding review:

l Source A: Containment A tmosphere: 100% noble gases, 25% halogens l

l Source B: Beactor Liquids: 100% noble gases, 50% halogens, 1% solids Source C: Suppression Pool Liquid 50% halogens, 15 solids Source D: Beactor Steam: 100% noble gases, 25% halogens X.1-27

Tha above release fractions were a pplied to the total curies available for the particular chemical species (i.e., noble gas, halogen, or solid) for an equilibrium fission product inventory for Susquehanna as listed in Table X.1.20-1.

The Regula tory Guide 1.7 solids release fraction of 13 was used for Cs and Rb on this review. Further evaluations of the T.1I radioactivity releases may conclude that higher release fractions are approp riate. However, until the release mechanisms and release fractions have been quantified, the existing regulatory guidance will be followed. No noble gases were included in the suppression pool liquid (Source C) because Regulatory Guide 1.7 has also set this precedent in modeling liquids in the pool (See Ref. 3 and 9) . Furthermore, cursory analyses have indicated that

, the halogens dominate all shielding requirements and that ccatributions to the total dose rates f rom noble gases are negligible for the purposes of shielding design review.

X.1.202 3.2 2 3 Source Term Guantification Sectiou X.1.20.3.2.2 above outlines the assumptions used for release fractions for the shielding design review. These release fractions are, howe ver, only the first step in modeling the source terms for the activity concentrations in the systems under review. The important modeling parameters, decay time and dilution volume obviously also affect any shielding analysis.

The following sectious outline the rationale for the selection of values for these key parameters.

X.1.20.3.2.3.1 Decay Time i.

For the first stage of the shielding design review process, minimal decay time credit was used with the above releases. The primary reason for this was to develop a set of accident radiation zone maps normalized to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months decay.

M zl00 33 32 3.2 Dilutien Volume The volume used for dilution is important, affecting the l calculations of dose rate in a linear fashion. The following l

dilution volumes were used with the release fractions and decay times listed above to arrive at the final source terms for the i shielding review:

Source A: Erywell and suppression pool free volumes.

i Source B: Reactor coolant system normal liquid volume (based on reactor coolant density at the operating temperature and pressure).

Source C: The volume of the reactor coolant system plus the suppression pool volume.

i X.1-28

Source D: Ihe reactor steam volume.

131.20.3.2.4 System /Sogree Sumgagz o Core Spray System: Source C o High pressure Coolant Injection System Liquid: Source C Steam: Source D (with credit for steam specific activity reduction due to turbine operation) o Reactor Core Isolation Cooling System Liquid: Source C Steam: Source D (with credit for steaw specific activity reduction due to turbine operaticn) .

o Residual Heat Removal System LPCI Mode: Source C Shutdown Cooling Mode: Source B (with credit for noble gas release during vessel depressurization) .

Suppression Pool Cooling and Containment Spray Modes: Source C o Main Steam Isolation Yalve-Leakage Control Systen Steam: Source D (with credit for steam specific Activity reduction due to RCIC turbine operation) .

o Sampling Systems Containment air sample: Source A Reactor coolant sample: Source B o Standby Gas Treatment System Charccal filter: 1% per day dryvell leakage (See Section X.1. 20. 3. 2.1.10 for discussion of source assumptions) .

For each of these systems, piping associated with the appropriate operating mode was identified on PSID drawings and traced throughout the plant to their final destination.

1.1.20.3.2.5 Dose Integration Factors fog _ Personnel I.1-29

Cusculative radiation exposure to personnel in vital areas (continuous occupancy) is determined based upon a maximum one year exposure period. The integra ted doses a re modified using Ref. 7 occupancy factors listed below.

Time (daysl Occu2ancy_ Factors 0 to 1 1.0 1 to 4 0.6 over 4 0.4 Exposures for areas not continuously occupied (f requent and infrequent occupancy) must be determined case by case, that is, multiply the task duration by the area dose ra te at the time of exposure.

X,1 20.3.3 shielding Review Methodology K.1.20.3.3 2 1__, Radiation Dose Calculation Model The previous sections outlined the rationale and assumptions for the selection of systems that would undergo a shielding design review as well as the formulation of the sources for those systems. The next step in the review process was to use those sources alcag with standard point kernel shielding analytical techniques (Bef. 13 & 14) to estimate dose rates f rom those selected systems.

Scattered radiation (e.g. , shine over partial shield walls) was considered but was not significa nt since the not reduction in dose is several orders of magnitude and no vital area is separated from a high activity source solely by a partial vall.

Radiation levels.for compartments containing the systems under review were based on the maximum contact dose rate for any component in the compartment. Radiation levels in areas not containing unshielded sources were based on maximun dose rates transmitted into areas through walls of these adjacent l compartments. Checks were also made for any piping or equipment that could directly contribute to corridor dose rates, i.e.,

piping that may be running directly in the corridor or equipment / piping in a compartment that could shine directly into corridors with no attenuation through compartment walls. There is no field routed small piping (i.e., piping less than 2" in diameter) for ECCS systems.

Dose rates are cummulative and are summaa over all systems in simultaneous operation in most cases. Tne exce ption -is steam piping for the RCIC and HPCI systems. Both are high pressure systems and cannot be operated simultaneously with low pressure systems such as core spray. This becomes a moot point, since I.1-30

these steam lines are routed in vell shielded compartments, causing no appreciable personnel doses.

X.1.20.3.3.2 _ Post-Accident nadiation zone 312S One of the principal products of this review is the series of accident radiation zone maps (Figures X.1. 20-1 to S). The zone boundaries used in the :aps are defined in Table I.1. 20-2. The zone maps present the calculated dose rates at one hour after the accident due to the sources described in Section X.1. 20. 3. 2. 4 in various areas of the plant site. The princi pal sources of radiation in each area are identified in Table X.1.20-4 The dose rates presented do not include contributions f'ros normal operating sources which say be contained in the plant at the time of the accident since these contributions will be =inor outside of well defined and shielded areas. They also do not include dose rate contributions due to potential airborne sources resulting from equipsent or drywell leakage.

The 2cne maps were used to deter =ine the accessibility of vital areas described in Section I.1.20.3.3.4 X.1,20 2 32 3.3 Personnel Radiation Errosure Guidelines In order that doses to occupied areas take on meaningful proportions, it is necessary to establish exposure goals or guidelines. The general design basis for these guidelines is ICC?R50, Appendix A, GCC 19. That material addresses control room habitability, including access and occupancy under worst case conditions. Exposures are not to exceed 5 res whole body, or its equivalent to any part of the body, for the duration of any postulated accident. GDC 19 is also used to govern design bases for the maximum permissible dosage to personnel performing any task required post-accident. These requirements translate roughly into the objectives to be met in the post-acciden t review as given below.

Radiation Exposure Guidelines Occupancy Dose Rate Objectives Dose Objective Continuous 15 mR/hr 5 Res for duration Frequent 100 m2/hr 5 Bes for all activities Infrequent 500 aa/hr 5 Res per activity Accessway 5 a/hr Included in above doses 1.1.20.3.3.3 Vital Area Identification and Access 121.20.3.32 4.1 vital __Araa Clarification Vital areas are those a which will or may require occupancy to 7arait an operator to aid in the aitigation of cr recovery from I.1-31

an accident". Reference (15) further defines recovery from an accident as, "when the plant is in a sa fe and stable condition."

"This may either be hot or cold .6 ntdown, depending on th e situation." The 10 CFR 73.2 det ition of vital area shall not apply here.

For the purposes of this study, the evaluation to determine necessary vital areas considers all of those listed in Reference (2). Upon examination several plant areas were determined not to be vital. Instrument panels were excluded because essential equipment control and alignment has been established in the control roca and requires no local actions. The radwaste control room is excluded because 1) no local actions are required to prevent spread of postaccident sources into the liquid radwaste system; 2) gaseous radwaste processing is not required, and; 3) activity sources early in the post-accident transient are much too high to be effectively processed through the liquid and eventually solid radwaste systems. Also excluded are the post-LCCA hydrogen control system and the containment isolation reset control area (which are operator actuated from the main control room). Lastly the emergency power supply (i.e., diesel generators) was excluded since system initiation comes from the centrol room and requires no local actions.

The resulting list of areas considered vital f or post-accident operations at Susquehanna appears in Table X.1. 20-3. Note that security f acilities are included as vital areas with regards to maintaining plant security.

121.20.3.3,4.2 Vital AIea Accegg Those operator actions required post-accident were reviewed to assure that first priority safety actions can be achieved in the postulated radiation fields. This review assures that access is available and required operator actions can be achieved.

Ingress and egress area dose rates to those vital areas identified in Table X.1.20-3 were examined to assure compatibility with the areas being accessed. Access to the Post-Accident Sampling Station will be addressed when the location has been finalized.

X 1.20.3.4 Results X.1.20.3.4,1 Radioactive Dgcar Effects Besults of the radiation level evaluation f or the shielding design review are presented in Figures I.l.20-1 to 8. Table X.1.2 0-4 identifies the sources contributing to dose rates in .

each of the plant areas shown on those figures. This table can be used in conjunction with the decay curves (Figures X.1.20-9 and 10) to estimate radiation levels at times other than one hour. The procedure for times less than one day, is to multiply X.1-32 t

the radiation level (i.e., radiation sone limit) by the decay factor given in Figure I.1.20-9. For times greatar than one day, it is necessary to sultiply by the decay f actor in Figure X.1. 20-9 at 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and by the decay factor in Figure X.1.20-10 at the desired lecay time. This procedure is conservative for areas in which the sources are shielded because it does not rigorously take into account the softening of tne energy spectrus an consequent increase in attenuation for longer decay times. A decay curve for source D, reactor stea s, is not included because the depletion effects due to steam usage by HPCI or RCIC resoves such of this source shortly af ter the accident. In addition, HPCI and 3CIC piping containing source D is run in shielded cubicles and does not contribute significantly outside those cubicles.

_X .1. 2 0. 3. 4. 2 Integrated Person nel_ Exposures Personnel integrated exposures in continuously cccupied areas were calculated based on 100% occupancy for the first day, 60%

occupancy from day one throagh f our and 40% occupancy for the duration (1 year) . These calculations showed that personnel exposures would be within the design objective of 5 Res.

Exposures in Zones I, II and III of the control structure are 0.24, 1.6 and 3.1 Res, respectively. These doses do no include the shielding ef fects of interior walls, equipsent, etc.,

therefore they represent the maximus dose to control building personnel due to contained sources. Personnel doses to the North Gate House (ASCC) and Security Control Center from contained sources were found to be insignificant (i.e ,40.1 Res) . These areas are a sinisus of 300 feet from the reactor building whose walls are a ninimum of 2.5 feet of concrete. Personnel doses to the Post- Accident Sampling Station will be included in Table I.1.20-3 when the location has been finalized.

I,1.20.3.4 22 Reactor Building Accessibility The results show that the reactor building vill be generally inaccessible for several days af ter the accident due to contained radiation sources. High radiation levels can be expected at Elevation 645'- 0" (Figure I. l. 2 0- 2) regardless of which system (s) is (a re) in operation. Radiation levels at Elevation 719'-0" (Figure I.1.20-3) and above are expected to generally be within Zone IV limits if the core spray and 3HH contilicsent spray systems have not been operated following the accident. This is beccuse these are the only unshielded post-accident systes sources at these elevations. Other systes sources are contained in shielded cubicles.

Exceptions to these general Zone IV levels are areas in the vicinity of reactor coolant and containment atmosphere sampling lines which are routed to the reactor building sasple station at Elevation 779'-0". The dose rate 10 feet f rom the reactor I.1-33

coolane sa mpling line one hour a f ter the postulated accident may exceed 100 3/hr.

The relative inaccessibility of the reactor building does not present a problem as it does not contain any vital areas or systea components which require operator actions.

X.12 20.h4.4 Control Building Accessibili ty Results for contained radiation sources show that vital areas in the control structure are accessible post-accident.

121220.3.5 _g,efg m ces

1) U. C. Nuclear Regulatory Commission, "TMI-2 Lessons Learned Task Force Status Report and Short-Term Recommendations" USNRC Report NUREG-0578, July 1979, Recommendation 2.1.6b.

2) U.S. Nuclear Regulatory Commission, "NRC Action Plan Developed as a Result of the T3I-2 Accident," USNRC-0660, Vols. 1 and 2, May 1980,Section II.B.2.

3) Letter from D. G. Eisenhut (N RC) to All Licensees of Operating Plants and Applicants for Operating Licenses Gud Holders of Construction Permits, subject: Preliminary Clarification of T5I Action Plan Requirements, dated Septe mber 5,1980.

4) U.S. Nuclear Regulatory Commission, "Cla rification of TMI Action Plan Requirements," USNRC Report NUREG-0737, November, 1980, Item II.B.2.

5) U.S. Nuclear Regulatory Commission, IE Bulletin No. 79-OlB,

" Environmental Qualification of Class IE Equipment", January 14, 1980.

6) U.S. Nuclear Regulatory Commission, "Inte rim Staf f Position

, on Environmental Qualification Report NUREG-0588, December 1979.

' ~

7) USNRC Standard Review Plan 6.4, "dabitability Systems",

Revision 1.

8) USNRC Regulatory Guide 1.3, " Assumptions Used for Evaluating the Potential Radiolcgical Consequences of a Loss of Coolant Accident for Boiling Water Reactors", Revision 2, June 1974.

9) USNRC Regulatory Guide 1.7, " Control of Combustible Gas Concentrations in Containment Following a Loss-of-Coolant Accident," Revision 2, November 1978.

1.0) USNRC Regulatory Guide 1.89, "Qualificaticn of Class IE Equipment for Nuclear Power Plants," November 1974.

X.1-34

11) Ccde of Federal Regulations, 10CFR Part 50, Appendix A, GDC 19, Revised as of January 1, 1980,

12) C. Michael Lederer, et al., Table of Isotoons , Lawrence Radia tion Laboratory, University of California, March 1968.

13) D. S. Duncan and A. B. Spear, g3AgI_I - An I3M 704-709 2I2SISS E221dn f9I_Computigg_ Gamma _Egy__Atteg3ation and E231133_1g_3pactor Shields 4 Atomics International, (June 1959) .

14) D. S. Duncan and A. B. Spear, SR_ ACE _II - An IB1 709 Proggag i for Cggg311gg_Gggma_ Ray Attenuation and Heattnq in ElliadI1 cal _and Sphegical Geometries t_ Atomics In'.ernational t Jovemggg_1959,

15) Memorandum of Telephone Conversation, S. Ford of LIS to N. !

Anderson of NBC's Lessons Learned Task Force,

Subject:

TMI Requirements at SHNPP, April 9, 1980.

16) USNRC Regional Meeting Minutes, Region I,

Subject:

TMI Review Requirements at SHNPP, April 9, 1980.

17) USNRC Regional Meeting Minutes, Region IV and V,

Subject:

TMI Review Requirements, 9/26/79.

4 1

I 4

e I.1-35

~ . .w. - - - .

i TABLE X.1.20-1 INITIAL CORE ISOTOPIC INVENTORY (1)

Isotope Curies Isotope Curies Isotope Curies I--131 8.66+7(2) Y---93 1.82+8 TE-129 2.38+7 I--132 1.29+8 Y---94 1.61+8 TE131M 1.31+7 I--133 1.99+8 Y---95 1.84+8 TE-131 7.74+7 I--134 2.32+8 ZR--95 1.84+8 TE-132 1.29+8 I--135 1.82+8 ZR--97 2.86+8 TE133M 1.40+8 I--136 9.22+7 NB-95M 3.81+6 TE-133 8.93+7 BR--83 1.52+7 NB--95 1.91+6 TE-134 2.05+8 BR--84 2.74+7 NB-97M 1.78+8 CS-137 1.13+7 BR--85 3.34+7 NB--97 1.85+8 CS-138 1.90+8 KR-83M 1.55+7 MO--99 1.84+8 CS-139 1.93+8 KR-85M 3.87+7 MO-101 1.49+8 CS-140 1.76+8 KR--85 1.31+6 M0-102 1.19+8 CS-142 9.22+7 KR--87 7.44+7 MO-105 2.05+7 BA137M 1.75+8 KR--88 1.04+8 TC-99M 1.63+8 BA-139 1.87+8 KR--89 1.37+8 TC-101 1.49+8 BA-140 1.87+8 XE133M 5.06+6 TC-102 1.23+8 BA-141 1.87+8 XE-133 1.98+8 TC-105 2.65+7 BA-142 1.71+8 XE135M 5.36+7 RU-103 8.93+7 LA-140 1.87+8 XE-135 1.87+8 RU-105 2.68+7 LA-141 1.90+8 XE-137 1.79+8 RU-106 9.84+7 LA-143 1.74+8 XE-138 1.76+8 RU-107 5.65+6 LA-142 1.74+8 SE--81 4.17+6 RH103M 8.93+7 CE-141 1.90+8 SE-83M 8.63+6 RH105M 5.6246 CE-143 1.75+8 :

SE--83 6.55+6 RH-105 2.68+7 CE-144 1.45+8 SB--84 2.92+7 RH-106 1.16+7 CE-145 1.15+8 RB--88 1.07+8 RH-107 5.65+6 CE-146 8.81+7 RB--89. 1.42+8 SN-127 3.27+6 PR-143 1.75+8 RB--90 1.72+8 SN-126 1.75+1 PR-144 1.49+8 KB--91 1.62+8 SN-128 1.10+7 PR-145 1.15+8 RB--92 1.31+8 SN-130 5.95+7 PR-146 9.14+7 SR--89 1.42+8 SB-127 3.87+6 ND-147 6.70+7 SR--90 1.14+7 SB-128 1.64+7 ND-149 3.24+7 SR--91 1.73+8 SB-129 2.20+7 ND-151 1.19+7 SR--92 1.58+8 SB-130 5.95+7 PM-147 3.45+7 SR--93 1.67+8 SB-131 8.03+7- PM-149 3.24+7 SR--94 1.28+8 SB-132 9.97+7 PM-151 1.25+7 Y-- 1.72+8 SB-133 1.01+8 SM-151 2.70+5 Y--91M 1.0l+8 TE127M 1.04+6 SM-153 4.70+6 Y---91. 1.70+8 TE-127 3.87+6 Y---92 1.76+8 TE129M 1.04+7 (1) Based on 1000 reactor operating days at 3440 MWt. Reference GE Internal Report Document, " Summary of Fission Yield for U-235, U-238, and PU-239," published

-by Meek and Rider, June, 1977.

.(2) -8.66+7 = 8.66x107 .

X.1-36

TABLE X.1.20-2 RADIATION ZONE CLASSIFICATION (1)(2)

Radiation Maximum Zone ,

Dose Rate I < 15 mR/hr II I 100 mR/hr III I 500 mR/hr IV 5 5 R/hr V < 50 R/hr VI I 500 R/hr VII {5000 R/hr

.VIII > 5000 R/hr Notes:

1. Based on maximum contact dose rate for zones containing radiation sources.

2. Based on maximum field dose rate for zones with radiation fields caused by sources located outside the area.

-X.1-37.

TABLE X.l.20-3 VITAL AREAS Radiation TID State of Occupancy Figure Symbo_1, Zone (rem)

Continuous Main Control Room X.1.20-5 A.1 I 0.24 Technical Support Center X.1.20-5 A.2 I 0.24 Operations Support Center X.1.20-5 A.3 II 1.6 North Gate House (ASCC) X.1.20-1 A.4 I <0.1 Security Control Center X.1.20-1 A.5 I <0.1 Emergency Operations Facility (*) X.1.20-1 A.6 I <0.1 As Required Post-Accident Sampling 4

1) Sample Station (later) Bel (later) (later)

2) Analysis Station (later) B.2 (later) (later)

3) Plant Vent Sampling Station X.1.20-8 B.3 (later (later)

(*}Information regarding the EOF may be found in Appendix I of the SSES Emergency Plan.

x .1 -38

TABLE X.1.20-4 PRINCIPAL _D05E RATE CONTRIBUTORS IN PLANT AREAS Structure Area Dominant System (Source)

1) Reactor Building Elev. 645'-0" Wetwell Suppression pool water (C) to 670'-0" EPCI HPCI (C, D)

RCIC RCIC (C, D)

RHR RER Cooling Mode (B)

Core Spray Core Spray (C)

Sump Room RHR Cooling Mode (B)

Elev. 670'-0" Wetwell Drywell (A) to 683'-0" RHR RHR Cooling Mode (B)

Accessway Core Spray (C), RCIC (C),

HPCI (C)

Truck Port RHR Cooling Mode (B)

Railroad Port RHR Cooling Mode (B)

Other Areas Core Spray (C), RCIC (C),

HPCI (C)

Elev. 683'-0" Drywell Drywell (A) to 719'-1" Equip. Areas RER Cooling Mode (B)

Equip. Removal RHR Cooling Mode (B)

Areas Core Spray Piping Area Core Spray (C)

-Elev. 719'-1" Drywell Drywell (A) to 749'-1" Penetration Core Spray (C), RHR Spray Rooms Mode (C), MSIV-LCS (D)

Core Spray (C), RHR Spray Mode (C)

SW Equipment Core Spray (C)

Airlock Sout'a Switch- RHR Spray Mode (C) gear Room CRD Hatch RHR Spray Mode (C)

Elev. 749'-1" Drywell Drywell (A) to 779'-1" Penetration Core Spray (C), RHR Rooms and Spray Model (C)

Other Areas

2) Control. Building Elev. 656'-0" All Areas Core Spray (C), RHR to 806'-0" Cooling Mode (C)

Elev. 806'-0" All Araes . Standby Gas Treatment to 818'-0" Systems x.1-39

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X21521 70G-1&CIDEH S A MPlI'ic; II!.B d X2 1321.1 statosant o f R*2uira:en t l A design and operational review of the reactor coolant and l ccatain ent atsosphere sampling line syste:s shall be performed to determine the capability of personnel to promptly obtain (less l than 1 hour) a sasple under accident conditions without inc2rring a radiation exposure to any individus1 in excess of 3 and 13-3/4 res to the whole body or extremities, respectively. Accident conditions should assu=e a 29gulatory Guide 1.3 or 1.4 release of fission products. If the review indica tes tha t personnel could not promptly and safely obtain the sa:ples, additional design features or shielding should be provided to meet the criteria. A design a nd operational review of the radiological spectru: analysis facilities shall be perfor:ed to deter:ine the capability to promptly quantify (in less than 2 hours) cartain radionuclides that are indicators of the degree of core danage. Such radionuclides are noble gases (which indicate cladding f ailure) , lodines and cesiums (which indicate high fuel tem pe ra tu r es) , and nonvolatile isotopes (which indicate fuel zelting) . The initial reactor coolant spectru: should correspond to a Regulatory Guide 1.3 or 1.4 reletse. The review should also consider the effects of direct radiation from piping and components in the auxliary building and possible conta ination and direct radiation f ros airborne effluents. If the review indicates that the analyses required cannot be perfoe=ed in a prompt manner with existing equip =ent, then design modifications for equipment procure:ent shall be undertaken to seet the criteria. In addition to the radiological analyses, certain chemical analyses are necessary f or zonitoring reactor cc oditions. Procedures shall be provided to perform boron and chloride chemical analyses assuming a highly radioactive initial sample (Regulatory Guide 1.3 or 1.4 source ters) . Both analyses shall be capable of being completed promptly (i . e . , the boron sample analysis within at hour and the chloride sample analysis within a shift). The following items are clarifications of requiresents identified in NUREG-0578, NUREG-0660, or the Septe=ber 13 and October 30, 1979 clarification letters. (1) The licensee shall have the capability to promptly chtain reactor coolant samples and containment atsosphere samples. The combined time allotte-1 for eaupling and analysis should be 3 hours or less f ro: the time a decision is made to take a sample. (2) The licensee shall establish an onsite radiological and chemical analysis capability to provide, within the 3-hour time frase established above, quantification of the following: I.1-50

I (a) certain radionuclidos in the reactor coolant and containment atmosphere that may be indicators of the degree of core damage (e.g. , noble gases; iodines and cesiums, and nonvolatile isotopes) ; (b) hydrogen levels in the containment atmosphere; (c) dissolved gases (e. g. , hydrogen) , chloride (time allotted for analysis subject to discussion below) , and boron concentration of liquids. (d) Alternatively, have inline monitoring capaoilities to perform all or part of the above analyses. (3) Reactor coolant and containment atmosphere sampling during postaccident conditions shall not require an isolated auxiliary system (e. g. , the letdown system, reactor water cleanup system to be placed in operation in order to use the sampling system. (4) Pressurized reactor coolant samples are not required if the licensee can quantify the amount of dissolved gases with unpressurized reactor coolant samples. The measurement of either total dissolved gases or hydrogen gas in reactor coolant samples is considered adequate. Measuring the oxygen concentration is recommended, but is not mandatory. (5) The time for a chloride analysis to be performed is dependent upon two factors: (a) if the plant's coolant water is seawater or brackish water and (b) if there is only a single barrier between primary containment systems and the cooling water. Under both of the above conditions the licensee shall provide for a chloride analysis within 24 hours of the sample being taken. For all other cases, the licensee shall provide for the analysis to be completed within 4 days. The chloride analysis does not have to be done onsite. (6) The design basis for plant equipment for reactor coolant and containment atmosphere sampling and analysis must assume that it is possible to obtain and analyze a sample without radiation exposures to any individual exceeding the criteria of GDC 19 (Appendix A, 10 CFR Part 50) (i.e., 5 ren whole body, 75 rem extremities). (Note that the design and operatienal review criterion was changed from the operational limits of 10 CFR Part 20 (NU R EG-0578) to the GDC 19 criterion (October 30, 1979 letter from H.R. Denton to all licensees) .) (7) The analysis of primary coolant samples for boron is required for PWas. (Note that Revisicn 2 of Regulatory Guide 1.97, when issued, will likely specif y the need I.1-51 l

for primary coolant boron analysis capability at BUR plants ) (8) If inline monitoring is used for any sampling and analytical capability specified herein, the licensee shall provide backup sampling through grab samples, and shall demonstrate the capability of analyzing the samples. Established planning f or analysis at offsite facilities is acceptable. Equipment provided for backup sampling shall be capable of providing at least one sample per day for 7 days following onset of the accident and at least one sample per week until the accident condition no longer exists. (9) Ihe licensee's radiological and chemical sa m ple analysis capability shall include provisions to: (a) Identify and quantify the isotopes of the nuclide categories discussed above to levels corresponding to the source terms given in Regulatory Guide 1.3 or 1.4 and 1.7. Where necessary and practicable, the ability to dilute samples to provide capability for measurement and reduction of personnel exposure should be provided. Sensitivity of onsite liquid sample analysis capability should be such as to permit measurement of nuclide concentration in the range from approximately 1 u Ci/g to 10 Ci/g. (b) Restrict background levels of radiation in the radiological and chemical analysis facility f rom sources such that the sample analysis will provide results with an acceptably small error (approximately a factor of 2) . This can be accomplished through the use of sufficient shielding around samples and outside sources, and by the use of ventilation system design which will control the presence of airborne radioactivity. (10) Accuracy, range, and sensitivity shall be adequate to provide pertinent data to the operator in order to describe radiological and chemical status of the reactor coolant systems. (11) In the design of the postaccident sampling and analysis capability, consideration should be given to the following items: (a) Provisions for purging sample lines, for reducing plateout in sample lines, for minimizing sample loss or distortion, for preventing blockage of sample lines by loose material in the RCS or containment, for appropriate disposal of the samples, and for flow restrictions to limit reactor coolant loss from a rupture of the sample I.1-52

l line. The postaccident reactor coolant and containment atmosphere following a transient or accident. The sample lines should be as short as possible to minimize the volume of fluid to be taken from containment. The residues of sample collection should be returned to containment or to a ciosed system. (b) The ventilation exhaust from the sampling station should be filtered with charcoal adsorbers and high-efficiency particulate air (HEP A) filters. Operating License Applicants--Provide a description of the implementa tion of the position and clarification including PSIDs, together with either (a) a summary description cf procedures for saaple collection, sample transfer or transport, and sample analysis, or (b) copies of procedures for sample collection, sample transfer or transport, and sample analysis, in accordance with the proposed review schedule but in no case less than 4 months prior to the issuance of an operating license. I.1.21.2 In te rpre ta tion None required. I.1.21.1 Statement of Response PPSL will comply with this requirement by (1) adding a dedicated post-accident sample station; (2) adding additional instrumentation to the on-site chemistry labora tory; and (3) contracting with an off-site laboratory on a contingency basis for selected chemical and radiochemical analyses. Design

   , documentation will be submitted by fuel load.        Modifications will
    .be completed by January 1, 1982. For modifications to plant
    ' systems and components such as addition of post-accident sampling capability, procedures are developed or revised as necessary and appropriate training is provided when the final design documents
 -   are approved and equipment is available for use.

I.l.22 TRAINING FOR MITIGATING CORE DAMAGE (II.B.4l I.1.22.1_ Statement of Requirement Licensees are required to develop and implement a training program to teach the use of installed equipment and systems to control or mitigate accidents in which the core is severely damaged. shift technical advisors and operating personnel f rom the' plant manager through the operations chain to the licensed operators shall receive all the training indica ted in Table I.1. 22-1. i I.1-53 l i i

Managers and technicians in the instrumentation and control, health physics, and chemistry departments shall receive training commensura te with their responsibilities. Applicants for operating licenses should develop a training program prior to fuel loading and complete perscanel training prior to full-power operation. X,1222.2 Interpretation None required. X.zlz22. 3 statement of_Eesponse I A course titled " Operations with Degraded Core Conditions" has j been developed by General physics Corporation. This course or a l similar one will have been given to all shift technical advisors and operations personnel f rom the plant manager through the operations chain to and including licensed recrators prior to fuel load to fulfill this training requirement. A course outline is provided in Table X.1.22-2.

Managers and technicians in instrumentation and controls, health physics, and chemistry will be given training commensurate with their responsibilities during accidents which involve severe core damage.

i f i i' l l k l l L X.1-54 {-

IABLE_1 1.22-1 THAINING CRITERIA POR M IT IG AT I?iG CORE CAMAGE A program is to be developed to insure that all operating personnel are trained in the use of installed plant systems to control or mitigate an accident in which the core is severely damaged. The training program should include the following topic s. A. Incore_ Instrumentation

1. Use of fixed or movable incore detectcrs to determine extent of core damage and geometry changes.

2. Methods for calling up (printing) incore data f rom the plant computer.

B. Jital_ Instrumentation

1. Instrumentation response in an accident environment; failure sequence (time to failure, method of failure) ;

indication reliability (actual vs. indicated level) .

2. Alternative methods of measuring flows, pressures, levels, and tem peratures.

a. Determination of reactor pressure vessel level if all level transmitters fail.

b. Determination of other reactor coolant system parameters if the primary method of measurement has failed.

I C. P rima ry Chemistry

1. Expected chemistry results with severe core damage; consequences of transferring small quantities of liquid outside containment; importance of using leak tight systems.

2. Expected isotopic breakdown for core damage; for clad l damage.

3. Corrosion effects of extended immersica in primary water; time to failure.

D. Radiation Monitoring

1. Response of Process and Area Monitors to severe damages; behavior of detectors when saturated; method for detecting radiation readings by direct measurement at detector output (overranged detector): expected accuracy of detectors a t dif ferenct lcca tion s; use of detectors to determine extent of core damage.

X.1-55

c-5

2. Methods of determining dose rate inside containment from measurements taken outside containment.

E. Gas Ggagration

1. Methods of hydrogen generation during an accident; other sources of gas (X e, Kr) ; techniques for venting or disposal of non-condensibles.

2. Hydrogen flammability and explosive limit; sources of oxygen in containment or reactor coolant systen.

b

                      ',      I.1-56'

T A B L E _. X .1. 2 2- 2 QPERATIONS WITH DEGRADED CORE _ CONDITIONS COURSE OUTLINE Session 1, Reactor Vessel Instrumentation o Review of Internal Components o Reactor Pressure Instruments o ReactUr Temperature Instruments o Reactor Vessel Flow Paths o Flow Instrumentation Session 2, Heactor Vessel Instrumentation o Reactor Level Instrumentation o Neutron Monitoring Systems Session 3, Instrumentation Failure Modes o Instrument Failure Response o Thermocouple Reference Temperature Change o High Temperature Effects on Neutron Monitoring o Reference Leg Failure Session 4, Alternative Measurements and hydrogen Generation o Heasurement Correlations o Core Conditions versus hydrogen Generation o Effects of Core Damage on Coolant Chemistry. Session 5, Radiation Monitoring o Use of Detectors to Determine Core Damage o Radiation Levels and Cladding Failure o Internal Containment Dose Ra tes o Summary and Review Sessions are designed.to run four hours. I.1-57

Id. 2 3 EfkU f_D'2_3APETY VAM E TEST REOUIRIE NTS (IIddl X2 1.23.1 _jtatement of Requirenent Boiling-water reactor licensees and applicants.shall conduct testing to qualify the reactor coolant system relief and safety valves under expected operating conditions for design-basis transients and accidents. Licensees and applicants shall determine the expected valve operating conditions through the use of analyses of accidents and anticipated operational occurrences referenced in Regulatory Guide 1,70, Revision 2. The single failures applied to these analyses shall be chosen so that the dynamic forces on the safety and relief valves are maximized. Test pressures shall be the highest predicted by conventional safety analysis procedures. acactor coolant system relief and safety valve qualificaiton shall include qualification of associated control circuitry, piping, and supports, as well as the valves themselves. Preimplementation review will be based on EPHI, BWH, and applicant submittals with regard to the various test programs. These submittals should be made on a timely basis as noted below, to allev for adequate review and to ensure that the following valve qualification date can be met: Final BWR Test Program--October 1, 1980 Postimplementation review will be based on the applicants' plant-specific submittals f or qualification of safety relief valves. To properly evaluate these plant-specific applications, the test data and results of the various programs will also be required by the following dates: BWR Generic Test Program Results--July 1, 1981 Plant-specific submittals confirming adequacy of saf ety and relief valves based on licensee / applicant preliminary review of generic test program results--July 1, 1981 Plant-specific reports for safety and relief valve qualification October 1, 1981 i Plant-specific submittals for piping and support evaluations-- l January 1, 1982 X.1.23.2 Interagelation l None required. X 1.23.3 Statement of Response PP&L is participating in the BWR Owner's Group ( BW ROG) program to test safet y/ relief valves (SRV s) . Wyle Laboratories in Huntsville, Alabama has been contracted to design and build a test facility. The design is complete and construction is well underway. The facility will be capable of high and low pressuro valve tests. X.1-58 L

Documentation of the BSROG testing program eas sent to the NRC on September 17, 1980 by a letter f rom D. B. Waters to H.N. Vollmer. A summary of this document is provided below. An engineering evaluation was done to identify the expected operating conditions for SHVs during design basis transients and accidents. This evaluation indicates the SRVs may be required to pass low pressure liquid as a result of the Alternate Shutdown Mode (described in Subsection 15.2.9) . No other significantly probable event, even combined with a single active failure or single ope rator error, produces expected operating conditions that justify qualification of SaVs for extreme operating conditions. Therefore a test program was developed to demonstrate the SRVs' capabilities as may be necessary during the l Alternate Shutdown Mode. pP&L is reviewing the program description and scope. The tecting is scheduled for completion by July 1, 1981. A plant specific SRV qualification report will be submitted to the NRC three months after receiving the BWHOG test results. A plan t specific evaluation of piping and supports will be submitted six months after receiving the BWROG test results. X.1. 2 4 S AFETY/R ELI_EF V A LVE POSITION INDICATICN (II.D.3L X.1.24.l__ Statement of Reguirement Reactor coolant system relief and safety valves shall be provided with a positive indication in the control room derived from a reliable valve position detection device or a reliable indication of flow in the discharge pipe. The basic requirement is to provide the operator with unambiguous indication of valve position (open or closed) so that appropriate operator actions can be taken. The valve position should be indicated in the control room. An alara should be provided in conjunction with this indication. The valve position indication may be se'ety grade. If the position indication is not safety grai a reliable single-channel direct indication powered f rot vital instrument bus may be provided if backup methods of deter. I valve position are available and are discussed in the emer3 precedures as an aid to operator diagnosis of an action. The valve position indication should be seismically qualified consistent with the component or system to which it is attached. The position indication should be qualified for its appropriate environment (any transient or accident which would cause the relief or safety valve to lift) and in accordance with-the Commission order on May 23rd, 1980 (CLI-20-81) . I.1-59

Zt is important that the displays and controls added to the control roca as a result of this requirement do not increase the potential for operator error. A human-factor analysis should be performed taking into consideration: (a) the use of this information by an operator during both normal and abnormal plant conditions, (b) integration into emergency procedures, (c) integration into operator training, and (d) other alarms during emergency and need for prioritimation of a la r m s. Documentation should be provided that discusses each item of the clarification, as well as electrical schematics and proposed test procedures in accordance with the proposed review schedule, but in no case less than 4 months prior to the scheduled issuance of the staff safety evaluation report. Implementation must be completed prior to fuel load. Xzl.24.2 In teggreta tion None required. X2 1.24.3 Statement of Response Each of the 16 safety / relief valves (S RVs) will be provided with a safety grade acoustic monitor to detect flow through the valve. An acoustic sensor will be mounted on the discharge piping, downstream of each valve. The monitors will be grouped into two divisions with 8 valves each. Each division will have group annunciation for valve opening and for division loss of power. A red annunciator window will be provided for valve opening and white annunciator window for loss of power on a front row control panel for these l annunciations. Each division will be powered from a lE vital l instrument bus. l Individual indication of an open valve will be provided by a red light (1 light for each valve) on front row control room panel

IC601. Individual indication of valve position is also available on a back row control room panel where the signal conditioning i instruments are located.

The acoustic monitoring system is designed to be safety grade. This equipment has been qualified to IEEE-344-1975, IEEE-323-1974 and NUREG-0588 in accordance with the Commission order on May 23, 1980 (CLI-20-81) . Additional design information will be presented in Subsection 7.6.la.4.3.7. X.1-60 L

A temperature measuring system chich records temperatures in each SRV discha rge pipes provides additional inf orma tion to the operator t. assess SRV status. This system is discussed in Subsection 1.6.la.4.3.7.2.1. A human factors review of the front row control panel on which these indicators are located has been completed. This same analysis is being applied to the SRV position indicators which are being added to this panel. Installatice of this system will be complete by fuel load. For modifications to plant systems and components such as the SRV position indicators, procedures are developed or revised as necessary and appropriate training is provided when the final design documents are approved and the equipment is available for use. X.1.25 AUXILIARY _FjEDWATER_ SYSTEM EVALUATION JII.E.1.lt This requirement is not applicable to SSES. X.1.26 AUXILIARY FEED'J ATER SYSTEM INITI ATION AND FLOW JII.E.1.2L_ This requirement is not applicable to SSES. I.l.27 EMERGENCY POWER FOR PRESSURIZER HEATERS {II.E.33 1L This. requirement is not applicable to SSES. X.1.28 DECICATED HYpBOGEN PENETRATIONS (II.E.4.lt X.1.28.1 Statement of Requirment Plants using external reco::biners or purge systems for postaccident combustible gas control of the containment atmosphere should provide containment penetration systems for external recombiner or purge systems that are dedicated to that service only. These systems must meet the redundance and single-failure requirements of General design Criteria 54 and 56 of Appendix A to 10 CFR 50, and that are sized to satisfy the flow requirements of the recombiner er purge system. The procedures for the use of combustible gas control systems following an accident that results in a degraded core and release of radioactivity to the containment must be reviewed an revised, if necessa ry. Operating license applicants aust. have design changes completed by July 1, 1981 or prior to issuance of an operating license, whichever is later. I.1-61

121.28.2 _ Interpretation None required. X.1.28.3 statement of__ Response SSES design includes 100% redundant internal hydrogen recombiner systems for postaccident combustible gas (hydrogen) control. Therefore this requirement is not applicable to SSES. X .1. 2 9 CONTAINMENT ISOLATION DEPENDABILITY 1]IzE. 4. 2L X.1.29.1 Statement of Requirement _ (1) Containment isolation system designs shall comply with the recom mendations of S tandard Revie w Plan (SEP) Section 6.2.4 (i.e. , tha t there be diversity in the parameters sensed for the initiation of containment isola tion) . (2) All plant personnel shall given careful consideration to the definition of essential and nonessential systems, identify each system determined to be essential, identify each system determined to be nonessential, describe the basis for selection of each essential system, modify their containment isolation designs accordingly, and report the results of the reevaluation to the NRC. (3) All nonessential systems shall be automatically isolated by the containment isolation signal. (4) The design of control systems for automatic containment isola tion valves shall be such that resetting the isolation signal will not result in the automatic reopening of containment isolation valves. Reopening of containment isolation valves shall require deliberate operator action. (5) The containment setpoint pressure that initiates containment isolation for nonessential penetrations must be reduced to the minimum compatible with normal operating conditions. (6) Containment purge valves that do not satisfy the operability criteria set forth in Branch Technical Position CSB 6-4 or the S taff Interim Position of October 23, 1979 must be sealed clo' sed as defined in SRP 6.2.4, item II.3.f during opera tional conditions 1, 2, 3, a nd 4. Furthermore, these valves must be verified to be closed at least every 31 days. (7) Containment purge and vent isolation valves must close on a high radiation signal. Applicants for an operating license must be in compliance with positions 1 through 4 before receiving an operating license. Applicants must be in compliance with positions 5 and 7 by July I.1-62

1, 1981, and position 6 by Janua ry 1, 1981 or before they receive their operating license, whichever is later f or each position. 121.29.2 Interpretations From item 4, the opening of containment isolation valves must require a deliberate operator action. From item 5, the containment isolation setpoint pressure should be optimized to prevent unnecessary isolations during normal operations. However, containment isola tion must not be prevented or delayed during an accident. X.1.29.3 Jtatement_of Response (1) Containment isolation signals are actuated by several sensed parameters (refer to Table 3.3.2-1 in the Technical Specifica tions) . This complies with SRP Subsection 6.2.4, Paragraph II-6. (2) Each process line penetrating containment was reviewed to determine whether it is an essential or non-essential line for purposes of isolation requirements. The classification for each line is given in Table X.1.29-1. Justification for the classification as an essential or non-essential line was also developed and is provided in Table X.1.29-2. Systems identified as essential are those which may be required to perform an indispensable safety f unction in the event of an accident. Non-essential systems are those not required during or after an accident. Since instrument lines are not governed by isolation signals but are equipped with a manual isolation valve followed by an

     . excess flow check valve outside the containment, the review of these lines was limited to ensure compatibility with the penetration listing in Table 6.2-12a.

(3) All lines to non-essential systems are provided with isola tion capability. All isolation valves in these lines, c except the reactor water clean-up system (R WCU) discharge l valves (G33-lFC042 and 1F104 receive auto-isolation signals (refe r to Table X.1.29-1) . The isolation function for the RWCU discharge lines is provided by three series check valves (141-lF010A,B, HV-14107 A, B and G33-lF0 39 A, B) which prevents back flow from the reactor vessel. The RWCU discharge isolation valves are not closed to prevent the loss of the filter cake in the RWCU filter demineralizer system and injection ' of resin into the vessel on restart of the RWCU system. (4) All containment isolation valves, except those listed below, will not automatically open logic reset. An overide of any isolation signal will not cause automatic reopening of any isola tion valve. X.1-63

a) The RCIC and HPCI turbino steam supply line isolation valves (HV-lF007, HV-lF008, HV-lF-002, and HV-lF003) which are normally open. The pressure equalization valves (HV-lF088 and HV-lF100) around the inside containment isolation valve if either is open when isolation occurs. b) The RHR containment isolation valves (HV-lF016 A , B , HV-1F021A,B, HV-lF024A,B, HV-lF027A,B, and HV-lF028 A,B) associated with drywell and suppressica pool spray header actuation. Reopening of these valves will occur if the hand switches are not placed in the closed position by the operator prior to actuation of the reset switch and the isclation parameters have cleared. Justification is as follows: a) With respect to RCIC and HPCI steam line isolation valves and inboard bypass valves, in order to prevent inadvertent closure of ECCS (HPCI) and coolant makeup system (R CIC) steam supply valves, the steam line isolation valves are provided with key-locked control X.1-64

switches which maintain contact. In order to insure that the operator considers his actions prior to resetting the isolation logic, and thus causing the isolation valves to reopen a u to m a tica lly , the logic reset switches are also keylock switches, which are locked in the normal positicn. An < administratively controlled key is required to reset the logic. b) With respect tot he RHR drywell and suppression pool spray line and test return valves, the three inboard valves have spring return to " Auto" position switches and will not automatically reopen upon logic reset. Two outboard isolation valves are provided with key-lock control switches to prevent inadvertently jeopardizing the LPCI function of the RHR system by opening the spray line and test lipa 7alves, which are normally closed. If an automatic closure signal caused the test line and/or spray line valves closed during HHR system test, only the outboard valves would reopen until the operator reset the logic after the initiating signal cleared.

 ,            The BWa owners' Group has performed a generic analysis which is summarized as follows.

(5) The BWR Owners' Group has performed a generic analysis which is summarized as follows. The containment isolation analytical setpoint pressure for Mark I, II, and III containments is approximately 2 psig (drywell pressure) . Under normal operating conditions, fluctuations in the atmospheric barometric pressure as well as heat inputs (from such sources as pumps) can result in containment pressure increases on the order of 1 psi. Consequently, the isolation setpoint of 2 psig provides a 1 psi margin above the maximum expected operating pressure. The 1 psi margin to isclation has proved to be a suitable value to minimize the possibility of spurious containment isclation. At the same time, it is such a low value (particularly in view of the small drywell volume of Mark I, II, and III i containments) that it provides a very sensitive and positive ! means of detecting and protecting against breaks and leaks l in the reactor coolant system.

No change of the setpoint is necessary for these containment types. PPSL concurs with this position. Therefore, no modifications to the containment isolation pressure setpoint are necessary in response to this requirement. (6) The design of the containment atmosphere purge values was reviewed against Branch Technical Position CSB6-4. On the l basis of this review the following valves will be administrative 1y maintained sealed closed when the reactor is in OP ER ATIONAL CONDITIONS 1, 2 or 3, except as provided in Technical Specifications 3.6.1.8. Operations Instruction I.1-65

O P-0 I-012 , " Locked Components," implesents the administrative controls for sealed closed valves. VALVE PSID M-157 COOFDINATES HV-15704 C-7 HV-15714 E-7 HV-15721 D-3 HV-15722 D-4 HV-15723 D-2 HV-157 2 4 C-2 HV-15725 C-4 Technical Specification 3.6.1.8 will be revised to require this sealed closed requirement, to be verified once per 31 l days per Specification 4.6.1.8. (7) Two redundant safety grade radiation monitors are installed down stream of the Standby Gas Treatment System. A high radia tion level will trip the Standby Gas Treatment System. This signal will be used to close the follcwing containment isolation valves in the vent and purge system: H V-15 705, HV-15713, HV- 157 03, HV-15711, SV-15736A, SV-15737, SV-15767 a nd SV-15776 A. The radiation setpoint will be set to so that the 10CFR 100 limits are not exceeded. The high radiation alarm for these detectors is annunciated on control room f ront row panel 1C653. The radiation level measured by these detectors is recorded on control room backrow panel 1C600. These modifications will be complete by fuel load. l

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IA_BLE X.1.29-1 (continued)_ REMARKS (1) Essential or non-essential classification basis codes are described in Table I.l.29-2. (2) Automatic actuation signal codes are described in Table X .1. 2 9- 3. (3) Where the control power source is left blank, the control power source is the same as the valve motor power source. (4) E32-lF001B automatic actuation signal is dependent upon action of MSIV's, time, HPV pressure. The valve is normally closed and interlocked when RPV pressure is greater than 35 psig. The valve opens on MSIV closure. Information presented is representative of that for main steam lines B, C and D. (5) Automatic signal code UA for B21-lF028 A, et al (Reactor vessel pressure) prevents operation of condenser low vacuum bypass. (6) Reactor recirculation system sample line valves B31-lF019 and 1F020 receive high radiation signals for isolation but since the line dces not provide an open path from the containment to the environs, the radiation isola tion signal may be considered a diverse signal in accordance with Standard Review Plan 6.2.4. This judgement is based on our definition of an open path as a direct, untreated path to the outside environment. (7) Hand Switch Nos. are from the PSID rather than referenced Schematic Diagram. (8) Automatic actuation signals for Ell-lF015 A and B: codes UB and Z are isolation signals; codes G and T are initiation

     . s ig na ls.

(9) Automatic actuation signals for Ell-lF050 A and B, and 1F122A, B: code Z is an isolation signal; no initiation signa ls. (10) Either valve opening (or closing) will energize a common open (close) status light. HS-ll314 controls both valves. Typical for HV-ll345 and HV-ll346. ! (11) Closes on "LOCA" signal but can be reopened af ter 60 minutes. Valves can be administratively reopened if the high dryvell pressure is due to plant heat up or loss of dryvell cooler. I.1-72 i f

T A BLE X.1. 2 9-1 (Cont inuedt (12) Closes on "LOCA" signal but can be reopened after 10 minutes. (13) Power source lY226 is for control. 1D614 cr 1D624 is for status indication lights. (l' 4 ) Switch types: 4 E-30AC Cutler Hammer two button operater momentary with MI = mechanical interlock E-30AE Cutler Hammer, momen ta ry Ca294 0 GE: KL = keylock Ro = key removable in open position RC = key removable in close position HN = key removable in normal position SRN = spring return to Normal SRA = spring return to Auto MAINT = maintained contacts PB = pushbutton (15) Initiation reset will automatically reopen valve if valve handswitch is in open position. (16) Initiation reset will not automatically reopen valve.

 - (17) Pneumatic actuated valve.

(18) Power sources 1Y236 and lY246 are AC contrci power, and ID634 is DC control power. I.1-73 m

T A B L E X .1. 2 9-1 ESSENTI AL/NON-ESSENTI AL PENETR ATION CL ASSIFIC ATION BASIS (1) Closed cooling Water - Non-essential since used during normal operation caly for reactor recirculation pump cooling, reactor water cleanup and other system components. Not required for design basis accident situation. (2) Containment Intstrument Gas - Essential to support safety equip:ent. (3) Instrument Gas - Non-essential support to non-safety related equi p ment, and for testing of safety related equipment. (4) Main Steam Line and MSIV Leakage Control System - Non essential for shutdown. (5) Feedwater Line - Not essential for shutdown but desirable for makeup water to vessel. Portion between reactor vessel and outermost containment isolation valve is essential for HPCI_and RCIC injection. (6) Reactor Core Isoltion Cooling - Essential for core cooling following isolation from turbine condenser and feedwater makeup. (7) Reactor Water Cleanup - Not essential during or immediately following an accident. Maybe important in long term recovery operations. (8) Reactor Water Sampling - Not essential for safe shutdown. Post-accident samples will be taken utilizing the post-accident sampling system developed in response to item II.B.3. (9) Standby Liquid Control - Essential as backup to CRD system. (10) Residual Heat Removal (RHR) Head Spray - Not essential for safe shutdown. (11) RHR Containment / Suppression Pool Spray - Essential for pressure control. l _(12) RHR Shutdown Cooling - Essential to achieve cold shutdown. (13) RHR Steam Condensing Recirc./ Test Return Line - Not essential since not a safety function. Used during hot standby and pump tests. (14) HHR Pump Minimum Flow Recirculation - Essential for protect l pumps for safety function. X.1-74

TABLE I.l.29-2_jgontinueil (15) RBR heat Exchanger Relief Valve Discharge Line - Essential to pretect HI frcm overpressurization for use in saf ety function. (16) RHR Suppression Pool Suction - Essential for vessel injection and pcc1 cooling safety functions. (17) Core Spray Injection - Essential safety function. (18)~ Core Spray Pump Test Return Lines - Non-essential. Used only during testing of pumps. (19) Core Spray Pumps Min. Flow Bypass - Essentail to protect pumps for safety function. (20) Core Spray Suppression Pool suction - Essential for vessel injection saf ety f unction. (21) High Pressure Coolent Injection (HPCI) Turbine Steam Supply and Exhaust-Essential to drive HPCI pump for vessel injection safety function. (22) HpCI Pump Min. Recirc. - Essential to protect pump f or safety function. (23) HPCI. Suppression Pool Suction - Essential for vessel injection safety fur.ction. Backup to Condensate Storage Tank supply. (24) . Containment Atmospheric Purge - Non-essential vent path to Standby Gas Treatment System. Backup to four hydrogen recombiners. (25) Containment Atmoshere Sampling - Essential. Not required for shutdown, but would be necessary f or post-accident assessment. (26) Suppression Pool Water Filtration - Not essential. Used only for periodic cleanup of pool water. (27) Liquid Radwaste Collection - Non-essential for safe shutdcwn. (28) Reactor Bldg. Chilled Water - Non-essential supply to recirculation pump motor coolers, drywell coolers. I.1-75

TA3LE X.1.29_-3 ACTUATION / ISOLATION SIGNAL CODES

                        & CORRESPONDING ACTUATING SWITCHES

ISOLATION FUNCTIONS: 0THER CODES FOR INFORMATION ONLY.

A* Reactor Vessel low water level 3 B21-N024A or B B* Reactor Vessel low water level 3 B21-N026A C* Main Steam line high radiation H21-P606 typ of 2 D* Main Steam lice high flow B21-N006A (any one of four) B21-N007A B21-N008A B21-N009A E* Main Steam line leak /high temp B21-N600A (either) B21-N603A FA* High drywell pressure Ell-N010A or C Reactor / Steam line low pressure E51-N019A or C (both required) FB* High drywell pressure Ell-N010A or C Reactor / Steam line low pressure E41-N001A or C (both required) G Reactor Vessel low level 1RHR, Core B21-N031A or C Spray (level 2_RCIC, HPCI), or Drywell high pressure Ell-N0llA or C (one of two twice), Bypass Switch EllA-S18A for E11-F016A, F021A, F028A (typ. for B) I Reactor Vessel low water level 2 B21-NO31A-D (one of two twice) J* RWCU line break /high flow G33-N044A RWCU high flow differential G33-R616A (either) K* RCIC Steam line leak /high temp: Equip room area high temp E51-N600B Equip room vent air high temp E51-N601B Emer area cooler high temp E51-N602B Pipe routing area high temp E51-N603B Pipe routing area high temp, after- E51-N604B time delay (any one of 5), Bypass Switch B21B-S3B RCIC steam line break /high P E51-N018 X.1-76

TABLE X.1.29-3 (Cont'd.) Reactor / Steam line low pressure E51-N019B & D Turbine exhaust diaphragm high E51-N012B & D pressure L* HPCI Steam line leak /high temp: Equip room area high temp E41-N600A Equip room vent air high temp E41-N601A Emer area cooler high temp E41-N602A Pipe routing area high temp E51-N603C Pipe routing area high temp, E51-N604C after (any one of 5) Bypass Switch B21B-S4A HPCI Steam line break /high P E41-N004 HPCI Steam supply low pressure E41-N001A & C Turbine exhaust diaphragm high pressure E41-N0012A & C LFCS CS pump discharge low flow E21-N006A (with CS pump running)- LFHP HPCI pump discharge low flow E41-N006 (with HPCT pump running) LFRC RCIC pump discharge low flow E51-N002 (with RCIC Pump running) LFRH RHR pump discharge low flow Ell-N021A (with RHK Pump running) M RHR Suction cooling line break: Equip area ambient high temp Ell-N600A or C Equip area vent air high temp Ell-N601A or C Bypass switch B21B-S6A Cooling line high P Ell-N019 (any of the above) P* Main Steam line low pressure B21-N015A Run Mode Only - Bypassed on l Start & Hot Stdby, Refuel or Shutdown mod?a T Reactor Vessel low pressure B21-N021A-D (permissive, one of two twice) UA Reactor Vessel high pressure B21-N020A UB Reactor Vessel low pressure B31-N018A X.1-77

TABLE X.1.29-3 (Cont'd.) W* RWCU leak detection ambient high G33-N600A, C, E temperature vent air high temp G33 N602A, C, E (any. ' of six) Z* Reac... Vessel low water level 3 B21-N024A, B Drywell high pressure C72-N002A, B Y* -Reactor Vessel low water level 2 B21-N026A, B

         -Drywell high pressure                               C72-N002C, D 4

L 1 b

    -(MG/2F)-

X.1 U g g,,,

X.1.30 ACCIDENT-MONITORING IN STRU g1(UTIO N { IIML 1 1.30.1 Statement of Requirement the f ollowing equipment shall be added: (1) Noble gas effluent radiological monitor; (2) Provisions for continuous sa mpling of plant ef fluents for postaccident releases of radioactive iodines and particulates and onsite laboratory capabilities; (3) Containment high-range radiation monitor; I l (4) Containment pressure monitor; i (5) Containment water level monitor; and (6) Containment hydrogen concentration monitor. It is important that the displays and controls added to the control rocm as a result of this requirement not increase the potential for operator error. A human-factors analysis should be performed which considers: (a) the use of this information by an operator during both normal and abnormal plant conditions, (b) integration into emergency procedures, (c) integration into operator training, and (d) other alarms during emergency and need for prioritization of alar m_ Each piece of equipment is fu; discussed below. X.1.302 1 l___ Noble Gas Effluent _ Monitor l Noble gas ef fluent monitors shall be installed with an extended ! range designed to f unction during accident conditions as well as during normal operating conditions. Multiple monitors are ! considered necessary to cover the. ranges of interest. t (1) reble gas effluent monitors with an upper range capacity of 105 pCi/cc ( X e-133) are considered to be practical and should be installed in ' all operating plants. 4 (2) Noble gas effluent monitoring shall be provided for the total range of concentration extending from normal condition (as low as reasonably achievable concentrations to a maximum of 105 p ci/cc ( Xe-13 3) . Multiple monitors are considered to be necessary to I.1-79

cover the ranges of in terest. The range capacity of individual monitors should overlap by a factor of ten. Licensees and licensing applicants should have available for review the final design description of the as-built system, including piping and instrument diagrams together with either (1) a description of procedures for system operation and calibration, or (2) copies of procedures for system operation and calibration. License applicants will submit the above details in accordance with the proposed review schedule, but in no case less than 4 months prior to the issuance of an operating license. Xz1z30.1 2__ _ _ _Sa mplino an d Analvgis o f Plant Ef[luents Because iodine gaseous effluent gonitors for the accident condition are not considered to be practical at this time, capability for effluent monitoring of radiciodines f or the accident condition shall be provided with sampling conducted by adsorption on charcoal or other media, followed by onsite laboratory analysis. Licensees shall provide continuous sampling of plant gaseous effluent for postaccident releases of radioactive iolines and particulates to meet the requirements of Table II.F.1-2 in NUSEG 0737. Licensees shall also provide onsite laboratory capabilities to analyze or measure these sa mples. This requirement should not be construed to prohibit design and developmen t of radiciodine and pa rticulate monitors to provide online sampling and analysis for the accident condition. If gross gamma radiation measurement techniques a re used, then provisions shall be made to minimize noble gas interference. The shielding design basis is given in Table II.F.1-2 of NUREG 0737. The sampling system design shall be such that plant personnel could remove samples, replace sampling media and transport the samples to the onsite analysis f acility with radiation exposures that are not in excess of the criteria of GDC 19 of 5-rem whole-body exposure and 75 rem to the extremities during the duration of the accident. The design of the systems for the sampling of particulates and iodines should provide for sample nozzle entry velocities which are approximately isokinetic (same velocity) sith expected induct or instack air velocities. For accident conditions, sampling may be complicated by a reduction in stack or vent effluent velocities to below design levels, making it necessary to substantially reduce sampler intake flow rates to achieve the isokinetic condition. Reductions in air flow may well be beyond the capability of available sampler flow cc<ntrollers to maintain isokinetic conditions; therefore, the staff will accept flow control devices which have the capability of maintaining isokinetic conditions with varia tions in stack or duct design flow velocity of +20%. Further departure from the isokinetic condition need not be considered in design. Corrections for non-X.1-80

isokinetic sampling conditions, as provided in Appendix C of ANSI 13.1-1969 may be considered on an ad hoc basis. Effluent streams which may contain air with entrained water, e.g. air ejector discharge, shall have provisions, e.g. , he aters, to ensure that the adsorber is not degraded while providing a representative sample. License appijcants will submit final design details in accordance with the proposed review schedule, but in no case less than 4 months prict to the issuance of an operating license. X.1.30 1.] containment _gigh-Range _3adiation Mgni3or In containment radiation-level monitors with a maximum range of 108 rad /hr shall be installed. A minimum of two such monitors that are physically separated shall be provided. Monitors shall be developed and qualified to function in an accident environment. The specification of 108 rad /hr in the above position was based on a calcu.ation of postaccident containment radiation levels that include both particulate (beta) and photon (gamma) radiation. A radiation detector that responds to both beta and gamma radiation cannot be qualified to post-LOCA (loss-o f-coolan t accident) containment environments but gamma-sensitive instruments can be so qualified. In order to fcilow the course of an accident, a containment monitor that measures only gamma radiation is adequate. The requirement was revised in the October 30, 1979 letter to provide for a photon-only measurement with an upper range of 107 R/hr. The monitors shall be located in containment (s) in a manner as to provide a reasonable assessment of area radiatica conditions inside containment. The monitors shall be widely separated so as to provide independent measurements and shall " view" a large fraction of the containment volume. Monitors should not be placed in areas which are protected by massive shielding and should be reasonably accessible for replacement, maintenance, or calibration. placement high in a reactor building dome is not recommended because of potential maintenance difficulties. The monitors are required to respond to gamma photons with energies as low as 60 kev and to provide an essentially flat response for gamma energies between 100 kev and 3 MeV, as specified in Table II.F.1-3 of NUREG 0737. Monitors that use thick shielding to increase the upper range will under-estimate postaccident radiation levels in containment by several orders of magnitude because of their insensitivity to low energy gammas and are not acceptable. License applicants will submit the required documentation in accordance with the approp'riate review schedule, but in no case X.1- 81

less than 4 months prior to the issuance of the staff evaluation report for an operating license. X.1 10.1.4 containment Prassare 9anitor A continuous indication of containment pressure shall be provided in the control room of each operating reactor. :teasuremen t and indication capability shall include three times the design pressure of the containment for concrete, four times the design pressure for ateel, and -5 psig for all containments. Operating license applicants with an operating license dated before January 1, 1982 must have design changes completed by January 1, 1982; those applicants with license dated after January 1, 1932 must hcve all design modificaticas completed before they can receive their operating license. Doc ume n ta tion is due 6 months for the expected date of operation. x .1. 3 0.1. 5_____co n tginaent Wa t er __ Le ve l_2o nitos A continuous indication of containment water level shall be provided in the contrcl room for all plants. A wide range instrument shall be provided to cover the range from the bottom to 5 feet above the normal water level in the suppression pool. The containment wide-range water level indication channels shall meet appropriate design and qualification criteria. The narrow-range channel shall meet the requirements of Regulatory Guide 1.89. For BWR pressure-suppression containments, the emergency core cooling system suction line inlets may be used as a starting reference point for the narrow-range and wide-range water level monitors, instead of the bottom of the suppression pool. The accuracy requirements of the water level monitors shall be provided and justified to be adequate for their intended function. Operating license applicants with an operating license date before July 1,1981 must have design changes completed by July 1, 1981, whereas those applicants with license dates past July 1, 1981 must have all design modifications completed before they can receive their operaitng license. Submittals from operating reactors licensees and applicants for operating licenses (with an operating license date before January 1, 1982) shall be providad by January 1, 1982. Applicants with operating license dates beyond January 1, 1982 shall provide the required design information at least 6 months before the expected date of operation. 121t10 2 1.6__ containment Hydrogen Monitor X.1-82

A continuous indication of hydrogen concentration ia the containment atmosphere shall be provided in the control room. Measurement capability shall be provided over the range of 0 to 10% hydrogen concentration under both positive and negative ambient pressure. Operating license applicants with an operating license date before January 1, 1982 must have design changes completed by J anuary 1, 1982 must have all design modificaticas completed before they can receive their operating license. Operating reactors and applicants for operating license receiving an operating license before January 1, 1982 will submit documentation before January 1, 1982. Applicants with operating license issued after January 1, 1982 shall provide the required design information at least 6 months prior to the expected date of operation. 121A20.2 In terpreta t ion None required. 1 1.3023 Statement of_Hesponse The response for each equipment requirement is given below. All equipment will be installed by the required da tes. A human factors evaluation will be performed for changes that involve control room instrumentation. For modifications to plant systems and components such as addition of new post-accident monitoring capability, procedures are developed or revised as necessary and appropriate training is provided when the final design documents are approved and the equipment is available for use. Y,,12J 0. 3. l __ _Hoble gas Efflgent_Moni_ tor , Each of the five plant vents will be monitored by an Eberline l Model FAAM (Fixed Airborne Activity Monitor). The FA AM's analyze representitive samples which are provided by isokinetic probes which are in compliance with ANSI 13.1-1969. Each FAAM has three noble gas detectors which provide overlapping ranges of 1 x 10-74 C1/cc to 1 x 105 pci/cc for re-133 gas. The sample stream is j filtered by a HEpA filter and a charcoal filter, which are j contained in a SA-13 assembly before passing the noble gas detectors. The charcoal filter can be replaced with a silver zeolite filter when required. The plant effluent noble gas data is continuously monitored and stored in solid state memory. The flow through the sample line is also measured and stored in solid state memory. The FAAM then calculates and stores activity per unit of volume. This information can be displayed upon request and is periodically X.1-83 L_.

i printed out for record keeping purposes. This information is displayed and recorded on backrow panel OC669. High activity alarms for the reactor and turbine buildings will be annunciated on control room f ront row panel IC651. High activity alarms for the Standby Gas Treatment System will be annunciated on control rocm front row panel 1C601. The low-range noble gas channel is calibrated using Kr 85 and Xe 133 gas standards traceable to the National Bureau of Standards. The mid-range noble gas channel is calibrated using a Cs 137 stick source. The high-range noble gas channel is calibrated using a KR 85 gas standard traceable to the National Bureau of Standards. The system is powered from non-class IE instrument AC power. An independen t battery backup is provided which is capable of providing power for 8 hours. This equipment is installed and will be operational by fuel load. 121 30 2 Jz2_____samnling and Analzgig_o f plant Effluents Each of the five plant vents has a continuous isokinetic sample drawn from it in accordance with ANSI-N13.1. Each sa mple is then taken through short runs of heat traced tubing to a Eberline Model FAAM (Fixed Airborne Activity Monitor) . In the FAAM the sample stream then passes through a HEPA filter which removes particulates. Upon leaving the HEPA filter the sample stream passee through a charcoal filter which removes iodines. When required this filter can be replaced with a silver zeolite filter. Capabilities for purging the sample line with compressed air are provided under manual control. The sa m ple stream is next measured for noble gas activity and then returned to the plant vent. During normal operation the HEP A and charcoal filters are monitored by' radiation detectors and this inf ormation is presented to the operator in the control room. Under accident conditions these detectors will saturate and the filters must be removed, placed in a shielded container, and analyzed in a laboratory. The FAAM also has provisions for obtaining a grab samples. The isokinetic sample is in compliance with ANSI-N13.1-1969. To accomplish this, each vent has an air profile (final gas treatment) station to eliminate turbulent and rctating gas flow. The average stack velocity and volume are then measured by means of a multipoint, self-averaging Pitot transverse station. An air flow contrclier then simultaneously withdraws a multipoint sample under isokinetic flow conditions by means of an isokinetic sample rack. This isokinetic sample is then directed to the Final Airborne Activity Mcnitor. The system is designed such that plant personnel can remove samples, replace sample media and transport the samples in I.1-84

shielded containers to an analysis facility. Radiation exposures for this process are not in excess of 3 rem whole-body exposure and 18.5 rem to the extremities during the dura tion of th e accident. procedures for analyzing samples both normal and accident conditions are described in Subsection 12.5.3.5.5. The equipment used to analyze these samples is described in Subsection 1.2.5.2.7.1. Additional instrumentation and procedures f or sampling and analyzing implant iodine are described in Subsection X .1.7 0. The installation plant vent sampling and monitoring system is complete. X.1.30.3.3__ Containment Hiqh-Range Radiation Monitor Redundant Class lE in-containment radiation monitors will be provided. The monitors will be Victoreen Model 875 high range radiation monitors. These monitors are capable of measuring radiation levels of 1R/hr to 1 x 107 R/hr (Gamma) for photon energies of between 60 Kev to 3 MeV. An accuracy of 1 20% is obtained on lower decades. The detectors '.ill be unshielded and physically separated on opposite sides of the reactor pressure vessel. Logarithmic indicating recorders will be provided for Channels A and B on f ront row panel 1C601. A common red high radiation annunciator for both channels will be provided on control rocm f ront row panel 1C601. A comaon white system trouble light will also be provided for both channels on control rocm front row panel 1C601. The containment radiation monitoring system is designed to be safety grade. This equipment will be qualified to IEEE-344-1975, IEEE-323-1974 and NUREG-1588 in accordance with the Commission order on May 23rd, 1980 (CLI-20-81) . f The installation of the containment radiation acnitoring system will be complete by January 1982. X.1.30.3.4 C2ntainment Pregggge_jonitog Three Class lE drywell chamber pressure measurements will be provided as follows: SERVICE RANGE Normal Operation -1 to + 2.5 psig LOCA Range O to 65 psig HL Range O to 250 psig I.1-85

The LOCA and HI ranges are divided into two divisions. Continuous, individual indication of all four Division I and II pressure measurements will be provided by indicating recorders for the operation on front row panels 1C601. A non-red un dant indicator for the normal range will be provided on front panel 1C601. Two Class 1E non-redundant wetwell chamber pressure measurements will be provided as follows: _S ER V IC E 3AEG3 Normal Operation -1 to +2.5 psig LCCA Range O to 65 psig The indicators for both wetwell chamber pressure measurements will be provided on control room front row panel IC601. The accuracy of these instruments is 12% of full scale. The containment pressure monitors are designed to be safety grade. This equipment will be qualified to IEEE-344-1975, IEEE-323-1974 and NUBEG 0588 in accordance with the Ccamission order on May 23rd, 1980 (CLI-2 0-81) . The containment pressure instrumentation will be installed by January 1982. X.1.30.1.5__ _ Containment Water _ Level _ Monitor Redundant wide and narrow range safety grade instruments will be installed to continuously monitor suppression pool water level. The channel A measurements will be displayed on control room front row panel 1C601. The channel B measurements will be recorded on front row panel 1C601. The narrow range instruments measure between 18 and 26 feet. The wide range instruments measure between 4.5 and 49 feet. This covers the required range of from the lowest ECCS suction to 5 feet above normal water level. Normal water level is approximately 23 feet. The accuracy of these instruments is 12% of full scale. Installaticn of the suppression pool water level instrumentation will be complete by January 1982. X.1.30.3.6 ContalDaent Hydrogen _ Monitor X.1-86

Continuous and redundant indication and recording of hydrogen will be provided on contrcl room front row panel IC601. These instruments will have a range of 0 to 30%. The containment hydrogen monitoring system is designed to be safety grade. The equipment will be qualified to IEEE-344-1975, IEEE-323-1974 and NUREG-0588 in accordance with the Commission 1 order on May 23rd, 1980 (CLI-20-81) . The accuracy of these instruments is 12% of full scale. Installation of the hydrogen mor.itoring instrumentation will be complete by January 1982. X.1.31 INSTRUMENTATION FOR DETECTION OF IN ADEQUATE COR E COOLING __lllzI. 2) _ ____ _ 1 1.31.1 Statement- of_ Requirement Licensees shall provide a description of any additional instrumentation or controls (primary or backup) proposed for the plant to supplement existing instrumentation (including primary coolant sa turation monitors) in order to provide an unambiguous, easy-to-interpret indication of inadequate core cooling (ICC). A description of the functional design requirements for the system shall also be included. A description of the procedures to be used with the proposed equipment, the analysis used in developing these procedures, and a schedule for installing the equipment shall be provided. 3z1 31.2 Intergre13 tion None required. 1 1.31,3 Statement of Response As stated in NEDE-24801, " Review of BWR Reactor Vessel Water Level seasurement", the optimum design is the ccid reference leg configuration with parallel instrument lines. Since the present design conforms to this recommended configuration, no additional instrumentation or modifications to instrumentation are needed for detection of inadequate core cooling (ICC) . Procedures are being developed (in response to requirement I . C .1) for proper identification of ICC. Refer to subsection I.l.8 for the response to requirement I.C l.

PPSL has d'ecided to provide an additional computer display format which will promote detection of ICC with the existing instrumentation. A discussion of this display format will be provided by fuel load. X 1-87

X .1. 3 2 EMERGENCY POWER _ZOR PR ES S U RIZ ER EQUIPjjgT_(II.G.1) This requirement is nct applicable to SSES. X3 1 33 R EVI EW ESZ_lALVES iII.K.1.5L , No requirement stated in NUREG 0737. Refer to Subsection X.2.25 which cantains the rtsponse to the requirement in NUREG 0694 x.1.34 gg;3A3ILITI_ STATUS (II . K. l .101 No requirement stated in NUREG 0737. Refer to Subsection X.2.26 which contains the response to the requirement in NUREG 0694. I.1.35 TRIP PRESSURIZER LOW-LEVEL COINCIDENT SIGNAL SISTABLES JII.K.1.171 __ _ - This requirement is not applicable to SSES. X.1.36 OPERATOR TRAINING FOR PROMPT MANUAL REACTOR TRIP JII23zl. 20) __ __ This requirement is not applicable to SSES. X.1.37 AUTOMATIC SAFETY GRADE ANTICIPATORY REACTOR TRIP JII.K.l.21) .__ This requirenent is not applicable to SSES. X.1. 3 8 AUXILIARY HjAT REMOVAL SYSTEM PROCEDURES _(II.K._1.22L No requirement stated in NUREG 0737. Refer to subsection X.2.30 which contains the response to the requirement in NUREG 0694

X.1. 3 9 RIACTOR VESSEL _1EVEL PROCEDURES _JII. K 2 1223L No requirement stated in NUREG 0737. Refer to Subsection X.2.31
which contains the response to the requirement in NUREG 0694.

X.1.40 COMMISSION _9BDERS ON BABCOCK AND WILCOX. PLANTS III.K.2L These requirements are not applicable to SSES. i X.1.41 AUTOMATIC POWER-OPER ATED RELIEF V ALVE ISOLATION - SYSTEM (II. K. 3.1) __ l I.1-88 L

This requirement is not applicable to SSES. I.1.42 PEPORT ON POWER-OPER AT ED RELIEF V ALV E F AILUR ES JII.K. 3. 2) This requirement is not applicable to SSES. X.1.43 REPORTING SAFETY / RELIEF VALVE FAILURES AND _ CHALL32EES JII.K.3.3) ____ ______ No requirement stated in NUREG 0737. Refer to Subsection X.2.33 which contains the response to the requirement in NUREG 0694 X.l.44 AUTOMATIC TRIP OF REACTOR C00LANI PUMPS DURING _ A LgCA_JII. _K. 3. .i) ____ This requirement is nct applicable to SSES. X.1. 4 5 EVALUATION OF POWER-OPER ATED RELIEF V ALVE OPENING PROBABILITY III.K.3 2L____ _______ This requirement is not applicable to SSES. X.1. 4 6 PROPORTIONAL INTEGRAL DERIVATIVE CONT 50LLER MODI FIC ATIO N (II 2 K.3.9L, __ This requirement is not applicable to SSES. X.1. 4 7 PROPOSED ANTICIPATORl_ TRIP MODIFICATICN JII.K.3.101 This requirement is not applicable to SSES. Xzl. 4 8 POWp3-OPER ATED_EELIEF V ALVE _ F AILURE RATE (II. K. 3,11[ This requirement is nct applicable to SSES. X .1. 4 9 ANTICIPATORY REACTOR TRIP ON TURBINE _ TRIP (II. K. 3.121 This requirement is nct applicable to SSES. 2.1.50 SEPARATION OF HIGH PRESSURE COOLANT INJECTION AND REACTOR CORE ISOLATION C0 CLING SYSTEM INITI ATION LEVELS _ (IIz K 3.13) _ _ _ _ X.1.50.1 Statement of Requirement X.1- 89

Currently, the reactor core isolation cooling (RCIC) system and the high-pressure coolant injection (HPCI) system both initiate on the same low-water-level signal and both isolate on the same high-water-level signal. The HPCI system will restart on low Wdter level but the RCIC system will not. The RCIC system is a low-flow system when compared to the HPCI system. The initiation levels of the HPCI and RCIC system should be separated so that the RCIC system initiates at a higher water level than the HPCI system. Further, the initiation logic of the RCIC system should be modified so that the RCIC system will resta rt on low water level. Ihese changes have the potential to reduce the number of challenges to the HPCI system and could result in less stress on the vessel from cold water injection. Analyses should be performed to evaluate these changes. The analyses should be submitted to the NRC staff and changes should be implemented if justified by the analyses. All applicants for operating license should submit the results of an evaluation and proposed modifications 4 mor.th s prior to the expected issuance of the staff saf ety evaluation report for an operating license or 4 months prior to the listed implementation date (July 1, 1981), whichever is later. X.1.50.2 Intercretation None required. X.1.50.1 Statement of Response PPSL concurs with the BWR Owners' Group position on the separation of the HPCI and RCIC setpoints which was transmitted to the NRC by letter from R. H. Buchholm (G E) to D. G. Eisenhut (NBC) , October, 1, 1980 (MF N-16 9-8 0) . This letter forwarded a GE study which showed that H?CI and RCIC initiations at the current low water level setpoints is within the design basis thermal fat 4.gue analysis of the reactor vessel and its internals. Separating HPCI and RCIC setpoints as a means of reducing thermal cycles has been shown to be of negligible

 , benefit. In addition, raisir.9 the RCIC setpoint or lowering the l HPCI setpoint have undesirable consequences which outweigh the benefit of the limited reduction in thermal cycles. Therefore, when evaluated on this basis, PPSL concludes that no change in RCIC or HPCI setpoints is required.

t PPSL also concurs with the BWR Owners' Group position that RCIC should restart automatically following a trip of the system at high reactor vessel water level. This position was transmitted to the NRC by letter from D. B. Waters (BWROG) to D. G 3 Eisenhut (NBC) , December 29, 1980. X.1-90 L

i l PPSL will implement the recommended option 2 which is described in detail in the GE study forwarded with the BWR owners' Group position. X .1. 51 MODIFY BR EA K-DET ECTION LOGIC TO PREVENT SPURIOUS ISOLATICN OF HIGH PRESSURE COOLANT INJ ECTION AND ___ REACTOR COPE ISOLATION COOLIN U Ii.K.1.15) _ _ _ _ 1212 51.1 Statomont of Raquiggment The high-pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) systems use differential pressure sensors on elbow taps in the steam lines to their turbine drives to detect and isolate pipe breaks in the systems. The pipe-break-detection circuitry has resulted in spurious isolation of the HPCI and RCIC systems due to the pressure spike which accompanies startup of the systems. The pipe-break-detection circuitry should be modified so that pressure spikes resulting from HPCI and RCIC system initiation will not cause inadvertent system iso la tio n. All applicants for operating license should submit documentation 4 months ptior to the expected issuance of the staff safety evaluation report for an operating license or 4 months prior to the listed implementation date (July 1, 1981), whichever is later. X.1.51.2 Interagetation None required. X.1.51.3 Statement of Response The BWR Owners' Group has performed an evaluation and recommends the f ollowing modification to the steamline break detection logic. In order to minimize inadvertent HPCI/RCIC isolation due to pressure transients during system initiation, a time delay relay, set at approximately three (3) seconds, is to replace the existing relay in the steamline high differential pressure circuitry. The time delay feature assures that the steamline break isolation signal is, in fact, due to continuous high steam flow. See Figure X.1.51-1. The time delay relay shall be class lE, with an adjustable time delay setting of 0-5 seconds. This classification is compatible with the system's existing circuitry. Two time delay relays are required for the trip system logic for both the HPCI and RICI systems. A design assessment study shall confirm the appropriate time-delay setting. X.1-91

FIGURE X.1.51-1 FUSE CLOSE ON 111C11 OTilER ISOLATION SIGNALS I {---- f - - DIFF. PRESSURE l j ,

                                                                                                                                                                                       , s '/
                                                                                                                  /
                                                                                                                                               /          TIME DELAY            ,'
                                                                                                                /                            /            RELAY CONTACT i                                                                                                              /                            /
                                                                                                     /                                    /

DPIS DPIS Y T REPLACE WITil TDtE DELAY RELAY AUTO ISOLATION RELAY gy

FUSE TYPICAL IIPCI/RCIC STEAMLINE BREAK DETECTION LOGIC

I.1.52 REDGCTION OF CHALLENGES AND FAILURES OF RELIEF VALVES ' _III.K.3.In _ I.l.52.1 statement oLJeguirement The record of relief-valve failures to close f or all boiling-water reactors (BWas) in the past 3 years of plant operation is approximately 30 in 73 reactor-years (0.41 failures per reactor-year) . This has demonstrated that the failure of a relief valve to close would be the most likely cause of a small-break l o ss- o f-coolant accident (LOCA). The high failure rate is the result of a high relief-valve challenge rate and a relatively high f ailure rate per challenge (0.16 f ailures per challenge) . Typically, five valves are challenged in each event. This results in an equivalent failure rate per challenge of 0.03. The challengo and failure rates can be reduced in the following ways: (1) Additional anticipatory scram on loss of feedvater, (2) Revised relief-valve actuation satpoints, (3) Increased emergency core cooling (ECC) flow, (4) Lower operating pressures, (S) Earlier initiation of ECC systems (6) Heat removal thrcugh emergency condensers, (7) Offset valve setpoints to open fewer valves per challenge, (8) Installation of additional relief valves with a block- or isolation-valve feature to eliminate opening of the safety / relief valves (S R V s) , consistent with the ASME Code, (9) Increasing the high steam line flow setpoint for main steam line isolation valve (MSIV) closure, (10) Lovering the pressure setpoint for MSIV closure, (11) Reducing the testing frequency of the MSIVs, (12) More-stringent valve leakage criteria, and l (13) Early removal of leaking valves An investigation of the feasibility and contraindications of reducing challenges to the relief valves by use of the aforementioned methods should be Conducted. Other methods should also be included in the feasibility study. Those changes which are shown to reduce relief-valve challenges without compromising the perf ormance of the relief valves or other systems should be implemented. Challenges to the relief valves shoold be reduced s ubsta ntially (by an order of magnitude) . ! I.1-93 i

Results of the evaluation shall be submitted by April 1, 1991 for staff review. The actual modifica tion shall be accomplished during the next scheduled refueling outage following staff approval or no lator than 1 year following staff spproval. Modificaticn to be implemented should be documented at the time of implementation. 1 1.522 2 Integggetation None required. 1.1.52.1 Sta tement of Response The BWH Owners' Group (B W ROG) is developing reccamendations to comply with this requirement. These recommendations are scheduled to be available for review in March 1981. PPSL will prepare a final response following review of the EWROG report. I.1.53 REPORT ON OUTAGES OF EMERGENCY COEE COOLING SYSTEMS _ JII.K.3 tl71 _ __ 1 1.51.1 Statement of Requiregent Several components of the emergency core-cooling (ECC) systems are permitted by technical specifications to have substantial outage times (e.g. , 72 hours for one diesel-generator; 14 days f or the HPCI system) . In addition, there are no cumulative outage time limita tions for ECC systems. Licensees should submit d report detailing outage dates and lengths of outages for all ECC systems for the last 5 years of operation. The report should also include the causes of the outages (i. e . , controller failure, spurious isolation). X.1.53.2 Interpretation Licensees should provide a report which contains emergency core cooling system unavailability data. This requirement can not be applicable to SSES, since the plant has never operated. X.1.53.2 Statement of_ Response This requirement is not applicable to SSES. X. l. 5 4 MODIFICATION OF AUTOMATIC DEPRESSURIZ ATION SYSTEM LOGIC (II.Kz 3.181 _ __ X.1.54.1 jtatement of Requiremeni The automatic depressurization system ( ADS) actuation logic should be modified to eliminate the need for manual actuation to assure adequate core cooling. A feasibility and risk assessment study is required to determine the optimum approach. One possible scheme that should be considered is ADS actuation on low I.1-94

reactor-vossel water level provided no high-pressure coolant injection or high-pressure coolant system flow exists and a low-pressure emergency core cooling system is running. This logic would complement, not replace, the existing ADS actuation logic. Applicants for operating license shall provide results of feasibility study 1 year prior to issuance of operating license. A description of the proposed modification f or staff approval is required 4 months prior to issuance of an operating license. X.1.542 2__Intag2retation The ADS actuation logic may not be automatically actuated for steam line breaks (SLB) outside con tainment. The operator must manually actuate the ADS af ter diagnosing that an SLB has occurred. The ADS actuation logic should be modified to provide automatic actuation for all Design Basis Accidents. I.lz54.3 Statement of Rosponse The BWR owners' Group (BW RO G) is currently perfctming a generic feasibilit y study. The results of this effort are scheduled to be available for review in March 1981. PPSL will prepare a response following review of the BWDOG report. X.1.55 BESTART OF CORE SPRAY AND LOW PRESSURE COOLANT INJECTION SYSTIMS (II.K.3.21L_ _ __ x,1.55.1 Sta_tement of_Fequirement The core-spray and low-pressure, coolant-injection (LpCI) system flow may be stopped by the operator. These systems will not restart automatically on loss of water level if an initiation signal is still present. The core spray and LPCI system logic should be modified so that these systems will restart, if required, to assure adequate core cooling. Because this design modification affects several core-cooling modes under accident conditions, a preliminary design should be submitted for staff review and approval prior to making the actual modification. All applicants for operating license should submit documentation 4 months prior to the expected issuance of an operating license or 4 months prior to the listed implementation date, whichever is later. X.1.55.2 Intagaretation None required. 131 5 5. 3_ _ gta tement _of R espon se X.1- 95

PPSL concurs with the BWR Owners' Group position which was forwarded to the NRC by letter from D. B. Waters (BWROG) to D. G. Eisenhut (NaC), December 29, 1980. The BWROG report states that the current ECCS design represents the optimum approach to BWR safety. No modifications to tisting LPCI and core spray systems are necessary in response to s .is requirement. X.1.56 AUTOMATIC SWITCHO7ER OF 3EACTOR CORE ISOLATION _ COOL _ Igg _S Y ST EM SUCTION JII.K.3.22L X.1.56.1 Sta temen t of Reguirement The reactor core isolation cooling (RCIC) system takes suction from the ccndensate storage tank with manual switchover to the suppression pool when the condensa te storage tank level is low. This switchover should be made automatically. Until the automatic switchover is implemented, licensees should verify that clear and cogent procedures exist for the manual switchover of the RCIC system suction from the condensate storage tank to the suppression pool. Documentation must be submitted 4 months prior to issuance of the staff safety evaluatica report or 4 months prior to the implementa tion date, whichever is later. Modifications shall be completed by January 1, 1982. X.1.56.2 In terpletaMon None required. X.1.56 s ]__ Statement of Response Banual switchover of the RCIC suction f rom the condensate storage tank (CST) to the suppression pool on low CST level is covered in the Emergency operating Procedures. Specifically, this item is addressed in the following Emergency Operating Procedures: EO-00-022 (Coold own) Section 2.C. EO-00-023 (Containment Control) Section 2.D. This procedural muidance is an intersim measure and will be revised to diser , automatic switchover of the RCIC suction when the design change is implemented. The design changes for automatic switchover are being developed. All modifications will be completed by January 1982. X 1-96

I.l.57 CONFidd ADECUACY OF SPACE COOLING FOR HIGH PRESSURE COOLANT INJECTICN AND RE ACTOR CORE _ ISOLATION COOLING _ SYSTEMS JII.K.l.24L_ X.1.57.1 Statement of_Raguiremo_nt Long-term operation of the reactor core isolaticn cooling (RCIC) and high-pressure coolant injection (HPCI) systems may require space cooling to maintain the pump-room tem pe ra tures within allowable limit s. Licensees should verify the acceptability of the consequences of a complete loss of alternating-current (AC) power. The RCIC and HPCI systems should be designed to withstand a complete loss of offsite AC power to their support systems, including coolers, f or at least 2 hours. All applicants for operating license should submit documentation 4 months prior to the expected issuance of the staff safety evaluation report f or an operating license or 4 months prior to the listed implementation date, wFichever is later. X.12 57.2 Int"I21etation Confirm that HPC and RCIC room cooling can be maintained to enable continuous operation during a loss of of f site AC power for 2 hours. X.1.57.3 Statement of_ Response The HPCI and RCIC room unit coolers and their support systems are designed to withstand the consequences of a complete loss of offsite AC power since these are powered from onsite diesel generators. Each HPCI and RCIC room is provided with a 100% capacity redundant unit cooler. Refer to Subsection 9.4.2.2. X.1.58 EFFECT OF LCSS OF ALTERNATING-CURRENT POWER ON __ R_ECIRCUL ATION PUM P SEA LS_ (II. K. 32 2 5) X2 12582 1 Statement of Requirement The licensees should determine, on a plant-specific basis, by analysis or experiment, the consequences of a less of cooling water to the reactor recirculation pump seal coolers. The pump seals should be designed to withstand a complete loss of alternating-current (AC) power for at least 2 hours. Adequacy of the seal design should be demonstrated. ~ Applicants for operating licenses shall submit th- evaluation and proposed modifications no later than 6 months prior to expected issuance of the staff safety evaluation report in support or license issuance, whichever is later. Modifications must be completed by January 1, 1982. X.1.58.2__ Interpretation X.,1- 9 7

Evaluate the effect of a less of offsite AC power for 2 hours on the recirculation pump seals. 1s.1158.3 11dtement_of RegEgggg The BWR Owners' Group (B W RCG) is performing an evaluation in response to this requirement. The results of this effort are scheduled to be available for review in April 1981. PPSL will prepare a response following review of the BWROG report. Preliminary results indicate a 2 hour loss of offsite AC power does not produce a significant impact to the safe operation of the plant. X.1. 5 9 PROVIDE A COMMON REFERENCE LE7EL __f0R VggSEL LjVEL INSTRUMENT ATION_IIIz f. 3. 27L X.1.59.1__ Statement of Requiremont Different reference points of the various reactor vessel water level instruments may cause operator confusion. Therefore, all love. instruments should be referenced to the same point. Either tie bottom of the vessel or the top of the active fuel are ree.sonable reference points. All applicants for operating license should submit documentation 4 months prior to the expected issuance of the staff safety evaluation report for an operating license or 4 months prior to the listed implementation date, whichever is later. X2 1.59.2 Interspetation None required. X.1.59.3 Statement of Response , The BWR Ow ners' Group (BWBOG) has performed a generic ew.luation in response to this requirement. This was transmitted to D.G. l Eisenhut by letter from D. B. Waters on December 29, 1980. They have stated no changes are necessary and the present system is fully adequate to allow plant operators to respond properly under all postulated reactor conditions. PPSL has reviewed the BWHOG evaluation and concurs with its findings. Therefore no changes will be made to vessel level instrumentation. l X.1.60 VERI?Y QUALIFICATION OF ACCUMULATORS ON AUTO M AT IC DEPRESSURI2ATION SYSTEM __ VALVES III.K.3.28) ___ X.1.60.1 Statement of Requirement Safety analysis reports claim that air or nitrogen accumulators for the automatic depressurization system (ADS) valves are provided with sufficient capacity to cycle the valves open five X.1-98

i l times at design pressures. GE has also stated that the emergency core cooling (ECC) systems are designed to withstand a hostile environmen t and still perform their function f or 100 days following an accident. Licensee should verify that the accumulators on the ADS valves meet these requirements, even considering normal leakage. If this cannot be demonstrated, the licensee must show that the accumulator design is still acceptable. The ADS valves, accumulators, and associated equipment and instrumentation must be capable of performing their functions during and following exposure to hostile environments and taking no credit for nonsafety-related equipment or instrumentation. Additionally, air (or nitrogen) leakage through valves must be accounted for in order to assure that enough inventory of compressed air is available to cycle the ADS valves. All applicants for operating license shall submit documentation 4 months before the expected issuance of the staf f safety evaluation report for an operating license or 4 months before the listed implementation date, whichever is later. 3 1.60.2 Interpretation None required. X.1.60.3 Statement of Response The BWR Owners' Group (BWROG) is performing a generic evaluation in response to this requirement. The results of this effort are scheduled to be available for review in May 1981. pPSL will prepare a response following review of the BWROG report. I.l.61 REVISED SMALL-BREAK LOSS OF COOLANT ACCIDENT METHODS

           .l M & h 1 9 L -                -                    -

x.1.61,1__ Statement of aequirement The analysis methods used by nuclear steam supply system vendors and/or fuel suppliers for small-break loss-of-coolant accident (LOCA) analysis for compliance with Appendix K to 10 CFR Part 50 should be revised, documented and submitted f or NRC a pproval. The revisions should account for comparisons with experimental data, including data from the LOFT test and Semiscale Test facilities. The Bulletins and Orders Task Force identified a number of concerns regarding the adequacy of curtain features of small- -break LOCA models, particularly the need to confirm specific model features (e.g. , condensation heat transfer rates) against applicable experimental data. - These concerns, as they applied to each light-water reactor (LW R) vendor's models, were documented in the task force also concluded that, in light of th e TM I- 2 X.1-99

accident, additional systems verification of the small-break LCCA model as required by II.4 of Appendix K to 10 CFR 50 was needed. This included providing experimental verificatica of the various modes of single-phase and two-phase natural circulation predicted to occur in each vendor's reactor during small-break LOCAs. Based on the cumulative staf f requirements f or sdditional small-break LOCA model verification, including both integral system and separate effects verification, the sta f f considered model revision as the appropriate method for reflecting any potential upgrading of the analysis methods. The purpose of the verification was to provide the necessary assurance that the small-break LOCA models were acceptable to calculate the behavior and consequences of small primary system breaks. The staff believes that this assarance can alternatively be provided, as appropriate, by additional justification of the acceptability of present small-break LOCA models with regard to specific staff concerns and recent test data. Such justification could supplement or supersede the need for model revision. The specific staff concerns regarding small-break LOCA models are provided in the analysis sections of the BSO Tack Force reports for each LWR vendor, (NUR EG-0 63 5, -0565, -0626, -0611, and - 0623). These concerns should be reviewed in total by each holder of an approved emergency core cooling system model and addressed in the evaluation as appropriate. The recent tests include the entire Semiscale small-break test series and LOFT Tests (L3-1) and L3-2) . The staff believes that the present small-break LOCA models can be both qualitatively and quantitatively assessed against these tests. Other separate effects tests (e.g. , ORNL core uncovery tests) and future tests, as appropriate, should also be factored into this assessment. Based on the preceding information, a detailed cutline of the proposed program to address this issue should be submitted. In particular, this submittal should identif y (1) which areas of the models, if any, the licensee intends to upgrado, (2) which areas the licensee intends to address by further justification of acceptability, (3) test data to be used as part of the overall verification / upgrade effort, and (4) the estima te? schedule f or performing the necessary work and submitting this information for staff review and approval. Licensees shall submit an outline of a program f or model justification / revision by November 15, 1980. Licensees shall submit additional inf ormation for model justifica tion and/or revised analysis model for staff approval by January 1, 1982. Licensees shall submit their plant-specific analyses using the revised models by January 1, 1983 or one year af ter any model revisions are approved. Applicants shall submit appropriate information in accordance with the licensing review schedule. I.1-100 4

I X.1.61.2 In t e r preta t io n None required. X.1.61.1 Statement Of nesponse PPSL considers that the reactor vendor, General Electric, is the most appropriate party to work with the staff in resolving staff concerns with small break LOCA models f or BWRs. Accordingly, the staff should direct their questions regarding the scope and schedule for this requirement to General Electric (a t tn. a. H. Duchholz, Manager, BWR Systems Licensing) . Copies of correspondence on this item should be sent to PPSL so that we may remain cognizant of the progress of the prog ram to resolve the staff's concerns on this requirement. X.1.62 PL ANT-SPECIFIC CA LCULATICNS TO SHOW COMPLIANCE WITH 10CFR ___ 23RI_50 2 u6 JII.K.3,31t_ ___ _ _ _ _ _ _ ___ 121252 1 S t a _t eme n t of Reguirement Plant-specific calculations using NRC-approved models for small-break loss-of-coolant accidents (LOCAs) as described in item II.K.3.'30 to show compliance with 10 CF3 50.46 should be submitted for NRC approval by all licensees. X.1.62.2 InterEIetation None required. 1 1.62.3 Spit e me n t_ o _f _ _ R e s po n ce Plant specific calculations will be performed following NRC approval of LOCA model revisions required by item II.K.3. 30 (see Subsection X.1.61). X 1.63 JVALUATION OF ANTICIf3TED TR ANSIENTS WITH SINGLE FAILURE TO VERIFY NO FUEL CLADDING F.\ILURE_JII.K.3z44L X 1.63.1 Statement of Requirement For anticipated transients combined with the worst single f ailure an assuming proper operator actions, licensees should demonstrate that the core remains covered or provide analysis to show that no significant fuel damage results from core uncovery. Transients which result in a stuck-open relief valve should be included in this category. All applicants for operating license should submit documentation 4 monthsLprior to the expected issuance of the staff safety evalaution report for an operating license or 4 months prior to the listed implementation date, whichever is la ter. X.1-101

fzl.63.2 In ter2reta t ion None required. 121253.1_ Statement of Resoonse The BWa owners' Group has prepared a generic response to this requirement. The report was transmitted to D. G. Eisenhut by a letter from D. D- Waters on December 29, 1980. This responae contains an evaluation of analyses performed to demonstrate the core remains covered or no significant fuel damage occurs from an anticipated transient with a single failure. PPSL is reviewing this report and will subsequently prepare a response to this requirement. 121.64_ XV ALUATION Of_DEPR ESSU RIZ ATION WITH OT H,*E_TE AN_TE E AUTOMATIC DjPPESSURIZATION _3YSTE3_JII.K.3.4jl 121264.1 jiatament_o f Re231gggent Analyses to support depressurization modes other than full actuation of the automatic depressurization system (ADS) (e. g. , early blowdown with one or two safety relief valves) should be provided. Slower depressurization would reduce the possibility of exceeding vessel integrity limits by rapid cooldown. All applicants for operating license should submit documentation 4 months prior to the expected issuance of the staff safety evaluation report for an operating license or 4 months prior to the listed implementation date, whichever is later. X.1.64.2 _Intgggggtation None required. x.l.64.3 Statemen1_of Response The BWR Owners' Group submitted a generic responde to this requirement. This response was transmitted by letter to D. G. Eisenhut from D. B. Waters on December 29, 1980. PPSL has reviewed this response and find it applicable to SSES. The report concludes that no improvement can be gained by a slower depressurization and actually could be detrimental to core cooling. Therefore no additional action is necessary in response to this requirement. x21. 6 5 MICHELSON CONCERNS (II. K 3. 4 61 X.1.6521 Statement of Reguirement A number of concerns related to decay heat reacval following a very small break LOCA and other related items were questioned by I.1-102

a Mr. C. Michelson of the Tennessee Valley Authority. These concerns were identified for PWas. GE was requested to evaluate these concerns as they apply to BWRs and to assess the importance of natural circulation during a small-break LOC A in 87Rs. X.1.65 2 2 Interpretation None required. X.1.65.3 Statement of Rasponsg The General Electric Company has responded to the questions posed by Mr. Mic helson. This response was sent by letter from R. H. Suchholz to D. F. Ross on February 21, 1980. These responses are applicable to SSES and no further response is necescary. 12125.5._. 13EE9E3Cl_ffIE3EIE23EE )) ORT TEld_JIII.A.1.1L No requirement stated in NUREG 0737. Refer to Subsection X.2.38 which contains the response to the requirement in NUREG 0694 Xz l.67 UPGRADE {MEFGjNCY SUPP03T FACILITIES _JIII.A.l.2L X.1.67.1. Statement _gf_He<1uirement Requirement to be issued in NUREG 0696. 121 67,2 Internggiation None required. X.1.67.3 Statement of Response The response to this requirement will be incorporated into Appendix I of the Emergency Plan. X.1.68 J3ERGENCY PR EP AH EDNESS-LONG TERM JIII. A. 2L X.1.68.1 Statgggnt of_Rggui Igsent Each nuclear facility shall upgrade its emergency plans to provide reasonable assurance that adequate protective measures l can and will be taken in the event of a radiological emergency. l Specific criteria to meet this requirement is delineated in NUREG-0654 (FEMA-REP-1), " Criteria for Preparation and Evaluation of Radiological-Emergency Response Plans and Preparation in Support of Nuclear .'over Plants." NUREG-0654, Revision 1; NUREG-0696, " Functional Criteria for Emergency Response Pacilities;" and the amendments to 10 CFR Part

 -50 and Appendix E to 10 CFR Part 50 regarding emergency I.1-103

preparedness, provide more detailed criteria for emergency plans, design, and functional criteria for emergency response f acilities and establishes firm dates for submission of upgraded emergency plans for installation of prompt notification systems. These revised criteria and rules supersede previous ccamission guidance for the upgrading of emergency preparedness at nuclear po wer facilities. Requirements of the new emergency-preparedness rules under paragraphs 50.47 and 50.54 and the revised Appendix E to part 50 taken together with NUBEG-0654 3evision 1 and NUREG-0696, when approved for issuance, go beyond the previous requirements for meteorological programs. To provide a realistic time f rame for implementa tion, a staged schedule has been established with compensating actions provided for interim measures. Specific milestones have been de'., loped and are presented below. Milestones are numbered and tagged with the following code; g-date, b-activity, e-minimu m a cceptance critaria. They are as follows: (1) a. Fuel load.

b. Submittal of radiological emergency response plans.

c. A description of the plan to include elements of NUREG-0654, Revision 1, Appendix 2.

(2) a. Fuel load.

b. Submittal of implementing procedures.

c. Methods, systems, and equipment to assess and monitor actual or potential off site consequences of a radiological emergency condition shall be provided.

(3) a. Fuel load.

b. Implementation of radiological emergency response plans.

c. Four elements of Appendix 2 to NUREG-0654 wth the exception of the class B model of element 3, or Alternative to ites (3) requiring compensating actions:

A meteorological measurements program which is consistent with the existing-technical specifications as the the baseline or an element 1 program and/or l element 2 system of Appendix 2 to NUREG-0654, or two independent element 2 systems shall provide the basic X.1-104 . I

meteorological parameters (wind direction and speed and an indicator or atmospheric stability) on display in the control room. An operable dose calculational methodology (DC M) shall be in use in the control room and a t appropriate emergency response f acilities. The following compensating actions shall be taxen by the licensee for this alternative: (i) If only element 1 or element 2 is in use: o The licensee (the person whc will be responsible for making offsite dose projections) shall check communica tions with the cognizant National Weather Service (NWS) first order station and NWS forecasting station on a monthly basis to ensure that routine meteorological observations and f orecasts can be accessed. o The licensee shall calibrate the meteorological mea surements program at a frequency no less than quarterly and identif y a readily available source of meteorological data (characteristic of site conditions) to which they can gain access during calibration periods. o During conditions of measurements system unavailability, an alternate source of meteorological data which is characteristic of site conditions shall be identified to which the licensee can gain access. o The licensee shall maintain a site inspection schedule for evaluation of the meteorological measurements program at a frequency no less than weekly. o It shall be a reportable occurence if the meteorological data unavailability exceeds the goals outline in Proposed Revision 1 to Regulatory Guide 1.23 on a quarterly basis. (ii) The portion of the DC3 relating to the transport and diffusion of gaseous effluents shall be consistent with the characteristics of the Class A model outlined in element 3 of Appendix 2 to NUREG-0654 (iii) Direct telephone access to the individual responsible for making offsite dose projections (Appendix E to 10 CFR Part 50 (IV) (A) (4) ) shall be available to the NRC in the event of a X.1-105

radiological omergency. Procedures for establishing contact and identifica tion of contact individuals shall be provided as part of the implementing procedures. This alternative shall not be exercised after July 1, 1982. Further, by July 1,1981, a f unctional description o f the upgraded programs (four elements) and schedule for installation and full operational capability shall be provided (see milestones 4 and 5) . (4) a. March 1, 1982.

b. Installation of Emergency Response Facility hardware and sof tware.
c. Four elements of Appendix 2 to NUREG-0654, with exception of the Class a modal of element 3.

(5) a. July 1, 1982.

b. Full operational capability of milestone 4.

c. The Class A model (designed to be used out to the plume exposure EPZ) may be used in lieu of Class B model out to the ingestion EPZ. Compensating actions to be taken for extending the application of the Class A model out to the ingestion EPZ include access to supplemental inf orma tion (meso and synoptic scale) to apply judgment regarding intermediate and long-range transport estimates.

The distribution of meteorological information by the licensee should be as follows by July 1,1982: l l < X.1- 10 6 y e--

NRC and Emergency Meteorological Response Organiza-Information CR TSC EOF tions Basic Met. Data X X X X (N RC) (e. g. , 1.97 Parameters) Full Met. Data X X X (1.23 Paraseters) DCM (for Dcse X X X X Pcojections) Class A Model (to X X X X Plume Exposure EPZ) Class B Model or X X X Class A Model , (to Ingestion EPZ) (6) a. July 1,1982 or at the time of the completion of milestone 5, whichever is sooner.

b. Mandatory review of the DCM by the licensee.

c. Any DCM in use should be reviewed to ensure consistency with the operational Class A model.

Thus, actions recommended during the initial phases of a radiological emergency would be consistent with those af ter the TSC and EOF are activated. (7) a. September 1, 1982.

b. Description of the Class B model provided to the NRC.

c. Documentation of the technical bases and justification for selection of the type Class a model by the licensee with a discussion of the l

site-specific attributes. (8) a. June 1, 1983.

b. Full operational capability of the Class B model.

l c. Class B model of element 3 of Appendix 2 to NUREG-0654, Revision 1 Applicants for an operating license shall meet at least milestones 1, 2, and 3 prior to the issuance of an operating license. Subsequent milestones shall be met by the same dates indicated for operating reactors. For the alternative to milestone 3, the meteorological measurements program shall be consistent with the NUREG-75/087, " Standard Review Plan for the Review of Safety Analysis Reports for Nuclear X.1-107 L

Power Plants," Secton 2.3.3 program as the baseline or element 1 and/or element 2 systems. X.1.68.2 _ Interpretation None required. X.1.68 2 3 Statement of Resnonsn Miles tones 1, 2 and 3 are being addressed as a part of the short term emergency preparedness requirement III.A.l.l. Refer to subsection X.2.38 for response. Responses to these and other milestones will be incorporated into Appendix I of the Emergency Plan. I.1.69 INTEGRITY OF SYSTEMS OUTSIDE CONT AINM ENT LIKELY TO CONTAIN _ ____M DIOACTIVE__ MATERIAL (III.D.1.IL_ ______ X 1.69.1 Statement of_Reguirement Applicants shall implement a program to reduce leakage from systems outside containment that would or could contain highly radioactive fluids during a serious transient or accident to as-Ice-as-practical levels. This program shall include the following: (1) Immediate leak reduction. (a) Implement all practical leak reduction measures for all systems that could ca rry radioactive fluid outside of containment. (b) Measure actual leakage rates with systnm in operation and report them to the NRC. (2) Continuing Leak Reduction--Establish and implement a program of preventive maintenance to reduce leakage to as-low-as-practical levels. This program shall include periodic integrated leak tests at intervals not to exceed each refueling cycle. This requirement shall be implemented prior to issuance of a f ull-power lice nse. Applicants shall provide a summary description, together with initia l leak-test results, of their program to reduce leakage from systems outside containment that would or could contain primary _ coolant or other highly radioactive fluids or gases during or.following a serious transient or accident. Applicants shall submit this inf ormation at least 4 months prior to f uel load. X.1.69.2 In ternIn tation I.1-108

None required. X.1.69.3 Statement of Response

1. Program summary description:

1.1 The f ollowing systems will be leak tested (the frequency is indicated in () after each each ites): A. Residual Heat 3emoval (18 months) B. Reactor Core Isolation Cooling " C. Core Spray " D. High Pressure Core Injection " E. Scram Discharge " F. Reactor Water Clean-up " G. Standby Gas Treatment " H. Containment Air monitors. " Initial leak-test results will be available when the first measurements are made, prior to completion of the startup test program. 1.2 The following systems contain radioactive material but are excluded from our program (justification for exclusion , follows each item) : A. Main Steam - identified by NEDO-24782 as not to be regarded as containing highly radioactive fluid f ollowing an accident. B. Feed water - same justification as A. C. Main Steam Line Drain - this system is isolated following a LOC A. D. Reactor Water Sample - this system will not be used following an accident, a separate post-accident sampling station is being developed in response to item II.B.3. E. Recirc Pump Seal Water --line is protected by a check valve and an excess flow check valve. F. Floor & Equipment Drains - this sytem isolated following a LOCA and will not be used following an accident. G. Suppression Pool Clean-up & Drain - same justification as F. 1.3 Method for obtaining actual leak rates X.1-109 c

A. Water - leakage will be collected in a graduated measuring device and timed to determine GPM leak rate. Implementing

          ,            procedures will establish criteria for initiation fo leak rate quantification.

B. Steam - an estimate of the size of the leak will be made (i.e. equivalent pipe diameter steam flow) . Flowrate will be determined using standard Handbook data. This will be converted to a GPM flowtate using the specific volume of the steam at the given conditions.

2. The two gaseous systems a re tested as folicws:

A. Standby Gas Treatment System - This system is subjec to filter efficiency testing in accordance with the Technical Specifications which includes "DOP" and refrigerant injection. B. Containment Air Monitors - These are tested while the system is under normal running conditions by checking each mechanical joint with liquid soap.

a. Consideration was given to the Standby Gas system regarding the incident at horth Anna Unit 1 in 1979. The standby gas piping and duct work from the containment to the filters are gas tight and do not include any pressure relief devices which would allow gases to escape to the Reactor Building.

The piping is rated at 150 psig and the duct work is H73-GS-G (High Velocity Medium Pressure - Galvanized Steel - Gas tight). In light of the above, the actions stated in 1.1.G and 2.A have resulted.

4. Technical Specifications will incorporate an acceptance criteria of 5 GP5 total leakage rate for the systems listed in'l.1 with the exception of:

A. Standby Gas' Treatment - which is limited to the Technical Specifications acceptance criteria stated in Subsection 4.6.5.3 and B. The containment air monitors - which has an acceptance criteria of zero leakage as determined by a liquid soap test. The program will implemented prior to fuel load. X .1. 7 0 INPLA NT IODINE B ADI ATICN MONITOpING {III.D.3.3L r.1.70.1 Statement _of Requirement X.1-110

Each licensee shall provide equipment and associated training and procedures for accurately determining the airborne iodine concentration in areas within the facility where plant personnel may be present during an accident. Effective monitoring of increasing iodine levels in the buildings under accident conditions must include the use of portable instruments using sample media that will collect iodine selectively over xenon (e. g. , silver zeolite) for the following reasons: (1) The physical size of the auxiliary and/or fuel handling building precludes loca ting stationa ry monitoring instrumentation at all areas where airborne iodine concentration data might be required. (2) Unanticipated isolated " hot spots" may occur in locations where no stationary monitoring instrumentation is located. (3) Unexpectedly high background radiation levels near stationary monitoring instrumentation after an accident may interfere with filter radiation readings. (4) The time required to retrieve samples after an accident may result in high personnel exposures if these filters are located in high-dose-rate areas. After January 1, 1981, each applicant and licensee shall have the capability to remove the sampling cartridge to a low-background, low-contamination area for further analysis. Normally, counting rooms in auxiliary buildings will not have sufficiently low backgrounds for such analyses following an accident. In the low background area, the sample should first be purged of any entrapped noble gases using nitrogen gas or clean air free of noble gases. The licensee shall have the capability to measure accurately the iodine concentrations present on these sam ples under accident conditions. There should be sufficient samplers to sample all vital areas. X.1.70.2 Interpretation PPSL is in basic agreement with the technical discussion as outlined in this requirement. It should be noted that SSES is a BWR and does not possess an auxiliary building. Consequently, it is premature to suggest that our counting facilities within the control structure will be inadequa te to effectively count air samples. Additionally, purging of the air sample cartridges may not be necessary if an effective collection media is used for radioiodine air sampling. I . l . 7 0. 3 statement of Response X.1-111

4 i PPSL intends to meet the requirements defined in this item. To summarize the program being implemented, three (3) Eberline Instrument Corporation PING - 2A Pa rticula te, Iodine and Noble Gas Air Monitoring Systems are provided for air sampling plant dreas where personnel may be presented during accident conditions. The systems are cart mounted with battery back-ups. Grap samples are obtained using the equipment specified in Subsection 12.5.2.6.3. During accident conditicns silve zeolite cartirdges will be used for radioiodine analysis in conjunction w ith two (2) Eberline stabilized assay meters (SAM-2) . Air samples are evaluated as specified in Subsection 12.5.3.5.5. In addition to initial training provided for Health Physics personnel, periodic drills are conducted in accordance with the Susquehanna Emergency Plan Section 8.1.2 (See Amendment 25 of Operating License Application). Analysis of iodine cartridges will be performed in a low background, low contamination area. During accident conditions, preliminary analysis will be performed by onsite radiation monitoring teams in the counting room, if accessible using a SAM-

2. Final analysis will be performed in the health physics facilities in the training center (onsite) or in another laboratory facility (of f site) where appropriate sensitivity can be achieved. Prior to analysis, cartridges will be purged using station service air or bottled nitrogen which is stored on site.

All equipment and procedures will be available for use by fuel load. X.1.71 CONT ROL ROOM HABITABILITY REQUIREMENTS (III.D.3.4) X.1.71.l_ Statement of Requirement Licensees shall assure that control room operators will be adequately protected against the effects of accidental release of toxic and radioactive gases and that the nuclear power plant can be safely operated or shut down under design basis accident conditions (Criterion 19, " Control Room," of Appendix A, " General Design Criteria for Nuclear Power Plants," to 10 CFR Part 50). All licensees must make a subaittal to the NBC regardless of whether or not they met the criteria of the Standard Review Plans (SBP) sections listed below. The new clarification specifies that licensees that meet the criteria of the SRPs should provide the basis by referencing past submittals to the NaC and/or providing new or additional information to supplement past submittals. I.l.71.1.1 Requirements for Licensees that _ Meet Criteria All licensees with control rooms that meet the criteria of the following sections of the Standard Review Plan: X.1-112

2.2.1-2.2.2 Identification of Potential Hazards in Site Vicinity 2.2.3 Evaluation of Potential Accidents; 6.4 Habitability Systems shall report their findings regarding the specific SRP sections as explained below. The following documents should be used for guida nce: (a) Regulatory Guide 1.78, " Assumptions for Evaluating the Habitability of Regulatory Power Plant Control Room During a Postulated Hazardous Chemical Release"; (b) Regulatory Guide 1.95, " Protection of Nuclear Power Plant Control Boom Operators Against an Accident Chlorine Release"; and, (c) K. G. Murphy and K. M. Campe, " Nuclear Power Plant Control Room Ventilation System Design for Meeting General Design Criterion 19," 13th AEC Air Cleaning Conference, August 1974. Licensees shall submit the results of their findings as well as the basis for those findings by January 1, 1981. In providing the basis for the habitability finding, licensees may reference their past submittals. Licensees should, however, ensure that these sub=ittals reflect the current facility design and that the information requested in Attachment 1 of NUREG 0737 is provided. X.l.71.1 2 Pequirements for Licens ees t ha t _ Do_ _Not Meat Criteria All licensees with control rooms that do not meet the criteria of the above-listed references, S tandard Review Plans, Regulatory Guides, and other references shall perform the evaluations and identify appropriate modifications, as discussed below. Each licensee submittal shall include the results of the analyses of control room concentrations from postulated accidental release of toxic gases and control room operator radiation exposures from airborne radioactive material and direct radiation resulting from design-basis accidents. The toxic gas accident analysis should be performed for all potential hazardous chemical releases occurring- either on the site or within 5 miles of the pla n t-si te boundary. Regulatory Guide 1.78 lists the chemicals most commonly encountered in the evaluation of contrcl room habitability but is not all inclusive. The design-basis-accident (DB A) radiation source term should be for the loss-of-coolant accident LOCA containment leakage and engineered safety feature (ESP) leakage contribution outside containment as described in Appendix A and B of Standard Review Plan Chapter 15.6.5. In addition, boiling-water reactor (BWR) facility evaluations should add any leakage f rom the main steam isoaltion valves (MSIV) (i. e. , valve-stem leakage, valve seat

            -                  X.1-113

leakage, main steam isolation valve leakage control system release) to the containment leakage and ESF leakage following a LOCA. This should not be construed as altering the staff recommendations in Section D of Regulatory Guide 1.96 (Sev. 2) regarding MSIV leakage-control s ystems. Other CBAs should be reviewed to determine whether they might constitute a more-severe control-rocm hazard than the LOC A. In addition to the accident-analysis results, which should either identify the possible need for control-room modifications or provide assurance that the habitability systems will operate under all postulated conditions to permit the control-room operators to remain in the control room to take appropriate actions required by General Design Criterion 19, the licensee should submit sufficient information needed for an independent evaluatior. of the adequacy of the habitability systems. Attachment 1 of NUREG 0737, item III.D.3.4 lists the inforcation that should be provided along with the licensee's evaluation. 121211z1z3 _ILocu mentation and_I_mple me nta tion Applicants for operating licenses shall submit their responses prior to issuance of a full power license. Modifications needed for compliance with the control-room habitability requirements specified in this letter should be identified, and a schedule for completion of the modifications should be provided. Implementation of such modifications should be started without awaiting the results of the staff review. Additional needed modificaticas, if any, identified by the staff during its review will be specified to licensees. X.1.71.2 Interpretation None required. Xzlzll.3 _ Statement _of Response The control room HVAC system layout and functional design ! includes protection of the control room f rom radioactive and toxic gases. Subsection 6.4 provides a complete description of this system and compliance to habitability requirements. Refer to Subsection 6.4 for the response to this requirement. (This subsection will be revised by May 1981 to include the response) . ! The revision to Subsection 6.4 will incorporate the following commitments:

1. Supplies of food and potable water adequate to support 30 people (5' operations and 25 Technical Support center personnel) f or 5 days will be maintained onsite.

(

2. Supplies of potassium iodide adequate to protect 30 people will be maintained onsite.

X.1- 1 14 . I

3. Self contained breathing apparatus and bottled air !

supply adequate to support 5 operations personnel for 6 hours will be maintained onsite. For those situations requiring use of SCSA's within the control roos HVAC envelope, the Technical Support Center activities will be relocated to the Emergency Operations Facility. e 4 L I a y [ s: :

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II;1- 115 -

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'f . 2 R ESPO NS E __TO REQUIREMENTS IN NUREG 0694 NUREG 0694 supersedes NUREG 0578. The clarifications given in the Vassallo letter on November 9, 1979 were used in the development of applicable responses. X.2.1 SHIFT TECHNICAL A DVIS0_R_JI. A. I. ll Requirement superseded by NUREG 0737. Refer to Subsection X.1.1 for response. X.2.2 _ SHIFT SUPER VISOR ADMINISTRATIVE _ DUTIES JI.A.l.2L X.2.2.1 Statement of Requirement Beview the administrative duties of the shif t supervisor and delegate functions that detract from or are subordinate to the management responsibility for assuring safe operation of the plant to other personnel not on duty in the control room. This requirement shall be met before fuel load. X.2.2.2 Interoretation None required. X.2.2.3 Statement of Response PPSL has restructured the operations organizaticn and redefined responsibilities of shift personnel to relieve the shift supervisor of routine administra tive duties. Administrative procedure AD-00-026, " Conduct of Operations," implements this policy. The Vice president - Nuclear Operations will review and approve assignment of the Shift Supervisor's responsibilities to ensure proper delegation of duties that detract from or are subordinate to the safe operation of the plant. X.2.3 SHIET MAENING (I. A. l. 3 L Requirement superseded by NUREG 0737. Refer to Subsection X.1.3 for response. X.2.4 IMMEDIATE UPGRADING OF OPERATOR AND SENIOR OPER ATOR IR AIEING AND OU A LIfIpATION JJ. A. 2.1) Requirement superseded by NUREG 0737. Refer to Subsection X.1.4 for response. I.2-1

X.2.5 REVISE SCOPE AND CRITERIA FOR LICENSING EXAMINATIOjj JI.A.3 lt Requirement superseded by NUREG 0737. Refer to Subsection X.1.6 for response. X.2.6 EVALUATION OF ORG ANIZATION AND MAN AGEMENT IMPROVEMENTS CF NEAR-TERM OPER ATING LICENSE APPLICANTS _JI.B.l.2) X.2.6.1 _ Statement of Reguirement The licensee organization shall comply with the findings and requirements generated in an interoffice NBC review of licensee organization and management. The review will be based on an NRC document entitled Draft Criteria for Utility Management and Technical Competence. The first draf t of this document was dated February 25, 1980, but the document is changing with use and experience in ongoing reviews. These draf t criteria address the organizatict, resources, training, and qualifications of plant staff, and management (both onsite and of fsite) for routine operations and the resources and activities (both onsite and offsite) for accident conditions. This requirement shall be met prior to fuel load. 132 6.2 __ Interpretation None required. X2 2.6.] Statement of Response A review of organization and management has been completed in accordance with draft NUREG 0731, " Guidelines f or U tility Management Structure and Technical Competence." An NRC audit of the organization was conducted March 2-6, 1981. A schedule for responding to recommendations made during the audit will be

  . developed prior to fuel load.

X.2.7 SHORT_ TERM ACCIDENT _ ANALYSIS AND PROCEDURE REVISION JI.C.1L Requirement superseded by NUREG 0737. Refer to Subsection X.l.8 for response. X.2.8 SHIZT RELIEF AND TURNOVER _PROCJDURES (I.C.2L X.2.8.1 Statement of Requirement Revise plant procedures for shif t relief and turnover, to require signed checklists and logs to assure that the operating staff (including auxiliary operators and maintenance personnel) possess adequate knowledge of critical plant parameter status, system I.2-2 L.

status, availability and alignment. This requirement shall be met prior to fuel load. X.2.8.2 Interpretation None required. X.2.8.3 Statement of Response Ad ministra tive procedure AD-00-026, " Conduct of Operations," discusses operations personnel responsibilities at shif t turnover. Operations Instruction OP-0I-003, " Shift Turnovers," specifically defines the shif t turnover process. X.2.9 SHIET_ SUPERVISOR RESPONSIBILITIES (I.C z Jl X.2.9.1 Statement of Requirement Issue a corporate management directive that clearly establishes the command duties of the shift supervisor and emphasizes the primary management responsibility for safe operation of the plant. Re vise plant procedures to clearly define the duties, responsibilities and authority of the shif t supervisor and the control roca operators. This requirement shall be met prior to fuel load. X.2.9.2 , Interpretation None required. X.2.9.3 Statement o f_ Response The Vice President - Nuclear Operations shall issue prior to fuel load a sta tement of policy establishing the primary responsibility of the Shif t Supervisor for saf e operation of the plant under all conditions and establishing authority to direct actions leading to safe operation in the Shift Supervisor. The Vice President - Nuclear Operations shall re-issue this statement of policy on an annual basis. Administrative Procedure AD-00-026, " Conduct of Operations," sets forth the plant policy on Shif t Supervisor duties. Training f or Shif t Supervisors includes plant Administrative Procedures, and will encompass AD-00-026. X.2.10 CONTROL ROCM ACCESS JI z C.3[ X.2.10.1 Statement of Requirement Revise plant procedures to limit access to the centrol room to those individuals responsible for the direct operation of the plant, technical advisors, specified NRC personnel, and to I.2-3

establish a clear line of authority, responsibility, and succession in the control room. This requirement shall be met prior to f uel load. X.2.10.2 InteEEretation None required. X.2.10.3 S ta te men t _o f Resgonse Administrative procedure AD-00-026, " Conduct of Operations," provides the authority and instructions for control room access control. X.2.ll _ PROCEDUR ES_ FOR FEEDBACK OF OPERATING EXPERIENCE TO PLANT ST A F F_ (I. C. 51 Requirement superseded by NUREG 0737. Refe r to Subsection X.1.12 for response. X.2.12 NSSS VENDOR REVIEW OF PROCEDURES _JI.C.7L X.2.12.1 Statement _of Requirement obtain nuclear steam supply system vendor review of low-power testing procedures to further verif y their adequacy. This requirement shall be met prior to fuel load. Obtain NSSS vendor review of power-ascension test and emergency procedures to further verify their adequacy. This requirement must be met before issuance of a f ull-pcwer license. X.2.12.2 Interpretation None required. X.2.12.3 Sta tement of Response The General Electric Ccapany, through its site startup organizatica, will review all Startup tests associated with NSSS systems and will review all Emergency opera ting procedures. The startup tests encompass the low power testing and the power l ascension testing phases. These reviews will be completed prior to fuel load. l X . 2.13 PILOT MONITORING OF SELECTED EMERGENCY PROCEDURES FOR NEAR-TER M OP ER ATING_LIC ENSE A PPLIC ANTS _JI.C. 8) X.2.13.1 Statement of__ Requirement Correct emergency procedures, as necessary, based on the NRC , audit of selected plant emergency operating procedures (e. g. , X.2-4

small-break LOCA, loss of feedwater, restart of engineered safety features following a loss of AC power or, stea m-line break) . X.2.13.2 Interpretation None required. X.2.13.3 _ Statement of Response The emergency procedures have been trdnsmitted to the NRC by a letter f rom N. W. Curtis to B. J. Youngblood on March 4, 1981. No further response is necessary until the NRC completes the audit and issues specific requirements. X.2.14 CONTROL ROOM DESIGN (I . D.1) Requirement superseded by NUBEG 0737. Refer to Subsection X.1.16 for response. X.2.15 J3AINING DURING LOW POWER TESTING _JI.G.IL Xz 2 15.1 Statement of Reguiremen_t Define and commit to a special low-power testing program approved by NBC to be conducted at power levels no greater than 5 percent for the purposes of providing meaningf ul technical information beyond that obtained in the normal startup test program and to provide supplemental training. This requirement shall be met before fuel load. Supplement operator training by completing the special low-power test program. Tests may be observed by other shifts or repeated on other shifts to provide training to the o pe ra tors. This requirement shall be met before issuance of a f ull-power license. , X2 2.15.2 Interpretation l None required. X.2 15.3 Statemen t_o f Response The -B WR Ow ners' Group has prepared a generic response to this requirement. This was transmitted to D. G. Eisenhut by a letter from D. B. Waters on Februar y 4, 1981. PP&L concurs with this response. This generic approach outlines an extensive testing program designed to contribute to and provide for extensive training opportunities during . the sta rt-up program. The objectives of this program are to provide:

        .l. A plant that has been thoroughly tested.

X.2-5 e

2. An operating staff that has received the maximum experience and in plant training to safely operate it.

3. Plant procedures that have been reviewed and revised to provide the staff with proven directions and controls.

Susquehanna's operator Training Program has been in progress since 1977 and is completing the final phases of training at this time. This program utilizes the Susquehanna Simulator located at the plant site and provides the operators with extensive training prior to actual operations in the plant itself. The Simulator is also used for procedure development and check out. The Operator Training Program tha t is being developed for the Preoperational and Low Power Testing Program incorporates and builds on the extensive training already completed by the operations section. It will include the recommendation presented in the BWR Owners' Group position but goes beycad those recommendations by maximizing the use of the Susquehanna Simulator in preparing the opera tors f or the start-up tests to be performed. The objective of the Operator Training Program is to provide each operator with the maximum learning experience during the start-up phase. In order to achieve this objective, a comprehensive training program is being developed that utilizes the nany training oppcrtunities that are available during this period and ensures actual testing. This program covers the period f rom Preoperational/ Acceptance Testing through the Power Test Program on Unit I. To support this amount of training the operations section which is staffed for'six sections has reorganized into four sections. This reorganization provided the benefit of allowing mere operators off shift to attend formal training as well as. provide more operating experience for each shif t team. Every effort is being made to keep the shifts intact and provide training that promotes the " Shift Team" concept. The training program being developed covers the areas of activities listed below but recognizes the overlap tha t exists between some of the areas. I. Preoperational/ Acceptance Testing II. Cold Functional Testing III. Hot Functional Testing IV. Start-up Tests V. Additional Testing Each area of testing has activities that lend itself to operator training. The major ones are outlined in Table X.2.15-1. The training prograa provides a vehicle to identify activities that have a significant benefit f or training, documents this training, and ensures that all shift crews receive equal experience opportunities. The program also attempts to schedule repeats of certain evolutions that are considered critical and cannot be X.2-6

routinely performed at a later time. Finally the training program will identify areas of testing / training tha t while not required by start-up program would have additional training benefit. This testing / training could then be scheduled into the testing program as additional testing. Finally this program will develop the basis for the In-Plant Drill Program. This comprehensive approach to testing / training more .than adequately satisfies the requirements of NUREG 0737. 1 l i X.2-7

TABLE X.2.15-1 TESTING PROGRAM OUTLINE I. Preoperational/ Acceptance Testing.

1. Perform system checkout S operations under the direction of the start-up engineer.

2. ECCS Testing.

3. System Flushing.

4 Procedure " dry run". II. Cold Functional Testing.

1. Procedure review / verification parf ormed by operators. ,

2. Operation of equipment for training under the direction of Shift Supervision.

III. Hot Functional Testing.

1. Procedure review / verification performed by operators.

2. Operations of equipment for training under the direction of Shift Supervision.

3. Set up of systems for operations at rated conditions under the direction of the Start-up Engineer or Technical Section Engineer.

IV. Start-Up Testing.

1. Performance of the S tart-Up Test will be balanced among the shifts so each shift will:

a. See at least one reactor scram transient.

b. See at least one pressure regulator transient.

c. See at least one turbine trip or load rejection transient.

l l

d. See at least one water level transient.

e. See at least one recirc ficw t ra nsien t.

l

f. . Operate the HPCI or RCIC system.

2.- Conduct preselected start-up tests on the simulator prior to the actual test in the plant. L 3. Feedback of data / response to the Nuclear Training Department to update the simulator S materials. i X.2-8 i

IAE13_hh15- L f Cont inttedt

4. Provide each shift with training on testing that they did not perform.

V. Additional Testing a group of supplemental tests will be developed, to be performed during the Preoperational Test Program, which will provide meaningful technical information in addition to established test prog ram s. The following procedures will be written or revised to incorporate the supplemental tests as developed by the BWR Owners' Group. The FSAR will be revised as appropriate.

1. IP 2.14 -will be reivsed to incorporate the " Integrated Reactor Pressure Vessel Level Instrumentation Test."

2. P59.2 will be revised to incorporate the " Integrated Containment Pressure Instrumentation Test. "

3. New Technical Procedures (TP's) will be written to incorporate three RCIC System Tests.

a. Start-up of the 2CIC system after a loss of alternating current (AC) power to the system.

b. Operation of the RCIC system with a sustained loss of AC power to the system.

c. Operation of the RCIC system to verify direct current power separation.

i

   -                               X.2-9                                 ,

e

X . 2. _16 SEACTOR CCOLANT SYST_EM_ VENTS (II. 3. ll Requirement superseded Dy NUREG 0737. Refer to Subsection X.1.19 for response. X.2.17 PLANT SHIgtDING_JII.3.2L Requirement superseded by NUREG 0737. Refer to Subsection X.1.20 for response. X2 2218 FOSTACCIDENT_ SAMPLING (II.B.3L Requirement superseded by NUREG 0737. Refer to subsection X.1.21 for response. X.2.19 TR AINING FOR_ MITIGATING CORE CAMAGE (II.B.4L Requirement superseded by NUREG 0737. Refer to Subsection X.1.22 for response. X.2.20 RELIg? AND S AFETY V ALVE TEST _ RE2UIR EM ENTS (II.D.lt Requirement superseded by NUREG 0737. Refer to Subsection X.1.23 for response. X2 3 21 RELIjF AND S AFETY VALVE POSITION INDICATION (II. D. 3L Requirement superseded by NUREG 0737. Refer to Subsection X.1.24 for response. X.2.22 CONTAINMENT ISOLATION DEPENDABILITY (II. E. 4 21 Requirement superseded by NUREG 0737. Refer to Subsection X.1.29 for response. X.2.23 ADDITIONAL ACCIDENT MONITORING _INSTRUMENTATIC;?,(II.F.ll Requirement superseded by NUREG 0737. Refer to Subsection X.1.30 for response. X.2.24 INADEQU ATE CORE COOLING _ INSTRUMENTS (II.722L Requirement superseded by NUREG 0737. Refer to Subsection X.1.31 for response. X.2-10

X.2.25 ASSURANCE OF PROPER ES P FUNCTIONING (II. K l. 5) Xz 2.25.1 _Sta_tement of_Heguirement Review all valve positions, positioning requirements, positive controls and rela ted test and maintonance procedures to assure proper ESF functioning. This requirement sl.all be met by fuel load. X.2.25.2 _ Interpretation None requirad. X.2.25.3 Statement of Response operating and surveillance procedures are currently being developed. Writing +.he procedures to reflect ESF requirement is a key cbjective of procedure originators. Additionally, these proced res will receive a review (independent of the originator) to provide further assurance that the procedura is technically correct and provides for accomplishment of procedural objectives (including maintenance of proper safety function) . X.2.26 SAFETY RELATED SYSTEM OP ER A BI LITY _ ST A TU_S_JII. K.1.101 X.2.26.1 Statement of Reguirement Review and modify, as required, procedures for removing safety-related systems from service (and restoring to service) to assure operability sta tus is known. This requirement shall be met by icel load. X.2.26.2 Inter 2retation None required. X.2.26.3 _ Statement _of Response i l Surveilla nce testing will be controlled by administrative l procedure AD-00-036. This procedure, which is curren tly being drafted, will require that surveillance implementing procedures contain a review of redundant component opecability prior to l removing the system to be tested from service, (if such removal is required by the test) , a review of proper system status prior to return of the tested system to service, and provide for notification to Operations of the need for system status changes.

    - An Operations Instruction being developed (see Subsection I.1.13.3) will establish control of system status as an

! operations responsibility and will provide the same reviews described above during normal operations and maintenance activities. Maintenance procedures will only cover activities while systems and components are removed from service, the 1 ( I.2-11

Operations section will actually accomplish changes in system status as controlled by the described Instructicn. X.2.27 TRIP PRESSURIZER LOW-LEVEL _CCINCIDENT SIGNAL BIST ABLES _JII g g K l.1 This requirement is not applicable to SSES. X.2.28 OP ER ATOR _ TR_AINING FOR_ PROMPT MANUAL REACTOR TPI2 JII.K.J.201 This requirement is not applicable to SSES. X.2.29 AUTOMATIC SAFETY GRADE ANTICIPATORY TRIP (II. K. l . 211 This requirement is net applicable to SSES. X.2.30 AUXILIARY HEAT REMOVAL SYSTEMS OPERATING PROCEDURES JII.K.l.221 X.22 30.1 Statement o.f Requirement Describe the automatic and manual actions necessary f or proper functioning of the auxiliary heat removal systems that are used when the main feedwater system is not operable. This requirement shall be met by fuel load. X.2.30.2 Interpretation None required. X.2.30.3 Statement of Response The response to this requirement was provided by General Electric in NEDO-24708, " Additional Inf orma tion Required f or NRC S taff Generic Report on Boiling Water Reactors," (August 1979) and supplement I. X. 2. 31 REACTOR LEVEL INSTRUMENTATION (II. K.1. 2 3) X.2.31.1 . Statement of Requirement For boiling water reactors, describe all uses and types of reactor vessel level indication for both automatic and manual initiation of safety systems. Describe other instrumentation that might give the operator the same informatica on plant status. This requirement shall be met before fuel load. X.2.31.2 Interpretation X.2-12

None required. l X.2.31.3 Statement of Response The response to this requirement was provided by General Electric in NEDO-24708, Additional Information Required for NRC Staf f Generic Report on Boiling Water Reactors," ( August 1979) and Supplement I. X.2.32 COZM_ISSION ORD_2RS ON BABCCCK AND_WILCCX P L A NTS _ J II. K _._2L These requirements are not applicable to SSES. X.2.33 RgPORTING R EQUIR E M E NTS _._ ?_0R SAFETIZRELIEF VALV_E_FAILUEEg_OR CHALLENGES _JII.K.3.3L X.2.33.1 Statement of Roguirement Assure that any f ailure of a PORY or safety valve to close will be reported to the NRC promptly. All challenges to the PORVs or safety valves should he documented in the annual report. This requiremen t shall be met before issuance of a f ull-power license. X.2.33.2 Interpretat(on Prompt reporting to the NRC consists of notification within 24 hours by telephone with confirmation by telegraph, mailgram or f acsimile transmission, followed by a written report within 14 days. The annual operating report has been supplanted by more detailed Monthly Operating Reports. Documentation required to be included in the annual report wi]l be supplied in Monthly Operating Reports.

   'X.2.33.3  Statement of Response Subsection 6.9.1.12 of the Technical Specifications will be changed to require prompt reporting with written followup for failures of main steamline Code Safety / Relief Valves to reclose after actuation. Procedure (s) for reporting of Reportable l   Occurences are being written incorporating this additional i    reporting ;aquirement.

Subsection 6.9.1.10 of the Technical Specifications currently requires documentation of all challenges to main steamline Code Safety / Relief Valves to be included in the Monthly 3eactor Operating Report. Procedure (s) for preparation and submittal of these monthly reports are being written incorporating this reporting requirement. X.2-13

X.2s34 PROPORTIONAL __ INTEGRAL DERIVATIVE CONTFOLLER (II. K. l. 9L This requirement is not applicable to SSES. X.2.35 ANTICIPATOBY R E ACTOR TR Ig_MODIFIC ATIO N_JII. K. 3.10[ This requirement is nct applicable to SSES. Xz2.36 F0WER O PER ATED R _ELIEF _ VALVE F AILUR E _ RATE (II. K._3 llt This requirement is not applicable to SSES. X.2.37 ANTICIPATORY REACTOR TRIP DN TURBINE TRIP (II. K. 3.12L This requirement is not applicable to SSES. X.2.38 JMERGENCY PREP AR EDNESS-SHORT TER3_JIII.A.I.ll X.2.38.1 Statement o' R eg_ui r e m e n _t Comply with Appendix E, " Emergency Facilities," to 10 CFR Part 50, Regulatory Guide 1.101, " Emergency Planning for Nuclear Po wer Plants," and for the offsite plans, meet essential elements of NUREG-75/lli (3 ef. 28) or have a favorable finding from FE3A. This requirement shall be met prior to fuel load. Provide an emergency response plan in substantial compliance with NUREG -06 54, " Criteria f or Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants" (which may be modified as a result of public comments solicited in early 1980) except that only a description of and completion schedule for the means for providing prompt notification to the population ( A pp. 3) , the staffing f or emergencies in addition to that already required (Table B.1) , and an upgraded meteorological program ( A pp. 2) need be provided (Ref. 10) . NRC will give substantial weight findings on offsite plans in judging the adequacy against NUREG-0554 Perform an emergency response exercise to test the integrated capability and a major portion of the basic elements existing within emergency preparedness plans and organizations. This requirement shall be met before issuance of a full-power license. X.2.38.2 Integnretation PPSL is interpreting Emergency Facilities as encompassing those requirements for TSC, Interim TSC, EOF, Interim EOF, SPDS, OSC as outlined in draft NUREG 0696 and TMI Action Items in 0737. Complete Site, State, County, Township and Municipality Emergency Plans using the Guidelines of NUREG-0654 Rev. 1. Exercise the plans to ensure they are integrated and workable. Comply with meteorological requirements of NUREG 0654 Appendix 2, Rev. 1 X.2-14

I.2.38.3 _ Statement of Response Emergency facility design criteria was submitted to NRC f or review and approval in February 1981. Interim facility use is defined in the SSES Emergency Plan and complies with NUREG 0737 req uire me nts. SSES Emergency Plan Rev. 2 was submitted to the NRC 10/30/80 complying with 10 CFR 50 Appendix E and General Criteria of draf t NUREG 0654. SSES Emergency Plan Implementing Procedures were submitted to the NRC for review in January 1981. NRC comments have not been received on either submittal. SSES Emergency Plan Rev. 3 complying with NRC commen t letter and NUREG 0654 Rev. I will be submitted subsequent to receipt of NRC comments. The Commonwealth of Pennsylvania Emergency Plan has been submitted to FEMA complying .ith NDREG 0654 Rev. 1. The County, Township and Municipality Plans are scheduled for submittal to FEMA by 3/16/81. SSES Integrated Emergency Exercise will be held prior to fuel load. SSES Emergency Plan, Rev. 3 and the SSES Emergency Plan Implementing Procedures will meet the requirements of NUREG 0654, Appendix 2 and related documents. The computerized dose projection calculations will be based on a straight-line Gaussian model with weather and building wake correction f actors included in the methodology. The Emergency Operations Facility will be provided with the computerized dose projection system results in accordance with functional requirements for this facility as specified in draft NUREG 0696. X.2.39 UPGRADE EMERGENCY SUPPORT FACILITIES (III. A._1._2L Requirement superseded by NUREG 0737. Refer to subsection X.1.67 for response. X.2.40 PRIMARY COOLANT SOURCES OUTSIDE_ CONTAINMENT _IILI.D.l._ll Requirement superseded by NUREG 0737. Refer to Subsection X.1.69 for response. I.2.41 INPLANT RADIATION _ MONITORING JIII.D.3.3L Requirement superseded by NUREG 0737. Refer to Subsection X.1.70 for response. X.2.42 CONTROL ROOM HABITABILITY (III.D.1.41 X.2-15

Requirement superseded by NUREG 0737. Refer to Subsection X.1.71 for response. l I I I.2-16 l

.p

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l l I TABLE OF CONTENTS Title Page FSAR Subsections 6.2.1.1.3.3.2 180 6.2.1.1.3.3.5 183 6.3.3 186 7.6.la.4.3.7 1 9.4.2.2 201 12.5.2.6.3 3 4 12.5.2.7.1 4 12.5.3.5.5 6 4 13.1.3 8 , Technical Specifications Table 3.3.2-1 13 Table 3.3.2-2 19 3.6.1.8 24 4.6.5.3 25 6.2.2 28

                      .6.9.1.10                                              31 Nuclear. Department Instructions 4
                     .NDI-QA-4.1.4                                           32 1

NDI-QA-4.2.1 46 NDI-QA-4.2.2 66

i. NDI-QA-6.2.1 72 NDI-QA-6.2.2 76 NDI-9.1.1 87

                  -Procedures AD-00-026                                             94 AD-00-101                           _                112~

j AD-00-103 117 EO-00-021 122

EO-00-022- 126 EO-00-023 130 EO-00-024 143

(. EO-00-025- 155 r- EO-00-026- 161 L. 'EO-00-027 164 i: 7 0P-0I-001' 166

j. ;OP-0I-003 171 OP-0I-012- 176 i

s . I i i I y' f[ ' b :. .

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                                                                                               $h         %*4 TEST TARGET (MT-3) 1.0        $ E4 PM y @ DE I.l  l 5 EE                                                      .,

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TEST TARGET (MT-3) 1.0 E52 EM E!NE I.l l""llO=2g ., 1 g I.25 1.4 1.6 / < 6~ = I

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n

SSES-FSAR i

pressure switches actuating on low pressure. Additionally, differential pressure of the common steamline (Piqures 5.4-13, 6.3-1a and 6. 3-1b) is monitored by differential pressure indicating switches to detect HPCI line break. Annunciation is provided in the main control room. These monitoring systems are d escr ibed in Subsections 7. 6.1a. 4.3. 9. 3 and 7. 6.1a .4. 3. 9. 4. 2s6slaxEs125___ Stag 19E_3a12E_Gltaa-ME_SIstga_Lggh_Dgigg;ign See S ub sec tio n 7. 3.1. la . 2. 4.1. 9.

   .-        ? . 9 - les S2322_ __Sa fs1I2He lia f _Ialin_ Lea k_ Det ssti on

(_

2s6slai32322=1___ssbsystem Issatifisati9n ' ~ . Normally, the safety / relief valves are in the shut tight condition and'are all at about the same tempera ture. Steam passage through the valve will elevate the sensed temperature at the exhaust, cau sing an " abnormal" temperature reading on the recorder. Microswitch contacts on the recorder, adjusted to actuate at a predetermined set point, close to complete an annunciator circuit. Safety valve operation usually occurs only after relief valve actuation. Leakage f rom a valve is usually characterized by a temperature increase on a single input. 1

    .        Rev. 17, 9/80         -

7.6-15 l l i < i

I SSES-FSAR

7. 6. la . 4.3. 7. 2 Safety /Helief Valve Discharge Line

_12EE2EatEI2_52ni19Eing_ ________ 2x5slame22222241___DREsE i Rii2E A temperature element (sensor) is placed in the discharge pipe of each of the sixteen (16) safety / relief valves f or remote indication of le a ka ge. The outputs of the temperature elements are sequentially sampled and recorded by one cosson temperature recorder.g Each teseprature element is compared against a set point valve which if exceeded will be annunciated by one common anunciator. Thus, when the annunciator sounds, it is possible to a scertain which specific valve (s) say be leaking by observing th e recorder prin t-out. 2sislaz32122r222___L22ic_and_S22nensing No action is initiated by the sa fet y/ relief valve temperature monitoring ci rcu it. 1sizldsEx2rls2s3___HInasses_and_Intet19sts There are no bypasses or interlocks associated with this subsystem. , 2sisla232222s22E___Eciandanst_and_Rizersiti No redundancy or diversity is required for this system. 2sislai322sa____Eeactor_Iessel_ Head _leat_Datastien lasslassal2aal _ssbsrstes raensifisatiga i ! & pressure between the inner and outer head seal ring will be sensed.by a pressure s witch. If the inner seal leaks, the pressure switch will sonitor the pressure. The plant will continue to operate with the outer seal as a backup and the inner seal can be reoaired at the next outage when the head is removed. If both the inner and outer head seals i t i Rev. 17, 9/90 7.6-16 */ i e

1

I SSES-FSAR i placed at locations where the potential exists for an unexpected increase in radioactive or chemical airborne system) concentrations (such as the water treatment building and radwaste . Fifteen (15) escape devices will also be located in the control room. If g applicable, respiratory protective face pieces w ill be wrapped in plastic bags and stored individually to prohibit plastic deformation. 12s5s2sss3__Ai t_Samg1;ng_gguipment Air sampling equipment will be available at the Health Physics l office (Central Access Control Area, Figure 12.5-2) and the l Health Physics Station (Radvaste Building, Figure 12.5-3). Airborne activity' levels dill be determined by the use of continuous airborne monitors (C AMS) , high and low volume portable air samplers, and breathing zone air samplerr- Five (5) CAMS, five (5) high volume air samplers, five (5) low volume air samplers, and two (2) impactor attachments will be available for use at Susquehanna SES. The CAM (s) can be used to measure particulate and gaseous activity. The air samplers can be used to measure pa rticula te and iodine activity using the appropriate filtering medium. Particulate activity and particle size distribution can be determined using an impactor attachment. Volumes necessary for representative samples will be specified in Station Health Physics procedures. Filter media such as H.E.P.A. filters and charcoal cartridges will be stored at the Health Physics office and Workroon Area. 12s5t 2sssisl__G2ntinE93f: AiX_ Monitors l CAMS will normally be used to sample selected areas of potential airborne concentrations. CAM sampling rates will be checked against calibrated rotometers or vet test meters on a quarterly basis and af ter pump replacement or repair. If CAM's are equipped with strip chart recorders or local readout, a base line sampling program will be completed prior to Unit 1 fuel load to allow estimation of naturally occurring isotopes' contribution to airborne background. CAM detector response to an appropriate check source will be performed on a quarterly basis. Manufacturer's recommended calibration or voltage plateau procedures will be performed on a quarterly basis. If applicable, operation of local alarms will be veri,fied on a 12.5-12 O l

SSES-FSAR 12s5 t 2s2__ESal t h _Ehys ics __ In s t ru m en t a tiga Instruments for detecting and measuring alpha, b e ta , gamma and neutron radiation will consist of counting room, and portable radiation survey / monitoring instruments. All instruments will be subiected to operational checks and calibration to assure the accuracy of measurements of radioactivity and ra dia tion le ve ls. p rim ary and reference standards (utilizing, or prepared from, standards of Sr-90, An-241, Cs-137, co-60, H-3, and others, traceaDle to tne National Bureau of Standards) will be used to maintain required accuracies of measurement. Background and efficiency checks of routinely used Health Ph ysics counting equipment will be performed daily and these instruments will be recalibrated whenever their operation appears statistically to be out of lirits specified in Station procedures. Routine calibrations will be performed on counting room instrumentation and radiation survey / monitoring instruments on a quarterly basis and af ter repairs affecting ca lib ra t io n. Efficiency curves for multi-channel analyzer systems will be determined on a semiannual basis using N.B.S. traceable sources for various reproducible geodecries. Sufficient quantities of instrumentation vill be available to allow for use, calib ra tion, maintenance, and repair. The instrumentation described in these Subsections may be replaced by equipment providing similar or improved capacilities. 12.5s2,2 1 _Cagaging_gsgo Instrumensalign Counting Roam instrumen's for radioactivity measurements will include the following: A 4096 channel analyzer, using a 3" x 3", 7% resolution Na I crystal, and a S Kev resolution (at 1 Mev energy full width half maximum peak) G E (Li) detector, for identification and measurement of gamma emitting radionuclides in samples of reactor primary coolant, process streams, liquid and gaseous effluents, airborne and surface contaminants. One coacuter which can be interfaced with a pulse height analyzer; equipped with a teletype machine for enttring instructions and printing results, a tape decx for eatering l orograms and stori q data, and an 1-Y plotter for making graphs. A low background gas flow proportional counter used for gross alpha and grosa beta measurements of prepared samples. 12.5-16

Li

r SSES-PSAR A liquid scintillation beta counter used for measurement of tritium in reactor primar y coolant, liquid and gaseous vastes, and gross beta activity other than tritium. (-sv) A NaI well crystal with counter-scaler or pulse height analyzer used for gamma analysis of various radionuclides in samples of reactor primary coolan t, liquid and gaseous wastes, or prepared samples. One beta-gamma counter-scaler, thin end window (2 mg/sq. cm, 2-inch diameter G-M) used for gross beta-gamma measurements of reactor primary coolant or prepared samples. ! One alpha scintillator or semiconductor crystal used for gross l alpha measurements of reactor primary coolant and prepared samples. One beta scintillation counter-scaler used for gross beta measurements of reactor primary coolant and prepared samples. 12ts s2,2,Z__gealth_PhIsics O f fi;e a nd _ workgoom Instrumentation Health Physics instrumentation normally located in the Health Physics Office and Workroom will include the following instruments, or equivalent: (~) One (1) automatic and one (1) manual beta-gamma counter-scaler, ( ) thin end window (2 sq/sq. cm) , 2 inch diameter G-M, used for gross ~ beta-camma' measurements of removable contamination, air samples and nasal swabs. An alpha scintillation or semiconductor counter-scaler used for evaluation of removable contamination, air samples and nasal swabs. A low Dackground gas flow proportional counter used for gross alpha and/or beta measurements of removable contamination, air samples and nasal swabs. Ten (10) G-M beta-gamma survey meters (most sensitive range 0 .2 ! mB/hr., marinum range 0-2 R/hr. , with internal probe) used for detection of radioactive contamination on surfaces and for low l level exposure rate measurements. Ten (10) ionization chamber beta-gamma survey meters 0-5 res/hr. (0-5 meem/hr. most secsitive range) used to cover the general range of dose rate measurecents necessary for radiation protection evaluations. 12.5-17

 -I )

a

SSES-FSAR 122 52 3252322__1gecial_ Air sa mpling

Records will be maintained to reflect the reason for the special surveys, device (s) and saa; ling media used and final results. The (' maiority of special air samples will be taken as result of Radiation Work Permit requests and pertinent results will be recorded thereon.

/-

12252 115 5 Air. saggie_avaluation 12252]is.5.1__Egrticulata Initial _gvaluation ..

                                          .= -                       .          .. ,
                                            ~~

1.- A data sheet will be completed to reflect sample location, date, starting flow rate, starting time, sampler and collection media used, and collection efficiency. At completion of sampling, the date, time, and ending fl'ow rate will be recorded. Air sample filters will be counted as soon as practicable following collection. Results will be recorded on an analysis form to reflect counter used, efficiency, counting time, background cour t rate, gross sample count rate, net sample count rate, and sample i disintegrations per minute beta, and/or be :a gamma, and/or alp'aa. Sample disintegrations per minute divided by collection efficiency of the media, the number of disintegrations per minute ~ per microcurie and the total volume of air sampled will yield the {- initial estimate of airborne concentration. Prior to Unit 1 fuel load an air sampling program will'be implemented to obtain a base line of information concerning naturally occurring radioactive concentrations. This data vill enable development of an average beta to alpha ratio of naturally occurring airborne emitters. This "First Count Factor" may be utilized as an initial evaluation technique for low level particulate air samples. 12252 22525z2__Enkgeggent Particul_ ate _3valgatiggs Every effort will be made to initially evaluate air samples as soon as practicable following collection. In instances where time delay before, analysis in coniunction with suspected short lived isotopes is significant, repeated counts may be performed to obtain a decay curve. Extrapolation and subtraction techniques say be used to determine initial amounts and half lives of com ponent isotopes. 12.5-48 6

SS ES- FS A R

          '4 hen statistically possi ble, fixed filter samples say be gas =a scanned witn a Nal or Ge (Li) detector to identif y gamma emitting

(~5 isotopes. dhen this or other specific analyses are not (_) oracticaole, the MPC f or unidentified beta-gamma emitters will be used for exposure evaluation and procedural controls. Other evaluations that may be utilized are beta absorption countina, radiochemical separations and analysis, and liquid scintillation counting. 1225sJz515l x Gasanus_IIaluations AirDorne radiciodine samples will normally be collected on charcoal canister or cartridges, and analyzed on a NaI or Ge (Li) detector. Appropriate standard sources in reproducible geometries . will be used to obtain ef ficiency curves for analysis equipsent. Photopeak areas, counting efficiency and branching ratios for the identified isotope will be utilized to calculate the amount of deposit. Collection efficiency and total volume of samoled air will be incorporated to calculate airborne Concentrations. Airborne tritius samples will normally be collected in water bubolors or dessicant columns.- Collection and counting eff tciencies and total air volume vill be verified and used to

  <~s     calculate airborne concentrations.
 '    )
   ~'     If analyses of restricted area air for noble gases are required, s43 Die Chambers 24Y be analy2ed vita Nal or de(Li) detectors to identify isotopes.

12 z 521sizs__Ee s2irat e tI_EI21e c t i2 n The respiratory protection program will assure that personnel intaka of radioactive material is minimized. The respiratory protection program will not be used in place of practicable enaineering controls and prudent radiation safety practices. Every reasonable effort will be expended to prevent potential, and minisize existing, airborne concentrations. When controls are l not practicable, or conditions unpredictacle, respiratory l protective devices say be utilized to minimize potential intake of airborne radioactive material. The Susquehanna SES Respiratory Protection Progras will ensure that the following miniaus criteria are set: written standard operating procedures; proper selection of equipment, based on the 12.5-43 p

    /
                                                                                  ~7

SSES-FSAR o The Senior Compliance Engineer Supervises the activities of the compliance staff. The compliance staff provides the plant technical interface with NRC, evaluates and interprets licer. sing documents such as Technical Specifications, Regulatory Guides, IE Bulletins and Circulars, represents the plant staff in licensing activities, coordinates the su m illance and inservice

                  -inspection programs at the pl.snt, and prepares routine and special NRC reports.

13.1.2.3 - Shift Crew Composition The shift complement for normal operation of both units consists of eleven (11) qualified individuals; the Shift Supervisor who holds an SRO License, two (2) Unit Supervisors who hold SR0 Licenses, three (3) Licensed Operators with R0 Licenses and five (5) Non-Licensed Operators (See Figure 13.1-6). Five crews as specified provide continuous coverage. Table 6.2.2-1 cf the Technical Specifications shows the minimum number and type of licensed and non-licensed operating personnel required to be on-site for each operating shift. Health Physics coverage is described in Section 13.1.2.2.2. For those operations that involve core alterations, direct supervision of fuel mov aents is provided by an individual holding an SRO License. This person & will have no other concurrent responsibilities during this W assignment. 13.1.3 QUALIFICATION REQUIREMENTS FOR NUCLEAR PLANT PERSONNEL 13.1.3.1 Minimum Required Qualifications Mien selecting p'ersonnel and sched tling training assignments for the plant staff positions listed be low, the requirements of NRC Regulatory Guide 1.8, Rev. 1-R, 9/7i will be met. Experience , education, and training are such that the criteria in Section 4 l of MSI/ANS-3.1-1978 are met at the time of the core loading of l the appropriate unit. For these determinations the following plant staff positions are

    . identified with the classifications contained in Section 4 of ANSI /ANS-3.1-1978:

l l l REV. 18, 11/80 13.1-16 8

i

I l SSES-FSAR l O'~ Susquehanna SES Staff Position ANSI /ANS-3.1 Classification Superintendent of Plant Plant Manager (4.2.1) Assistant Superintsndent of Plant Plant Manager (4.2.1) Supervisor of Operations Operations Manager (4.2.2) Shift Supervisor Supervisors Requiring NRC Licenses (4.3.1) Unit Supervisor Supervisors Requiring NRC Licenses (4.3.1) Licensed Operators Operators (Licensed) (4.5.1) Non-licensed Operators Operators (Non-Licensed) (4.5.1) Technical Supervisor Technical Manager (4.2.4) s)

       -         Reactor Engineering Supervisor           Reactor Engineering (4.4.1)

Instrumentation and Control / Instrumentation and Computer Supervisor . Control (4.4.2) Instrumentation and Controls Supervisors Not Requiring Foreman and Assistant Foreman NRC Licenses (4.3.2) Instrument Man Technician (4.5.2) Chemistry Leader Technician (4.5.2) Chemistry Supervisor Radiochemistry (4.4.3) B l Supervisor of Maintenance Maintenance' Manager l (4.2.3) Foreman and Assistant Foreman - Supervisors Not Requiring Mechanical Repairs NRC Licenses (4.3.2) Foreman and Assistant Foreman - Supervisors Not Requiring Electrical Repairs NRC Licenses (4.3.2) - Mechanic Repairmen (4.5.3)

                .REV. 18, 11/80                        13.1-17 9

i SSES-FSAR '

Health Physics Supervisor Qualifications per NRC Regulatorf Guide 1.8, Rev. 1-R, 9/75 Health Physics Foreman and Supervisors Not Requiring Assistant Ioremar. NRC Licenses (4.3.2) Health Physics Personcel Qualification per Section 12.5 13.1.3.1.1 Qualifications of Personnel that Cannot Be Directly Cross-Referenced to ANSI /ANS-3.1-1978 The below listed positions cannot be directly cross-referenced to corresponding positicas in ANSI /ANS-3.1-1978; hcwever, personnel filling these positions will have that combination of education, experience and skills commensurate with their functional level of responsibility which provides assurance that decisions and actions during normal and abnormal conditions ull be such that the plant is operated in a safe and efficient manner: Personnel and Administrative Supervisor Security Supervisor g Senior Compliance Engineer Shift Technical Advisor Mechanical Maintenance Supervisor Electrical Maintenance Supervisor

                     ' Senior Results Engineer Engineer Administrative Supervisor Clerks
 .                    Material Supervisor Material Personnel Stockman Supervisor.- Nuclear Records System Records Personnel
                                   ,                                                   h REV. 18, 11/80                          13.1-18 to

W 1 1' SSES-FSAR l l l

 " O.
                                   - 13.1.3.2 Cualifications of Plant Personnel i

. t i . The qualifications of the key plant supervisors are shown on :

                                 -' Tables 13.1-3.                                                                                                                                                                                              ,

I r t

   .                                                                                                                                                                                                                                            I e

i t i 1 l i , . r i i i 1 d

                          . s t

j} t ( l i. i l l~ ! h I i.. t '.

. .i i

i 1 .

        -s            .

REV.18,Lil/80' - 13.1- l'! ' I ' l. + ' r , v .I - , rw w. s-y.,. +ccw-,.,,w.,,, ,,,.,,,,,.,,_,,,.,_-,.w,,.,,,,,,,,,, ,,,,_,w,_,,.,,,,,,,,.%gY, , _ _ _ ,,m,,,,, y,,y, ,,._ ,, ., , , ,7mmm,.,..,c,,,,-...ww-m ye , , ,,-y ---

SSES-FSAR n TABLE 13.1-1

  \ )*

KEY TECHNICAL SUPPORT PERSONNEL RESUMES Positions Senior Vice President - Nuclear Vice President - Nuclear Operations Vice President - Engineering and Construction - Nuclear l Manager - Nuclear Plant Engineering l Manager - Nuclear Licer. sing i Manager - Nuclear Fuels

       . Manager - Nuclear Trainir.g Manager - Nuclear Support i

Manager - Nuclear Administration Manager - Nuclear Safety Assessment , Manager - Nuclear Quality Assurance Construction Manager Manager - Procurement l .

Q- Rcsvu,m Not b fid f

    /                          .

REV. 18, 11/80 1

O

    ,                                                                   TAlllE 3.3.2-1 m                                           ,

ISOLATION ACTUA110N INS 1RUMENIATION h m 4

                         -                                     VALVE GROUPS          HINIHllH      APPLICABLE OPERATED fly    OPERAlllE CllANNELS OPERATIONAL TRIP filW IION                                      SIGNAL (al Pfit TRIP SYSIfH (1 }     CONillil0N     AClION
    #" "      PRIMARY CONIAINHfNI IS0lATION 4

Reactor Vessel Water Level Low, level 3 (2, 6, 8)ICI

                                                                                                                      /
                    \l)    2       Low low, Level 2            (1,3) 2 2

1, 2, 3 1, 2, 3 11 20

h. rywell essure - liigli (2, 6)ICI 2 1, 2, 3 20 l

c. Main Steam Lin

1) Itadiation - 1110 (1) 2 1, 2, 3 21 w (7) 2 1, 2, 3 22 3 2) Pressiere - low (1) 2 C

1 23 w 3) ilow - liigh 2/1 e 1, 2, 3 21 5 d. Main Steam Line Tunnel lemperatiare - liigli (1) 2/line 1, 2, 3 24

e. Main Steatii line Tunnel A lemperature - liigh (l) 2(" 1, 2 3 21 l

f. Condenser Vacuum - Low (1) 2 1, 23, 3* 21

g. Manual Initiation *

( 4 groisp) 1, 2, 3 24 (1)3,6,7) (2, (1)/((hcqup) 1, 2, 3 26 (0) (1)/(valt 1, 2, 3 26 h.

2. SfC0H11AltY CONI AINHf NI 150 TION

a. Plant Exliainst 'idum liailia tiosi llirjli 2 IUI II 1, 2 , 'a, d^^ 25

h. IlrywellJressure - liigh (6)ICNII (6) 2 1, 2, 3 25

( c. React # Vessel Water idGel - low, level (3) (6)ICIII) 2 1, 2, 3, and # 5l o R$tuelingiloor[xhsust [d. e. Radiation - liigh Hanual Initiation (6) III 2 IU) (1)/(gioup) 1, 2, 3, and *^ l 2, 3 25 26 (6){g) *A

  -                                                            (6)                  (1)/(group)                     25  l w

J. 10 TABLE 3.3.2e1 ISOLATION ACTUATION INSTRUMENTATION HINIMUM OPERABLE APPLICABLE .

OPERATIONAL INSTHUMENT CilANNELS TRIP FoHCTION PER TRIP SYSTEM (b)(h) CONDITION ACTION

1. CONTAINMENT ISOLATION

            -a. Reactor Vessel Water Level

1) Low, Level 3 (LIS-B21-H042 A%B and N024 A thru D) 2 1,2,3 20

2) Low I.ow, Level 2 (c)

(LITS-B21-N026 A thru D; LIS-g B21-NO31-A thru D; LIS-B21-4 20 $ N025 A thru D)- 2 1,2,3 T 3) Low Low Low, Level 1 % (l.IS-B21-N031-A thru D) 2 1,2,3 20 i 4 Q ~ p b. Drywell Pressure - liigh (c) (PSil-C72-N002 A thru D) 2 1,2,3 10 %

2. MAIN STEAH 1.INE ISOLATION

a. Reactos Vessel Low Low 1,2,3 21 Water Level 2 (LIS-N026 A thru D) 2 L. Radiation - liigh (e)

(RE-D12-N006 A thru D) 2 1,2 73

 .            c. Pressure - Low (PSL-B21-N015 A thru D)                              2                 1           22

d. Flow - liigh

( FIS-B21 -11006 A thru D,-Il007 A thru D,-N008 A thru D -N009 A thru D) 2/11ne 1,2 21

h4 e. Condenser Vacuum - Low (PSil-B21-VN056 A thru D) 2 1,2* 21

f. Main Steam Line Tunnel Temperature - Iligh (TSil-B21-N600 A thru D) 2 1,2 21

g. Hain Steam Line Tunnel A Temperature - liigh (TDSit-B21-N603

   ~               A thru D)                                            2                 1,2         21
   -C U                                                          L                                     U

l l i I l l l 3l C

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O '

7. IIICl4 PRESSURE COOLANT INJECTION SYSTEM ISOLATION a, llPCI Steam Line A Pret ore-liigh (PDIS-E41-N005 A&B) 1 1,2,3 20 b HPCI Steam Supply Pressure-Low (PSL-E41-N001 A thru D) 2 1,2,3 20

c. IIPCI Turbine Exhaust Diaphragm Pressure-liigh (PSit-E41-N012 A thru D) 2 1,2,3 20

d. IIPCI Equipment Room Temperature-liigh (TSil-E41-N600 A&B) 1 1,2,3 20

a. IIPCI Equipment Room A Temperature-Iligh (TDSit-E41-N601 A&B) 1 1,2,3 20 [4

f. IIPCI Emergency Area Cooler Terr crature-High 7 (Tdll-E41-N602 A&B) 1 1,2,3 20 y y g. IIPCI Pipe Routing Area Temperature-liigh N (TSil-E51-N603 B&D) 1 1,2,3 20 $

I h. IIPCI Pipe Routing Area A Temperature-liigh

  !            (TDSII-E51-N604 B&D)                             1   1,2,3 20 e

1m

l 1 1 i TABLE 3.3.2-1 (Continuec) ISOLATION ACTUATICN INSTRUMENTATION ACTION

                                                                                                                                                                         / 2.

ACTION 20 - Se in at least HOT SHUTCC'nN within / ncurs and in COLD SHUTCC'nN within the next JC' neurs. 14 cNo r:1:44& C ed Mf'24 ad 'al ACTION 21 - Se in at least STA?.T'.? *iu me asscciatec isolation valves C closed wiuinTZ hours anc in COLD ShUTCC'nN wi nin ne next .ad nours.neurs or ce in at least HOI.d*HUTCC'nN witnin 5

        .~...u.,> ..                     _
                                                     .~ . . . . . ..... .. . .
                                                                            ...      .u.....                                ....                  . ..:..

ac.c.-a.a c ' - c :"::::: :, :tr ' ACTION ",3In- Se in .t least STARTUP witnin hours. [. :: r : cia. ACTION WJ- Restore tne manual initiation function to C?ERABLE status witnin 48 hcurs or te in at least HOT SHUTCC'nN witnin ce next

                                #j                  12 hours anc in COLD SHUTCC'nN itnin ce following 24 hours.

ACTION "rEJ - Estaclisn SECONDARY CONTAINMENT INTEGRITY *itn tne stancey gas treatment system ccerating witnin ene neur.

            -.e--_n .- e.
                                                        . . _ _ . . . . . . . .                                                . .. .                      ........--.e..-
                                                                                                                   ... . u...  .
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                                                                      ,s
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                                                                                                                                                                                       .         ..g   - . .

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s. /.u. = *e<cr $ 0TES " ' ~' 'N "#"*

6<e May be bycassed with reactor steam pressure < {:94C-? psig anc all turcine , step valves closec. , When hancling irradiated fuel in the secondary containment anc curing CCRE j ALTERATIONS and ccerations witn a potential for draining ue reacter vessel.1

                                                                                                                                                        . . .         ....w...:
                                                                                                                                                                                                                        .                  . ~
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         ?,

s , ... . , - , . :

                                                         ...-                    ....,.,                      ..            ,e s.. .
                                                                                                                                                                                                 . . - ... ., . ~ . . . -

W Idr) A cnannel may be placec in an incceracle status for uc to 2 neurs for required surveillance wi= cut clacing One trip system in =e triscec con-dition previcec at least one etner CPERAELE cnannel in :ne same tric - system is monitoring that parameter. (O$c7 Also actuates tne stancty gas treatment system. (c)fg1 Also trips and isolates the mecnanical vacuum cumes, c../ rre. ;,7 m e#*. r, , s ros

i. -cc.~.:s -

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Q , TABLE 3.3.2-2 Sl ISOL AIION ACIllATION INSTRUMENTA110 4 SEIP0lNTS g ALLOWA8tE TRIP IHNCTION 1 RIP SEIP0lHI VAlllE I. RI_HARY CONIAINHENT ISOLATION ..

a. e clor Vessel Water Level /

1) ow, level 3 > (12.5) inches * > (11.0) inc)ef" 2). Lo ow, level 2 5 -(30) inches

I -(45) l li . Drywell Pre s are - liigh 3(1.69)psig 3(1.9)Jaclies*psig

c. Main $tcam Lint.
I) Radiatlosi - l191 < (3.0) x full power background < (3.6) x faill power back0round: 2) Pressure - Low > (054) psiti 1 (034) Psl0; 3) flow - tiluh -< (140)% of rated flow -< (145)% of rated flow; d. Hain Steam iine Iunnel t -

lemperature - liigh < (140)"f <( )*f s

c. Main Stcam Iine Tunnel A lemperature - lii 0h < (S )Q <( )"f

          $          f. Condenser Vacuum - tow                     I (23) tilettes I Absolute Pressure 5(        ) inches lig absolute un                                                                                                           pressure i                    U. Hanual Initiation                          HA                                  NA h.

2. SECONDARY CONIAINHINI IS0lAll0N

a. Plant t xlianst Plestiin 2

Radiation - 11101: < (4.5) ar/hr** < (5.5) ar/hr^^ !

h. Drywell Pressiere ligh {(1.69)psig .89)

c. Reactor Vesse level-id, level 3 ater ('(1, \ psig

                                                                      -> (12.5) inches *                  ~> (11.0) inches"

d. RetuejidiloorExhaust jalliat ioni - liiglt < (V J mr/hr^^ < (35) ar/hr^^ x l

e. Manual Initlation HA NA 'N s

1

 ,      ~

A

lJf.* TABLE 3.3.2-2

                                              .,,,_ei           ..o                      ..-

ISOLATION ACTUATION INSTRUMENTATION _SETPOINTS ALLOWABLE TRIP FUNCTION TRIP SETPOINT VALUE_

           -1. CONTAINHENT ISOLATION

a. Reactor Vessel Water Level

1) Low, Level 3 13 inches > 11.5 inches

2) Low Low, Level 2 -38 inches I-45 inches

3) Low Low Low Level 1 -149 laches I-155 inches

k. b. Drywell Pressure - liigh 1.69 psig -< l.89 psig A

2. MAIN STEAM LINE ISOLATION

     .',                                                                                                             li
   '[            a. Reactor Vessel Water Level - 1.ow, Level 3                   13 inches                        > 11.5 inches        1

b. Main Steam 1.ine Radiation - liigh 3 X full power background < 3.6 X full pou>r Eackground

c. Pressure - Low 855 psig > 835 psig

d. Flow - liigh 110 paid < 115 paid

e. Condenser Vacuum - Low 9.0 inches lig > 8.8 inches Ilg

f. Hain Steam Line Tunnel Temperature - Iligh 1770F < id40F

g. Main Steam Line Tunnel A Temperature - liigh 990F+ <F 10F c

d C

t. ) U

tr

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t A . 8 GE-STS 3/4 3-17 c23

o : . l '.lll f I l' 'l A* l1,$d l 8 0 4l I ll . ' if I 8 6 P' I l 'i' 8 ll8'II

7. IIICil PRESSilRE C001. ANT INJECTION SYSTEM ISOI.ATION ' I I I 'AI '

i., . - , is is e . . .. g ri t us : les

a. IIPCI Steam I.ine Flow-High 289 inches I:20 <303 inches of 110 2

b. IIPCI StcamSiip'pi'y 'Pr' tis'##rh-Chu 81' " " l ' ' 4 ' 8 " " 110 psig [100 prig

c. HPCI Turbine Exhaust Diaphragm Pressure-liigh 10 psig ' <20 psig " ,

d. liPCI Equipme'nt Room Teitiperatur e-liigh ' ""' 167dF ' *

[1740F

e. IIPCI Equipmeut Room Temperature-High 89 F <980F

f. IIPCI l'mergency Area C' o blar Temperature-liigh 1470F 715'dOF

g. IIPCI Pipe Routing Area Temperature-liigh 1670F after 15 min TD [174F ,

( h. IIPCI Pipe Routing Area Tempe ra tu re-liigh 890F after 15 min TD <980F

     %                                                                                                                                                                               h I                                                                                                                                                                              =

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     ?                                                                                                                                                                               A y

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CCNTAINMENT SYSTEMS PRI. WARY CCNTAINMENT : URGE SYSTEu g LIMITING CCNDITICN :0R OPERATICN

3. 6.1. 3 The drywell anc su==ression enam:er curge su==1y anc exnaur' isciation valves snall be closec,eueer e* T

APPLICA2ILITY: CPERATIONAL CCN0!TICNS 1, 2 anc 3 i

       '          ACTION:

g,,,,, ,, r.--..wat .Lc se. With a drywell or su= ression enam:er : urge su=cly and/or exhaus isolation f valve c=en, close :ne c en valve (s) wi:nin ene nour er :e in at least HOT SHUTCCnN within :ne next 12 hours anc in CCLD SHUTDC'aN within :ne following 24 nours.

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o.t'e -~ t ~ - d FAe c.9. t s .c.r l

                              .a y ** ,- u y e. e e 4 ua r v .t. Je e os e / u eal.

SURVEILLANCE RECUIREMENT5 4.6.1.8 The drywell or su:Oression ena= er : urge sue::1y anc exnaus: isciatien valv'es sna11 de verifiec ta ::e cicsec,,at least once ;:er 31 cays. a se e,= s.1 p - ~. r.J . 4<.re , m :- .-- : :--- - --. - - -- 9 2 : y : -- -:,:.. u :---

                                  - :. - - 7           _.s               ---.    -
                                                                                       ;      3, 1

d i GE-5TS 3/4 6-11a /#Io l

            ..                                                                                             .. ~    ~

  /      CONTAINMENT SYSTEMS s                                                                                                             l STANOBY GAS TREATMENT SYSTEM
         'IMITING CONDITION FOR OPERATION
       . 3.6.5.3     Two indecencent stancty gas treatment sucsystems aail be CPERAELE.

APOLICABILITY: CPERATIONAL C':NDITIONS 1, 2, 3 anc ". l ACTION:

a. With one stancby gas treatment sucsystem inoceracle, restore tne inoperaole sucsystem to OPERABLE status witnin 7 cays, or:

1. In OPERATIONAL CONDITICN 1, 2 or 3, be in at least NT SHUTCCkN within the next 12 hours anc in COLD SHUTCCWN witatn :ne foliosing 24 hours.

2. In Operational Candition *

                                                                  , sustenc aanaling of ir acia;ec fuel in the secondar/ containment, CCRE ALTERATICNS anc ocerations with a potential for craining ne reacter vessel.               The =rovi-sions of $pecification 3.0.3 are not acclicacle.

c. Wita both stancby gas treatment sucsystems inoceracle'1In 0:erational Condition *, suscenc hancling of irradiated fuel in :ne secondary l i

containment, CCRE ALTERATIONS or ocerations witn a :otential for i draining tne reactor vessel. The pr: visions of Specification 3.0.3. l are not acplicable. 1, r,, cou rru **t. cw a r r c" <. a a - 3, k -J /#asf "*r

f""'# *

                              .rs i      i2 Ae rs a - ./ m Ce sa siv arrpr .s J ... no.., ca n o r z </ 4e., ..

SURVEILLANCE REOUIREMENTS

4. 6. 5. 3 Each stancby gas treatment sucsystem shall be demonstratac CPERASLE:

! a. At least once per 31 days by initiating, from tne c:ntrol room, ficw l through the HE?A filters anc cnarcoal acsor ers anc verifying that the subsystem ocerates for at least 10 hours witn =e neaters on autcmatic control. ihe o# As "* d e * ~r * * * * *j b e. ~ sed as

a. .rc a , < e. i a,- i<s che r es t .

l

         "%nen irraciatec fuel is being handled in the sec:ncary c:ntainment anc curing                      i

, CORE ALTERAT!CNS anc ocerations witn a potential for craining ne reactor vessei.l GE-ST5 3/4 6-29 /c/jt !

l CCNTAfNMENT SYST95 SjlRVdILLANCE RECUIRE.uENL fContinuec)

b. At least cace ::er 13 mentns or (1) after any structural maintenanca on the HE?A filter or cnarc:a1 acscr:er housings, or (2) fc11cwing painting, fire or enemical release in any ventilation c:ne czmunicat-ing with tne sucsystem ::y:

    .            1. Verifying that the su: system satisfies ne in-claca testing acceptance criteria anc uses ne test crocacures of Regula:crj Positions C.5.a. C.5.c anc C.5.d Of Regulat:ry Guice 1.52, Revisicn 2, Marcn 1973, anc ce system ficw rata is :-- ;' cfm

10%. se. .rc o

2. Verifying witnin 31 cays after removal :nat a lacera:Ory analysis of a recresentative car:cn samcle octained in acc:rcance ita Regulatory Position C.5.0 of Regulatory Guice 1.52, Revision 2, Marth 1973, meets ne laceratorj testing critaria Of Regulatory Position C.6.4 of Regula:arj Guice 1.52, Revision 2, Marcn 1973.

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c. After ever/ 720 hours of cnarc:al - Or:er c::eration y verifying within 31 days after removal :na a laceratory analysis of a repre-sentative carcon samcle cc:ainec in accorcance wita Requiat:rf Position C.5.0 of Regulat:r/ Guide 1.52, Revision 2, Maren 1573, meets the laccratory testing critaria of Regulatory Position 0.5.a of Regulatory Guice 1.52, Revision 2, Maren 1978.

d. At least once per 18 months by:

1. 4E?A Verifying filters anc:nat tne cressure crarc:al acscr:ercroc ::anks across the :c=cinec.incnes is less nan f,rf' Water Gauge wnile ccerating tne filter train at a ficw rata of (43GG-) cf.m : 1C%.

Asee cA e <.t,-.i -i~1a. a vc.<: rad

2. Verifying tnat tne fil ter train starts and -::' W - camcers open en eacn of the fci b irg test signals:

m . .J . . 7 . t n ., , ~ . . - ca t : <. m >

a. '" :n : :~ a a . : =ici d i.. - . . ;.i ,

b. Or/well pressure - nign,

c. Reac:ar vessel water level - Icw, level 3, eae-s.

d. e. Refuelin k a c. s -a fl c e xnaus r, e,h raciation fic - - st erh ar

                                                                                       - nign,et.
                                                                                     ~h.t. -o.5/

3. Verifying tnat :te filter c::aling ::ypass cam::ers can te :anual!y coened and One fan can te manually started.

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C"NTA IN.u:N'.

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   ! _e 6.0 ~ ADMINISTRATIVE CONTROLS 6.1  Responsibility                                                          l 6.1.1    The Superintendent of Plant-Susquehanna shall be responsible for overall facility operation and shall delegate in writing the succession to this responsibility during his absence.

6.1.2 The Shift Supervisor shall be responsible for the Control Room command function, and shall be the only individual that may direct the licensed activities of licensed opera *.crs. A management directive to this effect, signed by the Vice President-Nuclear Operations shall be reissued to all station personnel on an annual basis. 6.2 Organization OFFSITE 6.2.1 The offsite organization for facility management and technical support shall be as shown on Figure 6.2.1-1.- Organizational changes may be made without prior NRC concurrence provided these changes and their justification are submitted to the NRC in the next C'; Monthly Operating Report. FACII.ITY STAFF 6.2.2 The facility organization shall be as shown on Figure 6.2.2-1 and:

a. Each on anty shift shall be composed of at least the minimum shift crew composition shown in Table 6.2.2-1.

b. At least one licensed operator shall be in the control room for each reactor contaicing fuel,

c. One licensed operator, in addition to any required by Specification 6.2.2(b), shall be l

present in the control room for each reactor i in that process of startup, scheduled shutdown, or recovery from reactor trips.

d. A health physics technician or an individual qualified in radiation protection procedures shall be onsite when fuel is in either reactor.*

I 6-1 10/80 I

TABLE 6.2.2-1 MINIMUM SHIFT CREW COMPOSITION d With both units in CONDITION 1, 2 or 3 Position Number of Individuals Recuired j SS (,) 1 S20 1 R0(b) 3 NLO 3 , STA 1 With one unit in CONDITION 1, 2, or 3 and one unit in CONDITION 4 or 5 Position Number of Individuals Recuired SRO(a) 1 RO 3 NLO 3

             . STA                                      1 With both units in CONDITION 4 or 5 Position                   Number of Individuals Recuired SS                                       1 SRO                                      O RO                                       2 NLO                                      3 STA                                      0 With one unit in CONDITION 1, 2 or 3 and no fuel loaded in other unit reactor Position                   Nussbar of Individuals Recuired SS                                       1 SRO(,)                                   1 l                   RO                                       2

, NLO 2 STA 1 With one unit in CONDITION 4 or 5 and no fuel loaded in other unie reactor l Position Number of Individuals Recuired SS 1 SRO O R0 1 NLO 1 STA 0 is i

Prgs 2 TABLE 6.2.2-1 MINIMUM SHIFT CREW COMPOSITION Table Notation (a) - Individual filling this position shall be in the control room at all times except when relieved by an individual holding a Senior Reactor Operators License, who shall then provide the required SRO presence. (b) Individuals acting as relief operator shall hold a license for both units. Otherwise, provide a relief operator for each unit who holds a license for the unit assigned. SS - Shift Supervisor with a Senior Reactor Operators License for each unit whose reactor contains fuel. SRO - Individual with a Senior Reactor Operators License for each unit whose reactor contains fuel. Otherwise, provide an individual for each unit who holds a Senior Reactor Operators License for the unit assigned. RO - Individual with a Reactor Operators License or a Senior Reactor Operators License for unit assigned. One RO shall be assigned to each unit whose reactor contains fuel and one RO shall be assigned as relief operator for unit (s) in CONDITION 1, 2 or 3. NLO - Nor. licensed operator properly qualified to support the unit to which assigned. STA - Shift Technical Advisor, properly qualified to support facility operations. This is an interim position which need not be filled after the Shif t Supervisor qualifications are upgraded equivalent te STA qualifications. Except for the Shift Supervisor, the Shift Crew Composition may be one less j than the minimum requirements of Table 6.2.2.1 for a period of ti=e not to exceed 2 hours in order to accommodate unexpected absence of on-duty shif t crew members provided immediate action is taken to restore the Shift Crew ( Composition to within the minimum requirements of Table 6.2.2-J. This provision does not permit any shift crew position to be unmanned upon shift change due to an oncoming shift member being late or absent. i ' During any absence of the Shif t Supervisor from the control room, an individual with a valid SRO license shall assume the control room command function. D 30

c. principal radionuclides (specify whether determined by measurement or estimate),

d. type of waste (e.g., spent resin, compacted dry waste, evaporator bottoms),

e. type of container (e.g., LSA, Type A, Type B, Large Quantity), and

f. solidification agent (e.g., cement; urea formaldehyde).

The radioactive effluent release reports shall include unplanned releases from the site to unrestricted areas of radioactive materials in gaseous and liquid effluents on a quarterly basis. The radioactive effluent release reports shall include any changes to the PROCESS CONTROL PROGRAM (PCP) made during the reporting period. Monthly Reactor Operating Report 6.9.1.10 Routine reports of operating statistics and shutdown experience, including documentation of all challenges to the Code Safety / relief valves, shall be submitted on a monthly basis to the Director, Office of Management and Program Analysis, U.S. Nulear Regulatory l Cocaission, Washington, D.C. 20555, with a copy to the Regional Office of Inspection and Enforcement, no later than the 15th of each month following the calendar month covered by the report.

l Any changes to the OFFSITE DOSE CALCULATION l MANUAL shall be submitted with the Monthly i Operating Report within 90 days in which the l change (s) was made effective. '

I Reportable Occurrences l 6.9.1.11 The REPORTABLE OCCURRENCES of Specifications 6.9.1.12 and 6.9.1.13 below, including corrective actions and measures to prevent recurrence, shall be reported to the NRC. Supplemental reports may be required to fully describe final resolution of occurrence. In 9 case of corrected or supplemental reports, a 6-16 10/80 h r l St t

m .

                                                                .                      NDI-QA-4.1.4 NUCLEAR DEPARTMENT INSTRUCTION Rs. O, 12/23/80 Page 1 of 10 INSTRt'CTOR CERTIFICATION             NDI-OA-4.1.4 Originating Manager         u.anager-Nuclear Training I M - b l. I              Iby   f
 .                                                Title                    /      Slgnature e._

Reviewing and Concurring Managers Title Signature . Title Signature

                    /        )L  iA
                                                ...n J.i'ML OUI KOUED
                                                                                        /
                            / .n            // } 1 ,,.

ss== f, f i l 4\/

                                                                             }        /

y' K //\!/ [/I V L-/ Approved Date 1.0 Purcose l This procedure states the certification requirements and certification process for persons perfoming the duties of instructor. 2.0 Scope This procedure applies to all instructors in the Nuclear Department l and to instructors and their supervisors outside the Nuclear Department, l who perform nuclear related training. An example of these instructors outside the Nuclear Department are the PP&L Construction Department Training Instructors who teach General F.mployee Training and Health ( . Physics Training to Construction Department employees. l 3.0 References 3.1 NUREG-0585 TMI-2 Lessons Learned Task Force Final Report, Page l A-6. l 3A

l

                                                                         .-   NDI-QA-4.1.4
    .                                                                         Rev. O, 12/23/80 Page 2 of 10 3.2 Harold Denton's letter of March 28, 1980; Article 2.d.

3.3 ANS 3.1 - 1979 (Draft) , 3.4 Regulatory Guide 1.8 Revision 2 - 1980 (Draft) 4.0 Definitions , 4.1 Instructor Certification - A procedure designed to ensure that personnel performing training are competent to perform that training. 4.2 Instructor - A person with the job title of Instructor or Simulator Instructor, who normally develops and presents training coe ses. 4.3 Temporary Instructor - A person who performs formal instruction on a temporary basis within his own work group, as a temporary addition to the training staff, or because of expertise in a specific field. 4.4 On the Job Training Instructor - a person who instructs using

                   - the informal method of On The Job Training as. described in NDI 4.1.6.                   .

4.5 Contr'act Instructor - a person who is a member of an organization outside of PP&I. but is working as an instructor in the Nuclear Department under the terms of a contract. This person reports to a manager in the Nuclear Department and normally performs any training functions assigned. 4.6 Vendor Course Instructor - a person from an organization outside the Nuclear Department, who is teaching a training course to members of the Nuclear Department. His services normally consist of only those required to present the course. 5.0 Responsibilities 5.1 Manager Nuclear Training ! . Responsible to ensure all persons with the job title of Instructors l performing nuclear related training are competent to perform training and are certified in accordance with this procedure. 5.2 Supervisors - Nuclear Training Group l Responsible to ensure instructors in their section are certified to perform training assigned.

Responsible to provide training and retraining as required to enable-the instructors to' achieve and maintain certification. e l . 33 y y

  -                                                                         NDI-QA-4.1.4 Rev. O, 12/23/80 Page 3 of 10 Responsible to evaluate instructors and upgrade or remove from teaching assignments any instructor who does not meet the appropriate certification requirements.

w ~ 5.3 Instructors and Simulator Instructors Responsible to complete the certification requirements assigned. 5.4 Supervisors in the Nuclear bepartment Responsible to ensure that personnel they assign as Temporary Instructors and On The Job Training Instructors are certified in accordance with this instruction. 6.0 Instructions - 6.1.(h2 The Job Training Instructors shall be certified to instruct

               ' as follows:

6.1.1 The supervisor assiguing a person as an On The Job Training Instructor shall 6.1.1.1 ensure the person is technically competent to instruct.the skill or task assigned, 6.1.1.2 ensure the person is sufficiently skilled in On The Job Training techniques to perform the training satisfactorily. 6.1.1.2.1 This includes desire to teach, communications ability and ability to answer questions. 6.1.2 No documentation is required to certify as an On The

                        . Job Training Instructor.

6.2 Temporary Instructors shall be certified to instruct as follows: 6.2.1 The supervisor responsible for the training shall 6.2.1.1 ensure the person is technically competent j to instruct the topic assigned.

                     . 6.2.1.2    ensure the person is sufficiently skilled in instructional techniques to perform ~the

, training satisfactorily.

6.2.1.2.1-This includes desire to teach and public speaking ability. l 4 l 34

                                                                       '    NDT-QA-4.1.4 Rev. O, 12/23/80 Page 4 of 10 6.2.2    No documentation is required to certify as a Temporary Instructor.

s --e.- 6.3 Instructors shall be certified to instruct as follows: 6.3.1 The Instructor shall receive instruction covering the following topics: 6.3.1.1 Adult Learning and Motivation 6.3.1.2 Lesson Plan Preparation and Use 6.3.1.3 Use of Instructional Aids and Equipment 6.3.1.4 Classroom Teaching Techniques 6.3.1.5 Skills /" Hands On" Teaching Techniques 6.3.1.6 Questioning and Testing Techniques 6.3.1.6 Evaluation of Training Note: This instruction may be completed in a comprehensive Instructor Workshop. 6.3.2 Prior to completion of the requirements for instructor certification the instructor should be assigned instructional duties. 6.3.2.1 The Instructor should be certified for these duties using either 6.3.2.1.1 On The Job Training Instructor Certification Method 6.3.2.1.2 Temporary Instructor Certification Method. 6.3.3.2 If certified using either method, a person who meets the requirements of 6.4.2 or 6.4.3, may instruct the licensed operator training identified in 6.4.1. 6.3.3 Instructor Evaluation 6.3.3.1 When the supervisor determines that the instructor is ready for certification the supervisor should schedule evaluations for the instructor. 6.3.3.2 At least 3 evaluations using Nuclear Department Form QA-4.1.4-A with an overall grade of " GOOD" or b< tter shall be required . for Certification. 6.3.3.2.1 Grades in a'scending order are: Poor, Fair, Good, Excellent, Outstanding. m

                                                                   .                           3T

NDI-QA-4.1.4 Rev. O, 12/23/80 Page 5 of 10 6.3.3.3 These evaluations

   **==cr 6.3.3.3.1 shall be performed by training supervisors in the Nuclear Department and should be performed by three different supervisors.

6.3.3.3.2 shall be performed at different training sessions on different days. 6.3.3.3.3 shall become part of the instructors training record. 6.3.4 Certification Recommendation and Appt, val

                 .         6.3.4.1     The Instructor's supervisor may recommend Certification as an Instructor when:

6.3.4.1.1 The ind'vidual i has completed the training and evaluation identified in 6.3.1, 6.3.2 and 6.3.3.

                                      - 6.3.4.1.2 The supervisor subjectively determines that the individual is capable of performing all the duties of an instructor.

6.3.4.2 When the Instructor has met all toe require-ments for certification, the Manager Nuclear Training may approve his certification. 6.3.5 This certification shall be documented using Nuclear Department Form QA-4.1.4-B. 6.3.6 Certification as Instructor ensures that a person is skilled in instruction techniques. 6.3.7 Prior to assignment to teach any lesson the supervisor shall ensure the Instructor has sufficient technical ! knowledge for that lesson. 6.4 Licensed Operator Training Instructor 6.4.1 Technical Certificatien is renuired to ensure technical

                                                                              ~
          ,                competence if the Instructor performs the following portion of the Licensed Operatar Training program:

6.4.1.1 Susquehanna Systems Technology Course 6.4.1.1.1 Nuclear Steam Supply Systems 9 s

3(.

4

                                                              ,     NDI-QA-4.1.4
     '                                                              Rev. O, 12/23/80 Page 6 of 10 6.4.1.1.2 Integrated Plant Operation 6.4.1.2    Susquehanna Operations    Course w                                          -

6.4.1.2.1 Integrated Plant Operation 6.4.1.2.2 Plant Responses 6.4.1.2.3 Transients 6.4.1.2.4 Simulator Training 6.4.2 Technical Competence to perform the portions of Licensed Operator Training identified in 6.4.1 shall be certified using the following methods. 6.4.2.1 Hot License Training and Requalification Training Instructor. 6.4.2.1.1 Shal) pass an NRC administered SRO Examination for Susquehanna SES. . Note: Required by Reference 3.4 Position 14. 6.4.2.1.2 If 6.4.2.1.1 i s not met jan instsc: tor may be provisionally certified to teach the portions identified in 6.4.1 if the following are met. 6.4.2.1.2.1 Pass a company administered SRO l examination for l Susquehanna SES. I 6.4.2.1.2.2 Within 30 days of company certifi-cation submit application for NRC administered SRO examination. Note: The option stated in 6.4.2.1.2 is not pe. sitted by any reference to this rocedure. Precedent for this aption may be found in the quitification of instructors at Vendor Simulators. L__

NDI-QA-4.1.4 Rev. O, 12/23/80 Page 7 of 10 The .ntent of this option is to rilew a technically and profes-onally ec=petent person to 6 -=r-r erform the indicated duties while the application for exani-nation is being processed by the NRC. 6.4.2.2 Inicial Cold License Training Instructors shall be certified to perforn the portions identified in 6.4.1 by either of the following methods. , 6.4.2.2.1 Pass an NRC adninistered SRO examination for Susquehanna SES.

            ,                                  Note: Meets requirenents of t

Reference 3.4. 6.4.2.2.2 Hold or'have held an SRO license from a BWR. Note: Meets Reference 3.1 Appendix A paragraph 1.4(6), Reference 3.2 Enclosure 1 para-graph A.2.d, Reference 3.3. paragraph 4.4.7.2b. Does not meet Reference 3.4 Exception 2.6 which requires

                                               " Successful completion of SRO examination applicable to the facility for which the courses are intended".

I 6.4.2.2.3 If-an instructor does not meet

                              .                either 6.4.2.2.1 or 6.4.2.2.2, he say be assigned to teach the portions identified in 6.4.1 if he is sp;e. vised .by a person metr'.:.g thes t requirements.

6.4.3 Individuals with knowledge in siecific areas nay . . instruct the' portions of lice,med operator training listed.in 6.4.1 concerning those specific areas

        ,               without meeting the'ren.uirements of 6.4.2. These individuals shall be ce ttified as stated in 6.1 or 6.2 as appropri:::.                                                    -

38

i

                                                                       '     NDl-QA-4.1.4 Rev. O, 12/23/80 Page 8 of 10 6.5 Contract Instructors shall be .ertified as appropriate using one of the following methods; w .ar-        6.5.1       On The-Job Training Instructor Certification 6.5.2       Temporary Instructor Certification 6.5.3       Instructor certification 6 . 5 .'3.1  Contract Instructors who are contracted for greater than 6 months should co=plete Instructor Certification.

6.6 Vendor Course Instructors 6.6.1 Certification :f Vendor Course Instructors shall be considered when aalyzing the course and instructors offered. Acceptance of the course indicates approval of the instructor for that course. No additional documentation is required. 6.7 Recertification of instructors and licensed operator training instructors. 6.7.1 Annual formal instructor training sessions should'be held to maintain and improve skills. These training sessions should cover topics related to training

             '             duties. Each instructor should attend 24 hours of formal instructor training annually.

6.7.2 Instructors' performance shall be observed twice a year in the following areas. Form NDI-QA-4.1.4-C shall be completed to document these evaluations. 6.7.2.1 Classroom Presentations 6.7.2.2 Skills Presentations 6.7.2.3 Training Course Development 6.7.2.4 Administrative Areas (testing, reports, student evaluations,etc.) 6.7.2.5 Technical Competence 6.7.3 Supervisors shall take corrective action, as acces-i sary to upgrade deficiencies whe they are detected. i 6.7.4 In addition to the above steps, licensed operator training instructors shall be enrolled in a technical requalification progres to maintain the required . level of technical co= 6 l. M M 267A %petencec M~M 4 % d W W % e 9M--TMJ- QI4.2 Note: This meets tne requirements o all references.

i* 3*/ e

NDI-QA-4.1.4 Rev. O, 12/23/80 Page 9 of 10 6.8 Certification to instruct specific courses or lessons. 6.8.1 Instructors in the Nuclear Training Group and Con-t -=rr struction Department Training Instructors when teaching nuclear safety related material shall be certified to instruct a lesson or course prior to instructing that lesson or course. Note: Section 6.8 does not apply to instructors or training supervisors in the Susquehanna Plant Staff Security Section. 6.8.2 When an instructor is technically competent and possesses the required instructional skills for a particular course or lesson:

                 ,           6.8.2.1    The appropriate supervisor in the Nuclear Training Group should recommend the instruc-tor for certification for that course or lesson by completing the appropriate information on Nuclear Lepartment Form QA-4.1.4-D.

6.8.2.2 The Manager. Nuclear Training may approve this certification by signing the appro-priate line on Nuclear Department Form QA-4.1.4-D, after he has ensured that the instructor i's able to instruct the lesson or Course. 6.8.3 No instructor may instruct a course or lesson without this certification. Nuclear Training Group Supervisors may grant interim

                          . certification without the approval of the Manager-Nuclear Training.

The supervisor's recommendation on Nuclear Department Form QA-4.1.4-D documents the granting of interim certification.

       .           6.8.4    Instructors shall be reevaluated by the appropriate supervisor each time they are assigned to instruct a lesson or course. Documentation of this reevaluation is not required.

6.8.5 If an instrnetor is determined to be no longer able to satisfactorily instruct a course or lesson: 6.8.5.1 A program designed to upgrade technical competency and instructional skil)I to the _m

                                                            .                                  N

h

                                                                                             -   NDI-QA-4.1.4 Rav. O, 12/23/80 Page 10 of 10 required level shall be co=pleted prior to assignment as instructor for that course g,,,e_                                              or lesson.         -

OR 6.8.5.2 The appropriate supervisor shall revoke the certification to instruct that course or lesson by drawing a line through the certification or. Nuclear Department Form QA-4.1.4-D and signing his name next to the line out. 6.8.6 During the period that the Manager Nuclear Training position is vacant, either the Acting Manager Nuclear Training or the appropriate supervisor in the Nuclear Training Group may approve this certification on For= NDI-QA-4.1.4-D. Note: Certification required by 6.8 is required by Reference 3.3, Paragraph 4.4.7.2.d.

7. 0 Records ,

7.1 For:s A, B, C, and D of this procedure are QA records. They shall be filed in the employee's training record and inserted into the Susquehanna Records-Management System as described in appropriate records management system procedures. 7.2 Reco-ds documenting a Senior Reactor Operator License or Certification shall be handled in accordance with NDI-QA-4.2.1, ' Licensed Operator Training and Qualification Frogram.

              - (MG/11-K) e m
           .e 4l

Nuclear D*pt. Form QA-4.1.4-A Rev. O, 12/24/80 CUIDE FOR EVALUATION OF INSTRUCTION INSTRUCTOR DATE ROOM _ LESSON LENGTH EVALUATOR'S SIGNATURI NO. OF STL* DENTS CLASS NUlf3ER COURSE NAME w-- 3 9 E 5 5 d 8 5 g M 0 x 8 5 m LESSON: W

GENERAL COMMENT

S: 8 I .' INTRODUCTION

A. Establish student learning goals A .' l l B. Provide adequeate cotivation B.I i l l II. PRESENTATION A. Logical A. l l

B. Explain unfa:iliar ter=s B. I C. Use adequate training aids C. I l I D. Utilize Training aids effectively D. __ E. Use of proper questioning technique E. F. Stress "uhy" and

                     " application"                     F.

G. Allow for proper notetaking G. H. Maintain class control H. I I. Tactful I. i f J.' Technical Content of Lesson J. } I III.

SUMMARY

A. Effectiveness A. l l l l INSTRUCTOR: I. PERSONAL TRAITS - A. Quality of voice A. l l B. Volume of voice B. i l C. Type of Delivery C. I D. Rate of speaking D. I t E. Body =anneris=s E. ' t i F. Pronuncia**,on 7. I t G. Enunciation G. I i~"" . H. Choice, use of words H. l l I. Eye contact I. l J. Enthusiasm J. K. Appearance K. I II. . GENERAL CHARACTERISTICS A. Use of the lesson plan A. B. 'Use of available ti=e B. I C. -' Accomplishment of the

                    ~ obiectives                        C.

OVERALL EVALUATION A. l 4A

1 Nuclear Department Form QA-4.1.4-B NDI-QA-4.1.4 Rev. O, 12/24/80 INSTRUCTOR CERTIFICATION DOCUMENTATION - INSTRUCTIONAL TECHNIQUES sg -

(Name) Employee No. (Position) I. INSTRUCTOR CERTIFICATION ' Completed Training in the following areas: Certifier /Date

1. Adult Learning and Motivatics

2. Lesson Plan Preparation and Use

3. Use of Instructional Aids and Equipment 4 Classroom Teaching Techniques

5. Skills /" Hands On" Teaching Techniques

6. Questioning and Testing Techniques

7. Evaluation of Training Signature of Supervisor Instructor Evaluations *:

(Grade) (Date) Signature of Nuclear Department Training Supe: visor Certification Recommended Supervisor Signature (Date) Certification as Instructor Approved Manager Nuclear Training (Date)

Evaluations should be attached to this form.

43

Nuclear D:partmInt Form QA-4.1.4-C NDI-QA-4.1.4 : Rev. O, 12/24/80 l ANNL'AL INSTRUCTOR RECERTIFICATION - Year 6 -c-Instructor Name Employee Number Job Title I. Formal Instructor Training completed this year. Topic / Title of Course Date II. Instructor Evaluations Grade (Outstanding, Excellent) Evaluator's Areas Evsluated Date (Good, Fair, Poor) Signature Clasr som Presentations - Skills Presentations Training Course Development Administrative Areas Technical Competence NOTE: In any area evaluated as " poor" the supervisor shall institute a retraining program immediately. The program outline, and results of a backup re-evaluation shall be attached to this form. III. Instructor Recertification Recommended: Supervisor /Date IV. Instructor Recertification Approved: Manager-Nuclear Training /Date W 94

a . Nuclear Departm m t Form QA-4.1.4-D i NDI-QA-4.1.4 Rev. O, 12/24/80 CERTIFICATION TO INSTRUCT SPECIFIC COURSES OR LESSONS im e - - Instructor Name Employee Number Job Title Recommended Approved Course or Lesson for which Course Number NTG Supervisor / Manager Nuclear i Certified (if appropriate) Date Training /Date e e N 4 P., h 4 \ a l-l' ( . U

e i ' f '8 NUCLEAR DcPARTMENT INSTRUb NON Licensed Operator Training e d Oud ifi;at Program

Originating Manager Manager - Nuclear Training E. R. Carlson Title Signature

 & --e-Rev.iewing and Concurring Managers Title            , Signature            Jitle              Signature
                                 /-                       '

V, f).c- lM

i T

                                                        , ,N/

n yU V N

Vt

6 Approved Date 1.0 Purpose

                 'This instruction describes the licensed operator training and qualification process and delineates responsibilities and requirements for subject material, courses, certification grading criteria and record keeping.

2.0 Scope This instruction is applicable to the new license candidate as well as requalification of a current license-holder. - - 3.0 References 3.1 ANS 3.1 Draft version 12/6/79 entitled Standards for Qualification and Training of Personnel for Nuclear Power Plants.

kb

 .-         s.

k ( NDI-4.2.1 Rev. 0 - 2/1/81 Page 2 of 11 3.2 NRC letter from Harold Denton to all reactor applicants and t -ac- ' licensees dated March 29, 1980, entitled Qualification of Reactor Operators. 3.3 Reg. Guide 1.8 dated June 19, 1980, entitled Persoanel Selection and Training. 3.4 NUREG 0094 Rev. 1 of Wash 1094' dated July, 1976, entitled A Guide for the Licensing of Facility Operators, Including Senior Operators. . 3.5 Title 10 Code of Federal Regulations Part 55 entitled Operator Licenses. - 3.6. FSAR Chapter 13.2 3.7 INPO - Guidelines for Requalification Training and Evaluation, Oct., 1980. 4.0 Definitions 4.1 Licensed Operator - Any individual who manipulates a control of a

 ,- -                     facility. An individual is deemed to manipulate a control if he directs others to manipulate a control.

4.2 Senior Licensed Operator - Any individual designated to direct the licensed activities of licensed operators. 4.3 Cold License - That operator license issued before fuel load occurs. 4.4 Hot License - That operator license issued after fuel load occurs. . 4.5 Requalification - That training / licensing process pursuant to issue of initial license and prior to issuance of subsequent licenses. ,

          .        4.6 License Candidate - The person who is in training to become a licensed operator o'r senior licensed operator.

5.0 Responsibilities 5.1 Vice President-Nuclear Operations Responsible for certifying to the Nuclear Regulatory Commission

      ,                   that the license candidate has met all applicable requirements, is technically competent to operate the- controls, and is 47

                                             -.      - __ .=                          __        .

(- (.

        -    s       ..

N NDI-4.2.1 Rev. 0 - 2/1/81 Page 3 of 11 medically sound to carry out licensed activities a.t Susquehanna

    %                        SES.             -                 -

5.2 Manager Un-lear Training Responsible for identifying and developing PP&L liceose training programs which meet all applicable industry and govsrnment requirements, and company training needs in areas of Susquehanna operations, maintenance, engineering, and relates support activities. 3.3 Supervisor-Operations Training

Responsible for implementing the license training programs, and for administering the written and simulator demonstration certification examination. 5.4 Supervisor-Training Service Responsible for maintaining training records which document

                            ' training and qualification history.

55 Superintendant of Plant-Susquehanna SES 7 Responsible for confirming that each' licensed operator candidate. ' has been properly trained, meets experience requirement, is technically competent and is medically sound to carry out licensed operator activities at Susquehanna SES and for recommending s'uch candidates to the Vice President - Nuclear , Operations

t.1:2 :: p:::iM f # conducting oral and walk-

                          ~t hrough exa,minations of each license candidate; destablishment

of the Performance Review Program.

5.6 Supervisor of Operations-Susquehanna SES Responsible for.# screening, selection, and assignment of license candidates to license training; ensuring each candidate meets the minimum acceptable criteria for. licensed operators; establishing, i_ implementing, and evaluating the Inplant Drill program; certifying candidate's Operational Competence and readiness for licensed operator duties. - - 5.7 Plant Administration Supervisor-Susquehanna SES

                          -Responsiblefortsettingup,schedulingfanddocumentingthe                   ,

medical certification program; preparation and distribution of license' applications. S 48

t ( GA NDI-4.2.1 Rev. 0 - 2/1/81 Page 4 of 11 5.8 Shift Supervisor-Susquehanna SES se - Responsible for: Certifying that the license candidate and/or operator has performed acceptably during the evaluation period (on-the-job-training or requalification cycle); identifying individual and/or shift complement training deficiencies and reporting deficiencies to Supervisor of Operations-Susquehanna SES. 6.0 Instructions , 6.1 Licensed Operator Candidate 6.1.1 The Supervisor of Operations shall select the persons

                             ,            to be placed in the licensed operator candidate training program based on established criteria of academic training, prior work experience and performance, and appropriate screening exams and procedures per reference 3.1. Appropriate training waivers will be determined by Manager Nuclear Training and Superintendent of Plant.

6.1.2 The 'licehsed operator candidate course should consist. of the following subjects as implemented by the Supervisor-Operations Training (outlined by references - dn Section 3): (The candidate will be given credit for any portion of these subjects 7pYo9fded"tTE person's scores were consistent with those in section 6.1.5.3.;) . 6.1.2.1 Fundamentals - Typically 18-22 weeks long consisting of mathematics, physics, chemistry, metallurgy, health physics, reactor ope. rations, electricity / electronics,

                                               ,. heat transfer and fluid flow and thermal hydraulics. This may be taught by PP&L personnel or outside training service organization or a combication and will use

,_ standard training techniq'ues including I . lectures, video tapes, exams, quizzes, and

                                                     ' textbooks.

6.1.2.2 Susquehanna Systems Technology - Usually 8

                     ,                                 weeks in length, consisting of-lectures, plant tours, and seminars on plant specific system design bases, flowpaths, components, instrumentation and controls, and operational
     ,                                                 aspects.

u W

         .s ..

( (- NDIy4.2.1 Rev. 0 - 2/1/81 Page 5 of 11 6.1.2.0 Susquehanna Operations - Usually b weeks long, consisting of lectures, seminars, and simulator exercises which apply the operating philosophy, procedures, and attitude needed as an operator in the Susquehanna SES Control Room; covers transient, malfunction, surveillance and normal operations. A / M ' 6.1.3 aO&z 5 .cd&1. Q 'sM. Additionally, a senior licensed operator candidate course should consist of: 6.1.3.1 Advanced Nuclear Fundamentals and Engineering

                                      - usually a 3 to 5-week course on advanced theory, thermal hydraulics, core response, transient analysis, and computer utilization.

6.1.3.2 Advanced Chemistry and Health Physics - a 2 week long session to cover sa=pling, analysis, control, and evaluation. 6.1.3.3 Management Theory and Practice - 1 week long course on managing people and resources.

6.1.3.4 Analytical Practices and Decision Making - a 1 week long session on using indications to arrive at causes, solutions, and determining

                        .            appropriate course of action.

6.1.3.5 Administrative Controls ' Typically one week long covering Station. Emergency Plan and administrative procedures. 6.1.4

                                                                                  . G s.ual When the above training has been completed Cru d # ~,

satisfactorily, the Si=l:ter Supervisor /should make arrangements for a certification exam to be administered. 6.1.5 Certification Examination - consists of written, oral, plant walk-through and simulator examinations which demonstrate that the license candidate can safely operate the plant, has good technical knowledge of the , plant system, can adequately and accurately express himself, and knows the locations and layout of the plant equipment and systems. 6.1.5.1 Persons responsible for examination ' administration should be:

4

                 ,s     ,

k , ( Ob NDIg4.2.1 Rev. 0 - 2/1/81 Page 6 of 11 6.1.5.1.1 Written examination: Supervisor-operations W' ' Training Should consist of the following area:

               '                                     lo-MPrinciples of Reactor operation Features of facility Design General Operating Characteristics Instrumentation and Control Safety and Emergency Procedures Radiation Control and Safety
                                           '           Heat Transfer and Fluid Flow
                                                      . SEQ - (In addition to above)

Emactor Theory

                            ,-                        Radioactive material handling Specific Operating Characteristics Fuel Handling and Core Parameters Administrative Procedures
                               ,                      Theory of Fluids and Thermodynamics i                                       6.1.5.1.2 Oral examination - Superintendent of Plant,
            '                                     ~

6.1.5.1.3' Plant examination - Superintendent of Plant 6.1.5.1.4 Simulator Demonstration: Supervisor-Operations Training 6.1.5.2 Passing certification examination scores will be:

                                     . 6.1.5.2.1 Written - 270% in all areas with overall i

average > 80%. If any area is less than 70%,

                                             .c the area should be retested in 5 working days; if the average is (80%, the entire exam should be readministered in 20 working days.

If the results are still < 70% in an area or

                                                    <80% overall, the candidate shall be removed from the license training program or a waiver obtained and an appropriate retraining program developed by plant and, training management.

6.1.5.2.2 Oral Examination - All board membe'rs must pass the candidate; if not, the candidate should be retested in 20 working days. If the candidate does not pass the second time, the candidate shall be removed from the

C C-a

NDIt 4.2.1 Rev. 0 - 2/1/81

                                                 .                                    Page 7 of 11 license training program or a waiver obtained and an appropriete retraining program developed by plant and training management.

6.1.5.2.3 Plant examination - The candidate cust pass this examination; if not, another plant examination should be administered in 20

   .                                                working days. If the second exam is also failed, the candidate shall be removed from the training program or a waiver obtained and an appropriate retraining program developed by plant and training management.

6.1.5.2.4 Simulator Demonstration ~- The candidate must pass the examination; if not, a second examination should be administered in 20 working days. If the second exam is also failed, the candidate shall be removed from the license training program or a waiver obtained and an appropriate retraining program developed by plant and training management. 1 <

6. l'. 6 Upon successful certification, the Supervisor-

                                       . Operations Training should notify the Supervisor of Operations that the license candidate is ready.for a 3
                                 .      month "on-the-job" trainine; period where he shall be assigned to an operating shift as an extra licensed operator "in training" to learn control room practices and procedures. (Not required for cold license examination.)

6.1.6.1 At the end of the third month, the Supervis'or of Operations shall make a written evaluation to the Superintendent of Plant recommending either application for a license examination or additional training for this person. 6.1.6.1.1 If licensing is recommended, the Superintendent shall forward Attachment 1 to Vice President-Nuclear Operations who will certify the Candidate is ready for assuming the responsibilities associated with the. license. If he determines through a records review and

interview that the candidate is ready for these responsibilities, he should certify to the h7C that Q

j. -

( , ( NDI .2.1 Rev. 0 - 2/1/81 Page 8 of 11 the candidate is ready for h e- ' licensing, and request a license examination be administered by the NRC. 4

                                                                       ,         6.1.6.1.1.1                If the NRC examination is failed, the candidate will be placed in an upgrade program after which another certification
                                                 ,                                            examination will be a&ninistered.               If the certification exam is
                              .-                                                              passed, the Vice President-Nuclear Operations will ag~ain review the qualifications
                                 ,                                                            of the candidate and, if appropriate, certify to the NRC that the individual is competent and request an examination be administered.               If the  ,

licensing examination is sp ~ failed, the candidate shall be removed from the - license program. 6.1.6.1.2 If continued training is

                                         .                                      recommended, a maxianum of 3 additional months should be provided, after which the above process should be repeated. If licensing is again not recommended, the license candidate shall be removed from the license training G ' I* ' NE                 ' olut L Gu                   Ch A Mg 7 6.2 Li'ensed c     Operator Requalification Training                                f 6.2.1      The Supervisor-Operations Training shall' implement the requalification training program within 3 months of                       '

receipt of the initial facility opv sting license. It should consist of those areas defined by references in

                                            .Section 3, and specifically:

O E3

_ _ . . . _ _ . ~ . 4 E

Gb NDIx4.2.1 Rev. 0 - 2/1/81

                                        ,                                     Page 9 of 11 6.2.1.1      Pre planned lecture series consisting of e -er                                   . classroom lectuce, seminars, and self-study covering:                                                                   -

i

                                             ' Rx Theory and Principles of Operation                                      ['
                                    .         General and specific plant operating Characteristics

Instru=entation and Control Systems !

Protection Systems Normal, abnormal, and emergency procedures ; Radiation control and safety Technical Specifications Code of Federal Regulations ' Hed Teenske- and find Pha l '.,n " !- L' * * +1 6.2.1.2 Operational evolutions consisting of simulator and plant activities covering topics identified in Attachment 3 during which time a formal annual perfor=ance evaluation will be completed. 6.2.1.3 Design, Procedure, and facility license Change Review including recent IP.R's, industry events, and significant plant

                      ,                       activities.
                      -                                                                                                    t 6.2.1.4      In plant drills which require appropriate                                    1 responses in the form of walk-throughs or actual manipulations and actions. (This phase shall be conducted 4y Supervisor of                              -

Operations.) 6.2.1.5 - Periodic exaninations to monitor program

effectiveness.

6.2.2 An annual written examination shall be administered consisting of those areas identified in 6.1.5.1. A grade of 70% in any category or less than 80% overall : will require accelerat?d requalification training and I another written examination to be ad=inistered. . 6.2.3 At least biennially, a recertification examination will I be administered consisting of a written, oral, plant walk-through, and simulator demonstration. The written exam passing criteria shal,1,be> 70% in all categories (defined.in-6.1.5.1) and K r80% overall. Tuu e s .1, _ plant walk-through, and simulator demonstration shall-

f

                               ' be graded " pass".

.-[^ Si

                                                          -         ,    ,    r-     - <       -r-

o

                                                  %                                         . \.

NDI;;4.2.1 Rev. 0 - 2/1/81 Page 10 of 11 6.2.4 If the ancf. performance evaluation is failed or the annual written examination score is<80% overall on the re-exanination,or any phase of the biennial recertification exam is failed, the Performance Review Program shall be implemented by the Superintendent of Plantye- r e k-ec~ee. J.4 6.2.5 At least sixty days before license expiration, the Superintendent of Plant shall recommend in writing to , the Vice President-Nuclear Operations those licensed and senior licensed operators who meet the standards for license renewal as documented by Attachment 2. 6.2.6 The Vice President-Nuclear Operations shall certify to

                          ,                    the NRC via license renewal requests at least 30 days prior to license expiration that those recommended individuals meet government requirements and should be
                                              ' relicensed.

l.. z . '1 rL:,%d-~:~ sLa L&

6. 'i Absence From Licensed Duties.

                                                                                           %l&          cf' LetJ        V z.

6.3.1 If a licensee is not actively performing licensed duties n'or attending the Requalification Program for a period of 45 days or longer, the Supervisor of Operations shaU not.ify the Supe arisor-Operations Training. That prson shculd be given appropriate training to ensure that the licensee is cognizant of recent plant and procedure modifications prior to performing those duties which require the NRC license.

This training should be documented using Attachment 4.

i 6.3.?

If a license holder is not actively performing licensed duties nor attending ,the Requalification Program for a peri,od of 60 days or longer, the Supervisor of Operations shall notify the Supervisor-Operations Training who shall provide appropriate training 'and arrange for an annual certification examination to be administered prior to the license h' older assuming

, duties requiring a license. This training should be documented using Attachment 4.

S e

                                  --          a m   . _   ._            ,

e

g 4L Gb NDI-!4.2.1 Rev. 0 - 2/1/81

                                            ,                                        Page il of 11 7.0 Records                                                          -
                                                                ~
                  ~7.1   Training Record' The Supervisor-Training Services shall be responsible for maintaining the license holders' and candidates' training records in accordance with Nuclear Training Group Procedures and
     ,                   reference 3.1.

7.1.1 Work history including copies of formal education certificates, trade school certificates, military service history; selection examination results; medical and psychological examination results; course I examination results att actual examinations if administered by PP&L; certification results; copy of

                                     . . vious and current licenses; copy of performance appraisals for as long as the person is a license

holder at Susquehanna SES.

GA-7.2 The appropriate attachment to NDI36 2.1 shall be completed prior to each license examination request and filed in the applicant's training record. d e d a f

v.

N o

( . ( Att chment 1 NDI .2.1 Rev. 0 - 1/1/81 Page 1 of 2

   , , , ,                                       L'icensed Operator Candidate Training Checklist SRO/R0       (Circle One)

Name of License Candidate Level

1. The above named person has satisfactorily completed the requisite training..

R0 Topics Score Date

a. Fundamentals Systems Technology

                         ' Susquehanna Operation

b. SRO (Above plus:)

Advanced Nuclear Fundamentals. and Engineering

 .                           Advanced Chemistry 'and Health Physics Management Theory and Practices Analytical Practices and Decision Making i

Administrative Controls Manager-Nuclear Training /Date t

2. The above' named person has successfully passed the , certification examination.

          ,                                                      Score                 Date i

a. -Written Examination '

RO . SRO

                  'b. 1 Simulator Demonstration i ~

l l

                                                                                                      $i7 o                                         ..                                _

k k-Attachment 1 NDP*.2.1 Rev. 0 - 1/1/81 Page 2 of 2

 **=mm-          c. Plant Examination                       -

d. Oral Examination Supervisor - Operations Training /Date

3. The above named person perfor:ed satisfac '.orily as an " extra on-shift" operator from to .

Shif t Supervisor /Date

4. The above named person has been found technically competent, kneeledgeable of plant procedures, capable of performing licensed duties, and meets necessary experience requirecents.

Supervisor of Operations /Date

5. The above named person has been found medically fit as required by if CIR55.60 to perform licensed operator duties.

Plant Administration Supervisor /Date

6. The above na=ed person's records have been reviewed, an interview has been conducted, and the person has been found to meet all requirements for examination by the NRC; therefore licensing is reco== ended.

Superintendent of Plant /Date

7. The above named individual is approved for examination by the NRC.

Vice President-Nuclear-Operations /Date

          ' Attachments: Experience Requirements and Summary Sheet Ccpy Medical ~ Certificate                                          ,

3 Month on Shift Training Evaluation Report. 2 e c.Avi f g m w ecotw.,4 6 k cr t..r e ( d #elma r f a e r. -Qa. .L 2.s/ i Copy to: Individual's Training Record 9

( ( Attach =ent 2 l NDIf 2.1 Pav. 0-1/1/81 Page 1 cf 3

w Licensed-Cperator Biennial Requalificatics Training Checklist Name of License-Operator ,: 1. The above named person has satisfactorily co=pleted the required ;

requalification training. . Tcpics Grade Instructor Date

a. Week 1

b. Veek 2

c. Week 3

d. Week 4

e. Week 5

f. Veek 6 . .

g. Week 7 -

h. - Week 8

i. -Week 9 .__

m 4 k a

.q

( ( - Atgchment2 t

                                             .                               NDip. 2.1
 '                                                                           Rev. 0-1/1/81 Page 2 of 3 we                  J. Week 10          .                          -

k. Week 11 .

1. Week 12

m. Other Manager-Nuclear Training /Date

                 -2.      The above named person has satisfactorily passed the annual / biennial requalification examinations.

Year 1 Year 2

                                     .                          Score         Date       Score              Date
                         -a. Written examination 80 SRO                                                   -

l. b. Simulator Examination; c. -Oral Examination / Plant
Walk Through

, Supervisor-Operations Training /Date I' . 3.- The above named person has performed satisfactorily as a licensed [- operator and has completed t.aose reactivity manipulations identified

! in Attachment 3 either in the plant or en the simulator.

j. -

Shif t Supervisor /Date L

                                                                                     .                                           N 4   ~ --

       .             . ..                  q                                   ,

s Att chment 2 ND *.2.1

     .                                                                Rev. 0-1/1/81 Page 3 of 3 we            4. The above na=ed person;&4 has demonstrated technical coc'petence and readiness to perfom licensed duties'(passed the a2nual perfomance evaluatica, and performed satisfactorily during the in plant drill sessions.

Supervisor of Operations /Date l ! 5. The above na ed person has been found physically qualified as defined in 10CFR55.60 to perform licensed operator duties. Plant Administration Supervisor /Date

6. Th'e above named person's records and performance have been reviewed.The person has been found to meet all requirements and is reco= mended for relicensing.

Superintendent of Plant /Date , 7. The' above [ named person is approved for application of renewal of license by the NRC.

                                                              , Vice President-Nuclear Operations /Date

Attachment:

Reactivity Manipulation Checklist. (patt % ..A ubr 4.2.s Annual Performance Evaluation

                                    " In-Plant Drill Evaluations j-                                     Copy Medical Certificate's.

I EC 32:1 t t I ( l GI

      -     a.     . ..                 g                                       (

Att chment 3 - NDI .2.1 Rev. 0 - 1/1/81 Page 1 of 3 Reactivity Manipulation Licensee or Checklist Candidate REACTIVITY MANIPULATION. The following control manipulations and plant evolutions where applicable to the plant design are acceptable for meeting the reactivity manipulations required. The starred items shall be , performed on an annual basis, all other items shall be performed on a two-l year cycle. However, the requalification programs shall contain a commitment that each individual shall perform or participate in a combination of reactivity control manipulations based on the availability of plant equipment and systems. Those control manipulations which are not performed at the plant shall be performed on a simulator. The use of the Technical Specifications should be maximized during the simulator control manipulations. Personnel with Senior licenses are credited with these activities if they direct or evaluate control manipulations as they are performed. These items should be signed off by Shift Supervisor or

Instructor.

Date Performance Item Performed Supervisor / Instructor

               * (1)     , Plant or reactor startups to include a range that reactivity feedback from nuclear heat addition

! is noticeable and heatup rate is j established. (2) Plant shutdown. l * (3) Manual control of feedwater during startup and shutdown.

              * (4)        Any significant ( 107.) power changes in manual rod control or recirculation flow.
              * (5)        Loss of coolant

1. Inside and outside primary containment ,

2. Large and small, including leak-rate determination.

(6) Loss of instrument air. (7) Loss of ' electrical power (and/or

degraded power sources).

Cisl

e t

           .. . ..                     T,.
                                                                           . N.

At*zchment 3 NDI .2.1 Rev. 0 - 1/1/81 Page 2 of 3 w' * (8) Loss of core coolant flow / natural circulation. (9) Loss of condenser vacuum. (10) Loss of service water. * (11) Loss of shutdown cooling. (12) Loss of component cooling system or cooling to an individual component (13) Loss of normal feedwater or nor=al

                       ,  feedwater system failure.
             *(14)        Loss of all feedwater (normal and emergency).

(15) ' Loss of protective system charnel. (16) Mispositioned control rod er rods (or rod drops). (17) Inability to drive control rods. ' (18) Conditions requiring use of standby liquid control system. . (19)- Fuel cladding failure or high activity in reactor coolant or offga,s . (20) Turbine or generator trip (21) Malfunction of automatic control system (s) which affect reactivity. . l l . (22) Malfunction of reactor coolant pressure / control sy' stem.~

  ,           (23)-      Reactor trip.

(24) Main steam line break (inside or outside containment)

    .         (25)       Nuclear instrumentation failure (s)
                                                                         .            (os

o. . . .

( / 1 -l Att hment 3 ND F

                                                                                                                                              .2.1
                                                                                               ,                            Rev. 0 - 1/1/81 Page 3 of 3 t

, ,, Other . . 1 ( l b 1 e f n 4 e t k. 4 A i f. 6 1 S 4 L 1 i

e

[ e d i k 6 4 4 d s 1 l' 4-I I I j, *

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                                   -rWre-y       >p*m.g-s                                                                                                                                                                   N wa$*           9 +                                  s      v ,w-,w,,,ew               - ' -           -   Wy   e-'1- m-*-*e--w-**=**-*79P-+                T- 's         " - " - '"'? $ 9---'-"'r   ' '

( . ( Att chment 4 NDI *.2.1 Rev. 0 - 10/2/80 Page 1 of 1

w e- ~ -

Training Following Absence from Licensed Duties Name of Licensee Period Absent Descripti'on of training to be completed prior to resuming liceas,e duties:

    ,                  Examinations required:            Sco're                   Date i

1 Training Satisfactorily Completed: l Supervisor-Ops Training /Date i j Forward Copy to: Licensee Tra# ang Record

            .                                   .Supervi3cr of Operations EC 32P:1-            .

i t . { I r l-

     ~ ~
         ~

NUCLEAP. DEPARTMENT INSTRUCTION ' I Selection. Training, and Certification of Shift Technical ?OR INFO.lMATION Advisors ON NDI 4.2.2 Rev. 0 9/11/80 Originating Manager Superintendent of Plant Title . Signature Reviewing and Concurring Manager: l Title Signature Title Signature Approved Date 1.0 PURPOSE . This instruction specifies the require =enta ar.d ptwrides the mechanisms for , selection. training, and certification of Shif t Tcchnical Advisors (STA's) at Susquehanna Steas Electric Station. Upon ce=pletion of this described process, candidates shall be leemed competent to perform the duties of a STA as set forth in Reference 3.5. l 2.0 SCOPE This instruction applies to prerent and future STA candiates and incumbents. b

                                                                                                                             -a.
                                                                                     .                                                .GG

.. z- . . - . . . .---

NDI 4.2.2 Revision 0 Page 2 of 11

3.0 REFE"INCES 3.1 NUREG-0737, " Clarification'of TMI Action Plan Requirements", Section I.A.1.1. 3.2 D. B. Vassallo (NRC) letters to Operating License applicants;Septenber 27, 1979, and November 9,1979. t 3.3 NUREG-0578 "TMI-2 Lessons Learned Task Force Report", Recommendation 2.2.1.b. 3.4 Institute of Nuclear Power Operations (INFO) Position Paper " Nuclear Power Plant Shif t Technical Advisor - Recoccendations for Position Description, Qualifications, Education and Training", Revision 0, April 30, 1980. 3.L Plant Administrative Procedure AD-00-101 " Shift Technical Advisors (STA) Duties and Responsibilities". 3.6 SSES Technical Specification, Secti a 6.0 4.0 DEFINITICNS 4.1 Academic Training - Successfullv completed college-level work which could be applied towards a recognized degree in a discipline related to

                      .'the position.

4.2 Experience - Applicable work in design, construction, preoperational and startup testing activities, operation, maintenance or technical services. Observation of others performing these functions shall not be considered acceptable experience. l 4.3 Nuclear Power Plant Experience - Experience acquired in the preoperational and startup testing activities or operation of nuclear power plants. Experience in design, construction, maintenance and instructing may be considered applicable nuclear power plant experience and should be evaluated on a case-by-case basis. S 4 67

NDI 4.2.2 Revision 0 Page 3 of 11 t i 5.0 RESPONSIBILITIES 5.1 Vice President - Nuclear Operations Responsible for certifying to the NRC thtt selected STA's are technically competent, have the requisite comprehension of plant

operations and are cognizant of the primary functica of their position (nuclear safety assessment).

5.2 Superintendent of Plant - Susquehanna Responsible for implementation of the STA program. Imple=entation encompasses selection of properly qualifir.d candidates, development of an appropriate administrative framework, confirmation of STA certification on a two year basis, and utilization of individuals who

                           'are certified in accordance with this instruction to perform STA duties.

5.3 Manager - Nuclear Training Responsible for the scope and content of the STA training program and for documentation of training. 5.4 Supervisor - Operations Training Responsible for deplecentation of the STA training program and the j ,' certification examination process. l l 6.0 INSTRUCTIONS . l 6.1 Selection of the STA candidates by the Superintendent of Plant - Susquehanna shall be accomplished on ao as-needed basis through the

normal PP&L personnel selection process. Since STA is a separate job l classification, the approved job description shall be utilized and all candidates shall meet the minimum qualifications specified below. The selection process should provide in-depth review of personnel l

experience, qualifications and training to facilitate selection of I candidates well suited for the responsibilites of the position. l l- Minimum Qualifications:

1. B.S. or equivalent (per reference 3.2) in Engineering or Related' Sciences.

l 2. 3 years power plant experience of which 1 year experience is l nuclear power plant experience.

        .                            .                                                                tbEl

h3I 4.2.2 Revision 0 Page 4 of 11

6.2 The Manager - Nuclear Training shall perform an initial audit of candidate experience and acacesic training prior to ce=encenent of training. 1.'here departures from the specified criteria are identified, the Manager - Nuclear Training in conjunction with the Superintendent of Plant - Susquehan=a shall provide justification for exe=ption. 6.3

Completion of tte components of the training program shall be documented. Jun tification for exe:ption of any portion of the training program shall be prepared by the Manager - Nuclear _ Training, in conjunction with the Superintendent of Plant.

6.4 The STA Training Program shall consist of: 6.4.1 Susquehanna System Technology - consisting of lectures, tapes, quizzes and exa=ications covering system design bases, flow paths, cocponents, and instr =entation and controls. 6.4.2 Susquehanna Operational Aspects - consisting of si=ulator time, seminars, lectures, tests, and qui::es covering transient analysis, plant startups, power operations, shutdowns, cooldo ns, malfunctions, accidents, and surveillances and Technical Specifications. o.4.3 Problem Solving and Decision Analysis - covering problem identification, alternate solutions, appropriate courses of action.

                . 6.4.4       Administrative Controls - covering station e=ergency and administrative procedures.

6.4.5 Chemistry and Health Physics - addressing corrosion control, metallurgy, sampling, analysis, and monitoring. 6.4.6 Advanced Applied Fundamentals - covering reactor technology and theory, instrumentatio=, thermal hydraulics, and ce=puter utilization. 6.5 STA Certification 6.5.1 Upsn completion of the SA Traini6g Program, the Supervisor

                              - Operations Training shall administer a certification examination to candidates consisting of:

6.5.1.1- A written examination to be passed with a score of 80% or greater. 6.5.1.2 - An oral exa'aination passed satisfactor'.ly.

                         . mp c4

i h3I 4.2.2 Revision 0 Page 5 of 11 1 6.5.1.3 A plant walk through examination, passed satis factorily. 6.5.1.4 A simulator perfo=ance exasination which sust be passed satisfactorily.

                    - 6.5.2      If a candidate is unsuccessful in the certification examination, the Superintendent of plant and the Mau         -

Nuclear Training shall determine appropriate actions 6.6 Upon formal certification, the individual =ay be assigned to an operating shif t performing the STA function. 6.7 Recertification 6.7.1 The STA Recertification Training Program shall consist of classroom, si=ulator, and plant ti=e covering operating procedures, syste=s, plant changes, industry events, transients and salfunctions. 6.7.2 Within two years following their last (re) certification, STA's shall be ad=i.nistered a recertification examination by the Supervisor - Operations Training consisting of as a minimum:

6.7.2.1' A written examination to be passed with a score of 80*. or greater. 6.7.2.2 A simulator perfor=ance examination that must be passed satisfactorily. 6.7.3 Completion of components of the recertification training [ program shall be documented by the Supervisor - Operations l Training. 6.7.4 If a STA is unsuccessful on a recertification exa=ination, the Superintendent of Plant and the Manager - Nuclear Training shall determine appropriate actions. D b

                               .                                                                70

NDI 4.2.2 Revision 0 Page 6 of 11 i I 6.8 Absence i;om STA Duties 6.8.1 If an STA has not actively perfor=ed STA duties for 60 consecutive days or longer and has not been participating.in the recertification program, the Superintendent of Plant shall not assign that person STA duties prior to completion of upgrade training appropriate to ensure cognizance of procedure and facility changes that have occurred. The Supervisor - Operations Training shall administer this training. 6.8.2 If an STA has not actively perfomed STA functions for a six month period or lo:2ger, the STA shall eccplete upgrade training (as detemined by the Manager - Nuclear Training) and successfully c>mplete an STA Recertification Examination (Section 6.7.2). The Supervisor - Operations Training shall administer this training and examination. 7.0 RECORDS The Supervisor Training Services shall maintain: 7.1 The Experience Records, Educational Background Records, STA

                              . Certification Forms, and STA Recertification Training Records and justifications for waivers of experience         'r caucation standards.

I 7.2 Outlines of STA training and retraining courses.

7.3 Records of experience and qualificatiens of instructors for the STA training and recertification training program. [. I

j.

l l

l .

                                             .                                                              Jl

ND1-QA-6.2.lA NUCLEAR DEPARTMENT INSTRUCTION Rev. o 6/1/81 Page 1 of 4 Dissemination of Information E Originating Manager Manager-Nuclear Support ur- Title -- - ~ Signature l ~

                                                                                     ~~               ~~

Reviewing and ' Concurring Managers

                    -Title: -                    Signature                                 Title              Signature
                                                            ~

Mgr. - Nuclear u" %ne _ nf 91,nr grq l Mgr. - Nuclear Licensing l g sesmum Managtr - NQA . = ,% se1 mA. O m . \ be 1 %[ > Manag:r - NPE L !b k $\ W i Managir - Nuclear Fuels l Manag:r - Nuc i a," Tr - l

                                .           r : - :- ..,      r.   . 2  .;.:           . . .  :

I

                                                     ..       :_r::

l

2 ';

2~

Approved - Data' l l V.P. Nuclear Operations l i . . ,. . . . . . . 1.0 Purpose- -Thishk struction provides guidance for the collection

and dir. semination of information from the industry and within the Nuclear Department that would aid personnel in the Nuclear Department in'the perfirmance of theiF normal or emergency duties. It assumes

proper review of--information, prevents duplication of effort and provides timely dissemination in accordance with the subject matter.

2.0 Scope

This instruction pertains to information sources outside the company that provide information on new developments, regulatory guidance, experience at similiar facilities, or. standards development. It also applies to the information sources inside the company that provide information on procedural changes and developments, design changes and Nuclear Department policy. The specific sources of information are delineated in Section 5. Personnel receiving this information should include all Nuclear Department personnel with responsibilities for engineering, operations, training or emergency response. Specific receipients of information are delineated in Section 5.

NDl-QA-6.2.lA Rsv. O 6/1/81 Page 2 of 4 In addition to identifv'.ng the source and receipients of information, this procedure identifies the functional groups responsible for collection and review of the information sources. The mechanics of information dissemination are also described. The instruction applies to all Nuclear Department Sections. 3.0 References 3.1 NUREG 0737; Action Plan Item I.C.5 3.2 NUREG 0660; Action Plan Item I.C.5 3.3 Regulation Guide 1.33 3.4 ANS 3.2 3.5 NUREG 0731; Item II.B.2.d 4.0 Definitions. None 5.0 Responsibilities 5.1 Each manager within the Nuclear Department has the responsibility - to review the items assigned for their applicability to Susquehanna and to summarize the applicable information for dissemination. 5.2.1 Manager-Nuclear Support

1) INPO/NSAC Significant Operating Event Reports (SOER)

2) SIL's

3) TIL's

4) NSAC & EPRI reports

5) Plant incident reports of general interest

6) IERP's

7) SSES LER's 5.2.2 Manager-Nuclear Licensing

1) NUREG's

2) NRC bulletins, circulars, information notices

3) Regulation guides i

4) Changes to the FSAR

5) Changes to Technical Specifications

6) Federal regulations and changes thereto applicable to SSES

7) NRC inspection reports

8) Reportable events other than LER's 5.2.3 Manager-Nuclear Plant Engineering

1) Plant design changes and modifications 2)- ASME code changes and interpretations 73

NDl-QA-6.2.lA Rrv. 0 6/1/81 Page 3 of 4 5.2.4 Manager-Nuclear Fuels

1) Vendor fuel information

2) National Nuclear Energy Software Center information 5.2.5 Manager-Nuclear Quality Assurance

1) Audit Reports 5.2.6 Manager-Nuclear Administration

1) # NDI changes 5.2.7 Superintendent of Plant-Susquehanna

1) Plant Procedures and changes thereto

2) IOM's and changes thereto 6.0 Instructions 6.1 General The manager, or his designated representative, will review the assigned areas listed in section 5. The information will be summarized in a concise report and sent to the Manager-Nuclear Suppo rt. The Nuclear Support Group will compile the information into a departmental report which will be issued bimonthly. If the information is such that a more timely dissemination is in order, the applicable manager will coordinate with the Manager-Nuclear Support to provide specific release instructions.

6.2 Format Report summaries can follow the format of attached form NDI 6.2.lA. or other appropriate format that clearly and concisely presents the information. 6.4 Group Dissemination Individual groups will provide the mechanism for their internal

               -dissemination of the bimonthly report of section 6.1.

7.0 Records 7.1 The bimonthly report is a QA record and will be retained for a period of two years. S. J. Diamond 2/17/81 ' SJD:mb/1-M

                                                                                              'f i

4 ND1-QA-6.2.lA Rev. O 6/1/81 Page 4 of 4 DISSEMINATION OF INFORMATION REF. DATE I. ITEM DESCRIPTION

2. APPLICABILITY TO SES t

NUCLEAR DEPARTMENT FORM'QA'6.2.lA TC

NDI QA 6.2.2 Rev. 1, 2/17/81 NUCLEAR DEPART 1ENT INSTRUCTION Page/of11

                                             .                                        k+   i INDUSTRY EVENTS REVIEW PROGRAM (IERP)

N nager - Nuclear Support Originating Manager Title Signature Reviewing and Concurring Managers Title Signature , Title Signature 'anag7r - NPE upt. cf Plant-SSES w e l I 'anag;r-Nuclear Licensing %A , P / ,( l ([ 'anagsr-NQA

                                   , v t<.     % r Oby jTWR L MN             v p/7

!anag:r-Nuclear Training tanag;r-Nuclear Ad=in. Approved Date V.P. Nuclear Operations 1.0 PURPOSE This procedure describes the process for reviewing relevant industry information and experience. This program meets the intent of References 3.1, 3.2, and 3.3 regarding the use of available industry information and experience. 2.0 SCOPE The emphasis of the industry information evaluation will be on the NSAC/INPO Significant Event Evaluation and Information Network (SEE IN), and GE Service Information Letters / Technical Information Letters. To the extent practicable, other industry information will also be evaluated. Specifically excluded from the scope of this document are NRC Information Notices, Bulletins and directives from NRC (such as "show-cause" orders) specifically directed to Licensing. Dissemination of information will be covered by a separate Nuclear Department Instruction. 7(o

NDI QA 6.2.2 Rev. 1, 2/17/81 Page 2 of 11 The scope of this instruction also includes non-time critical evaluation of internally generated information such as plant incident reports. Time critical evaluation of plant incidents is performed by the plant staff and is beyond the scope of this ins-truction. This instruction primarily applies to Nuclear Department Sections although work groups outside the Department may be asked to parti-cipate in the evaluation cycle.

3.0 REFERENCES

3.1 SSES FSAR, Chapter 14, Section 14.2.8. 3.2 SSES FSAR, Chapter 17, Section 17.2.1.1.4.2. , 3.3 USNRC NUREG 0737. 4.0 DEFINITIONS 4.1- Licensee Event Report (LER) - Reports concerninr " reportable occurrences" as delineated in Reg Guide 1.16 submitted to the NRC by utilities. 4.2 Open' Items Tracking - Automated management tool for following work assignments. 4.3 Service Information Letter (SIL) - A letter from GE to BWR owners whien documents recommended changes in equipment and procedures and conveys information concerning unique operating conditions and experiences. 4.4 Technical Information Letters (TIL) - A document from GE to GE turbine-generator owners to advise owners of recommended changes and modifications in operating or maintenance procedures. I 4.5 SEE IN - An NSAC/INPO system which analyzes LER's with an eye toward procedures, training programs and generic plant safety problems. 4.6 NOTEPAD --A rapid electronic communication system which trans- ! mits industry events and SEE IN reports via a system of porta-ble terminals which access the data from any telephone. l 4.7 NOMIS Nuclear Operations and Maintenance Information Service provided under contract to NUS for rapid response to member

              . utility questions.
                                                                                         't7

NDI QA 6.2.2 Rev. 1, 2/17/81 Page 3 of 11 4.8 EEI Round Table - The Edison Electric Institute system of answering questions posed by utilities. 4.9 PMR - Plant Modification Request, ad=inistrative method for initiating equipment and design changes for the Susquehanna plant. 5.0 RESPONSIBILITIES 5.1 Manager-Nuclear Support (MNS) - Responsible for the overall implementation of the Industry Events Review Progran. In addition, the MNS is responsible for coordinating the NSG and Plant Staff activities for the IERP review cycle. This res-ponsibility is primarily discharged through the Supervisor - Nuclear Operations Support. 5.2 Manager-NFE - Responsible for providing specific expertise for the evaluation and implementation of operating experience items not in the purview of expertise in NSG. 5.3 Superintendent of Plant - Susquehanna - Responsible for the feedback of pertinent external and internal infor=ation to operators and other personnel of the Plant Staff on a timely basis. In addition, the Plant Staff provides the = cans to assure that affected personnel become aware of and understand information of sufficient importance that should not wait for emphasis through routine training prograss. 5.4 Manager - Nuclear Training - Responsible for incorporating pertinent operating experience infor=ation into training and retraining programs.

          ~             '   ~

5.5 Manager - NQA - Provide periodic internal audits to assure that the feedback program functions effectively at all levels and that action items are closed out in a timely fashion. 5.6 Supervisor - Nuclear Operations Support - Responsible for collection of external information (SIL's, TIL's, NSAC/IN?O and other appropriate industry info) and screening them for applicability to the Susquehanna Steam Electric Station. The NSG will review the applicable ite=s and develop plans to resolve any valid concerns at coordinating with NPE, Plant Staff or Nuclear Training as appropriate. In addition, the NSG will assure that plant personnel do not routinely receive extraneous and unimportant information on operating experience in such volume that it would obscure priority information and assure that conflicting or contradictory information is not conveyed to operators and other personnel until resolution is reached.

                                                                                       '723   :

NDI QA 6.2.2 Rav. 1, 2/17/81 Page 4 of 11 6.0 INSTRUCTIONS 6.1 General Discussion All external information with the exception of NRC Bulletins and Circulars (which are screened by Nuclear Licensing) is initially screened by the NSG for potential applicability to Susquehanna. After this initial screening, the NSG evaluator works closely with the Plant Staff (or NPE for design changes) to resolve the issue. External information is prioritized by the NSG to ensure that time critical information is processed first. In addition, the NSG determines the recipients of various categories of information from operating experience (i.e. Plant Staff, NPE, Nuclear Training, etc.). The plant staff disseminates the information they receive from the NSG directly to the opera-tors if time critical in nature and/or by procedural and training changes. Internally generated operating experience and incident reports

are disseminated by the operating organization to the Plant Staff directly. A copy of incident reports generated by the Plant Staff is forwarded to the NSG for trend analysis and evaluation of corrective actica taken. (Form QA 6.2.2D)

          . If screening of operating experience indicates a potential                        .

design change for Susquehanna exists, the item will be resolved via a PMR. The PMR system will provide notification to NPE of the proposed design change and request appropriate support. 6.2 Information Review Cycle 6.2.1 The following information will be periodically reviewed by NSG:

a. NSAC/INPO Significant Event Evaluation & Infor-mation Network (SEE - IN).

b. General Electric Service Information Letters &

Technical Information Letters.

c. Periodically review industry information auch as Atomic Energy Clearing House, EPRI Reports, NSAC Reports and other industry information as applicable.

These items required mandatory IERP documentation. (Enclosure 2)

NDI QA 6.2.2 R:v. 1, 2/17/81 Page 5 of 11 6.2.2 Information reviewed in 6.2.1 will normally be documented using the IERP review log. (Form QA 6.2.2A) . These review logs are kept by the NSG evaluators and turned into the IERP coordinator when completed. 6.2.3 The IERP reviewer will review the document (listed in 6.1.1) for the following:

a. Is it applicable to Susquehanna?

b. Does it wr.rrant additional review?

c. If the item warrants additional review, the IERP Coordinator will assign the item to an evaluator. Form QA 6.2.2B will be used to docu-ment the evaluator findings.

6.2.4 The evaluator will:

a. Coordinate with the Plant Staff to determine if changes should be made to Susquehanna Procedures or equipment (Recommendation Section of Enclosure 2).

b. Enter the item into the Open Items Tracking System (NDI 1.1.3).

c. ~ Document the disposition of the IERP. (i.e.

PMR # forwarded to the Plant Staff. The following action was/will be taken . . ..) 6.2.5 If the Manager-Nuclear Support concurs with the evaluator's analysis of 6.2.4.a, he will sign the recommendation block of Form QA 6.2.23 indicating concurrence with the recommended action. The item is then dispositioned. 6.2.6 After disposition, the evaluator will send the IERP to the Manager-Nuclear Support for concurrence. If he is satisfied with the action taken, the IERP is closed out by the IERP Coordinator (Form QA 6.2.2C). 6.2.7 IERP closecut does not necessarily mean that the item is complete in terms of its implementation. It may require additional in-depth evaluation by the responsible organization or enter another tracking

     -system such as the Plant Modification Request (PMR) system.

So

            *g'                                                            NDI QA 6.2.2 Rev. 1, 2/17/81 Page 6 of 11 6.2.8     The IERP coordinator will periodically obtain a printout of outstanding IERP action items which were entered into the Open Items Tracking System (as part of 6.2.4) for use in determining the effectiveness of the program. This information will be included in the quarterly report of Sectici 7.2.

6.3 Information Systems 6.3.1 General Many sources of information exist to aid the eva-luator in his IERP review. These sources include system descriptions, STAIRS, system technical speci-fications, operators manuals and many others. 6.3.2 NOTEPAD The NOTEPAD system is coordinated for PP&L by the NSG. Other users of the system are NPE, Nuclear Licensing and the Plant Staff. The system can be used to poll other utilities on their approach to specific IERP's or to check the system memory for subject related information. 6.3.3 NOMIS d The NOMIS system polls other ut.lities for their approach to operations and maintenance related activities. Questions for the NOMIS system are coordinated by the Plant Staff. 6.3.4 EEI Questions on Nuclear Issues are also answered as part of the quarterly EEI round table discussions. The response time on this system is slower than for NOTEPAD or NOMIS but the volume of response is generally better. This function is coordinated through the NSG. 7.0 RECORDS 7.1 IERPereviewers will keep a log of all information that they screen whether or not an item of significance is'found. Monthly, these log sheets will be turned into the IERP coordi-nator. E3l

                   +           r w

NDE QA 6.2.2

                          -                                                                                                Rev. 1, 2/17/81 Page 7 of 11 7.2 . Quarterly, the IERP coordinator will turn in to the Manager -

Nuclear Support and '!anager-NSAG a sunusary of IERP ctivities, and applicable evaluator information (i.e. name of evaluator, IERP's found, action taken, etc.).

            ~7.3 .IERP records are stored in accordance with applicable QA instructions and retained for a period of two years.                                      - ~

e.m 35J/cak e v m o e w

NDI QA 6.2.2 Rav. 1, 2/17/81 Page 8 of 11 IERP REVIEW LOG

~~

Reviewer: _ Document /Date IERP # (if app.) Date Reviewed Time Expended I-Nuclear Department Form QA 6.6.2A

l 4 NDI QA 6.2.2 Rev. 1, 2/17/81 Page 9 of 11 INDUSTRY EVENTS REVIEW PROGRAM i i l

               - -    Ites No.                       Date             System                        Ref.

l t . .

1. Item Description (attach article if appropriate):

t .i

2. Evaluator analysis and recommendations:

i ) I i l l l-I Time l Evaluator Date

                                                          'Mgr-Nuclear Support                              Date
                   ' 3. Disposition:

i 5 i l

                                                          -Approved: MNS                                    Date l'                                                          Ites Closed:     IERP Coordinator                Date 9T er- - -                    a    -   -. , , , . ,          , , , -     .                   . ,       n -       m-  - + - - - -

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            .                                                                                                            NDI QA 6.2.2 D Rev. 1, 2/17/81 PLANT INCIDENT EVALUATION FORI                                                                       paa. 11 s i t r.n :tsca:p ::N eN::s __

oCxt we.:

m *Ia no.: (j) rtm? Arta MSS: 5: NIT Art? CONOl* ONAI.* T SIGNIT : ANT MC- $!Od:r:: ANT

                          $1. Two or more failures occur                 C1. A .Lagle f ailure occurs in        N1. A single failure occurs
              .                  in redundant syste.s during                  a non-redundant system.                 in a redundant system.           I I

tse sare event. N2. Men-critical degradatzens i e Does the failure violate _ S2. Two or more fa11 ares due to primary, secondary. or of boundaries oc:.r (pa:n-a common cause occur during contat.*. ment pressure bound. Lag leans, seal lasas. l the same event. ary. tuse lanxe, at=.I. l

                          $3. Three or more failures een:

e Does the f ailure lead to a - N3. Personnel err:rs and pro- i duriaq *.3e same event. an;or plant tran s t ant te.g., cedural deftetenetes are l

34. C aponent faili.:es occur overcooling. loss of heat cet tted *.A at do wt tant would have essaly '# ' EC'A ' * *8 ' I ***"18 I#** ** 2*" **"***,

ziaunderstanding. escaped detection by testing C2. Two apparently unrelated or smastaation. failures occur during the N4. beisate deficiencies 'c ru r SS. An event proceeds in a way same event. (pape hangers, snecere signi'icantly different f:=m o Are the failures common ****I* vnat would be ex7ected. cause or mode? N5. Cseponents operate out cf

                          $6. An event or operating condi-                e Did one f ailure lead to the              jpecfcat
                                                                                                                                    *;s .

at tien occur envel,,ed ,s y ccat is not e ,1 ant design occurren,ce fa11=,e of the other =1 age ==e eas": - bases. C3. A problem results in an off-N6. on-radioingical enviren-

57. Ar. event occurs wnich could ette radiatten release er , m ,3 g3 og g.g ,

have been a greater creat personnel erposure. to plant safety wita differ- e Is the amount of radiatica

th ' # I* M #18I*

a ve t? e r . i e unusually bagn? ,,,,. Ocvngraded ft:{ C:ndi-tionally Sigst..can.. l

                             . occur:ence, or a different                 e tid the release or eroosare progression of occurrences.                  occur under unusual es::.:.3

58. Administrative, precedural or stances?

cperati nal ert:rs are ::3 C4. A design er manufacturing ( matted that resulted'fres a defi: ency is identified as (N) v funda.5 ental misunderstanding of plant perf r=ance or the cause of a failu:e or potential failure. j **fet7 reTairements. e Is the deficiency an ! 39. Ctser (erplain) . 4bvious, describa21e hard-

                                                                             "*  # * # * "I i                          ~

Y. Upgraded f:cm Osaditienally ~~ ~ i Significant. C3. A pechlan resuT s in a long outage or ma3cr equipment damage. e Did the problem cause a unit outage of 10 days or longer? l e Did the probles require re-placement or entansive re-pairs to ma;or equipment (e.g. , steam generator, tur-bine, reactor coolant pu=p, etc.)?

Cs. An Isf actuation occurs during an event, e Did the actuation involve any unusual cir=u= stances?

C7. A part.icular oe:-=:ence is recognized as havtag a signtiicaat recurrence rats, e Is the recurrence rate high-er taan would be erpeeted? e fa the recurrence rate increasing? C5. Ctaar (szplaint . CO.".*.Dr-5 : s v

       ++ +     -                   -      -. ,     a   a.                                           l

  -                                                                                   . I-9.1.1 R      0' 11/12/80 NUCLEAR DEPARTMENT INSTRUCTION                                         Page      of 7 CHARTER - NUCLEAR SAFETY ASSESSFENT GROUP Rev i Drah
                                                                                   -l         )

Originating Manager WAGER-NUCLEAR SAFETY ASSESS'ENT Title SigTat'ur'e' Reviewing and Concurring Managers Title Signature , Title Signature V.P. Nuc.over. ' &l. iv-V.P.-ESC-Nuc. 3 1, 4

             .v.cr.Nuc. Adrin.     [lMf&      .r
                                        ?

f j i k i(h . . C- . v 4 b 7) Approved f x X6Ih , u Date jy, . ,[- me e GeniorVicePresident-Nuclear 1.0 Purcose This instruction describes the Charter of the Nuclear Safety Assessment Grcup (NSAG). 2.0 Scoce

    .      2.1 NSAG is pri=arily responsible for independently evaluating PP5L's nuclear activities with particular e=phasis on assessing the effectiveness and quality of the Cc=pany's nuclear operat,iens and related safety /enviren= ental programs.

Y* 87

i ,

         .                                                                     ,                 \

N.D.I.-9.1.1 Rev. O, 11/12/80 J {"

  -                                                               Page 2 of 7                    l j

2.2 NSAG assessments are not the traditional review / audit evaluations performed by NQA and other independent review groups. They are a means of informing management of how well we are performing our nuclear functions. Thus NSAG assessments are not audits or inspections relative to established minimum standards; but, are conducted aith :.he goal of determining and portraying actual levels of perforcance. 2.3 The results of NSAG assessments will be one factor used by management to help achieve the maximum practical level of performance. 2.4 Although some NSAG assessments may be quantitative in nature, many will be subjective. In order to be effective in this environment, NSAG must int-ract with other Nuclear Department sections in a spirit of cooperation and mutual trust. Therefore,

         '            NSAG's function is not,.ard should not be perceived as, one of finding fault within other organizations or individuals.

3.0 References - 3.1 NUREG-0731, Guidelines for Utility Management Structure and g-g,,

      ).              Technical Resources.

I 3.2' SSES Technical Specifications, Section 6. 3.3 ANSI /ANS 3.1 - December'1979, Qualification and Training of Personnel for' Nuclear Power Plants. .. . 3.4 ANSI /ANS 3.2 - February 1980, Administrative Controls and Quality Assurance for the Operational Phase of Nuclear Power Plants. 3'. 5 NUREG-0737, Clarification of TMI Action Plan Requirements. 4.0 Definitions None 5.0 Responsibilities 5.1 The Manager-NSAG is res onsible for implementing this' instruction.. , 5.1.1 The Manager-NSAG reports to the Senior Vice President-Nuclear. C 4

           ,w                                           -                 -r   - ,

{ R b 1 / 2/80 Page 3 of 7 5.2 The Senior Vice President-Nuclear is responsible for promptly bringing to the Corporate Management Cemittee's attention: 5.2.1 Significant generic industry concerns. 5.2.2 Significant nuel, ear related public concerns. 5.2.3 Significant Susquehanra specific concerns. 5.2.4 NSAG summary assessment reports. 5.3 The Senior Vice President-Nuclear is respcasibl- for assuring closure, through existing procedures, of open items referred to

                      . him by the Manager-NSAG or by other responsible managers when
           .            . such items result from NSAG assessments.

5.3.1 The Manager-NSAG and other. responsible managers are charged to make best efforts to resolve NSAG designated open items before referring such items to upper management. p! , 5.4 Nuclear Department managers, section heads, committee chairman, G etc. are responsible for cooperating with the Manager-NSAG during the performance of activities authorized in this instruction. 6.0 Instructions 6.1 The mission of NSAG is to: 6.1.1 Independently evaluate and report on PP&L's nuclear activities with particular emphasis on assessing the

                                 . effectiveness and quality of PP&L's nuclear operations and related safety / environmental programs.

6.1.2 Provide the on-site Independent Safety Engineering Group (ISEG) function described by the NRC in NUREGs 0731 and 0737. 6.1.3 Foster the adoption and implementation of senior management's commitment to nuclea'r and environmental safety.

                 .       6.1.4       Maintain a high level of awareness of nuclear plant operational and safety concerns at all levels of management.

g,

i s N.D.I.-9.1.1 Rev. 1, 11/12/80 Drai't Page 4 of 7 6.1.5 Provide an additional channel for the consideration of nuclear safety questions arising from within or outside the Company. 6.2 NSAG orga,nization, qualifications; and training: l 6.2.1 The NSAG organization is composed of no less than five dedicated technical personnel, of whom no less than three are assigned to the Susquehanna site. 6.2.2 From time to time the Manager-NSAG may augment his full . time staff with consultants. 6.2.3 NSAG members' qualifications shall be at a level generally comparable to that described in Section 4.2 of ANSI /ANS 3.1 (December, 1979 draft), i.e. a'

         ,                        bachelors degree in Engineering with 2 to 4 years experience in their field or equivalene as described in Section 4.1 of ANSI /ANS 3.1.                                 ,

6.2.4 All NSAG members should have training as described in Section 5.3 ,' of ANSI /ANS 3.1 (December,1979 draft). In addition, all members on site should have training 8 as described in section 5.4. The Manager-NSAG should have training as described in Section 5.3.1 of ANS 3.1. 6.2.5 NSAG members shall, through participation on industry

committees, in meetings, seminars, courses, etc.,

maintain sufficient technical cabpetence and industrial contacts to be cognizant of: 6.2.5.1 Significant operating experience, events or incidents at other nuclear facilities. 6.2.5.2 The development of refined process / analytical techniques of engineering and management. 6.2.5.3. Legitimate industry and NRC concerns. 6.3 Specific NSAG assignments which are the primary responsibility of NSAG's. general office section. include: . . 6.3.1 Development, by the end of the third quarter of each year, of a program for the next calendar year which incorporates anticipated NSAG review /assesment activities including priorities. This program shall be-reviewed and approved by the Senior Vice President - Nuclear.* q--

                                                                       ,   ._   m --_._ m   ___        w

l

N.D.I.-9.1.1 Rev. O, 11/12/80 C. Page 5'of 7 6.3.4 Maintenance of a list of consultants with a broad range of experience who could aid NSAG in an advisory capacity.

;                    6.4 Specific assignments which are the primary responsibility of NSAG's plant section include:     ,
       ,                   6.4.1     Assessment for technical adequacy and clarity of procedures important to the safe operation of the facility.*

6. :i 4 Assessment of plant operations from a safety / environmental perspective.* l i'

6.4.3 Assessment of the effectiveness of the nuclear quality assurance program.*

6.4.4 Assessment of plant performance regarding conformance to safety / environmental regulations.* 6.4.5 Assessment of plant safety requirements.* 0,; ;)

6.4.6 Assessmen't of Susquehanna operating experience in comparison with other nuclear plants of similar design.*

6.4.7 Assessment of plant staff perfo:mance. 6.4.8 Selected portions of. items 6.4.1 through 6.4.6 may be assigned to general office personnel. The Manager-NSAG shall make this decision when, in his sole opinion, l such items may most efficiently and beneficially be performed in the' general office. In making this deterpination the Manager-NSAG shall consider such i factors as proximity to data, proximity to responsible p personnel, available expertise and timeliness. [ 6.5 NSAG responsibilities which may be assigned to the general office j . and/or plant sections include: 6.5.1 Evaluation of employee safety and reliability concerns which remain unresolved after line management action.* i

Denotes mandatory NSAG activities, i.e., those which cannot

(( be deferred or postponed due to.other commitments and priorities. a - - . - _ - . . . .

N.D.I.-9.1.1 Rev. O, 11/12/80 { Page 6 of 7 6.5.2 Assessment of Susquehanna Review Committee performance, minutes, plans and activities. 6.5.3 Assessment of Plant Operations Review Committee performance, minutes, plans and activities. 6.5.4 Ass ssment of other Nuclear Department sections' performance, plans, documentation and activities. l 6.5.5 Independent assessment of Company nuclear factilities, operations and management using sophisticated . analytical tools such as decision analysis theory, failure modes and effects analysis and probabilistic risk assessment. 6.5.6 Review of violations, deviations and reportable events at PP&L facilities, which require reporting to the NRC in writing, such as: 6.5.6.1 Violations of applicable codes, regul-ations, orders, technical specifications, license p requirements, procedures or instructions C which have safety significance. s 6.5,5.2 Significant operating abnormalities or deviations from normal or expected l . performance of plant structures, systems, or components affecting safety. 6.5.6.3 Reportable events, which require notification

to the NRC in writing within 24 hours, as i

defined in the plant technical specifications. 6.6 In addition to the above assignments the Manager-NSAG shall be responsible for independently assessing the facility safety and reliability impact of: l 6.6.1 Key changes in organizational structure or personnel in i , either plant staff or suppe rt activities. 6.6.2 Staffing levels and qualifications associated with plant staff and support activities. 6.7 The Manager-NSAG may direct a review of any other matter impacting the safe and reliable operation of the Company's i nuclear facilities.

Ta

N.D.I.-9.1.1 { Rev. O, 11/12/80 Page 7'of 7 6.8 Open items arising as a result of NSAG activities will be considered open until formally closed (through existing procedures) provided that the Manager-NSAG and other concerned responsible manager (s) concur in the closing disposition, or until formally closed by the Senior Vice President-Nuclear. In addition, any NSAG actions resulting from employee safety concerns will be considered oped itema until said ezployee has been formally notified of the dc.sposition of his concern (providing that he can be easily reached and remains in the employ of the Company). , 7.0 Reports 7.1 Records which cover all formal NSAG activities will be maintained

                                                        ' ,.by the Manager-NSAG or his designee.

7.2 Project reports will be prepared at ,the conclusion of each NSAG evaluation. These reports (prepared after discussion with the responsible manager) will be distributed to the responsible m' a nager (s), the appropriate Vice President and the Senior Vice President-Nuclear.

                                   '                                              ~

7.3 Summary assessment reports, described in 6.3.2, will be addressed to the Senior Vice President-Nuclear and copies will be distributed to all members of PP&L's Corporate Management Committee. 7.4 Any condition which is considered by the Manager-NSAG to be , reportable to the NRC and which is uncovered as a result of NSAG activities shall be reported to the appropriate line managers and to the Manager-NQA. Timing of such reports shall be consistent with applicable regulatory requirements. CJK#154:5 . e 9 73 mi a i is i i e mi e i - ii-s

~ '

PCINSYLVMiIA PC'*ER & LIGHT CCMPM.T SUSQUEHMOTA SES U:i1TS 1 & 2 7 PROCEDURE APPRO7AL FORM [gjQ{ctireDate TITLE: AD-00-026 CONDUCT OF OPERATIONS REVISION g PAGE 1 0F 18 PORC REVII'd REQUIRED: US ( ) NO ( ) Meeting liunber ORIGETATOR: G. L. Adams A\ P APPROVALS: 1 . DATE SUPEREiTECCiT OF FLMiT DATE 1.0 PURPOSE The purpose of this procedure is to establish Operations Section responsibilities and to define the ad=inistrative progran for carrfing out these responsibilities to achieve safe, efficient and consistent plant operation. 2.0 SCOPE This procedure is applicable to Operations Section personnel. The responsibilities addressed are applicable for startup activities, power test phase and operating phase.

3.0 REFERENCES

3.1 FSAR Section 13.0, Conduct of Operations , 3.2 Technical Specifications Section 6.0 [ 3.3 10CF W ooerator Licenses OPS-12, nistrative Control of Plant Operations r-/ f0RM AD-00-001-1, 'Rev. 1 Pase 1 of 1

AD-00-026 Revision 1 Page 2 of 18

             '3.5   AD-00-021, Health Physics Section Organization and Responsibilities 3.6 AD-00-024, Station Security Responsibilities 3.7 Emergency Plan 3.8 ANSI N18.7, Administrative Controls and Quality Assurance for the
 -                  Operational Phase of Nuclear Power Plants 3.9 Regulatory Guide 1.114, Guidance on Being Operator at the Controls of a Nuclear Power Plant 3.10 10CRF50.54, Subsections (i), (j), (k), (1), (m) 3.11 NUREG 0731, Guidelines for Utility Management Structure and Technical Resources 3.12 NUREG 0737, Clarification of TMI Action Plan Requirements 3.13 NUREG 0660, TMI 2 Action Plan.

4.0 RESPONSIBILITIES 4.1 Supervisor of Operations The Supervisor of Operations is responsible for the safe, efficient and reliable operation of the plant and effects these responsibilities by: 4.1.1 Establishing operations policy for the safe, efficient and reliable operation of the plant in accordance with Federal Regulations, applicable Codes and Standards and Quality Assurance requirements.

4.1.2 Supervising the Operations section including

4.1.2.1 Establishing the organizational structure and staffing requirements. 4.1.2.2 Hiring, promoting, salary administration and job performance evaluation. 4.1.2.3 Establishing requirements for and initiating programs to train and retrain operations personnel. l 4.1.3 Formalizing plant operating and personnel administrative policy in approved procedures nr the Operations Instructions Manual as appropriate.

AD-00-026 Revision 1

                                                                                   .             Page 3 of 18 4.1.4     Coordinating operating functions with other plant sections and e empany departments, contractors, consultants and industry representatives.

l N 4.1.5 Ensuring that the Shif t Supervisor is not assigned routine

administrative duties which sight interfere with his primary f rerraa. i b ilities .

l 4.2 Senior Results Engineer i The Senior Results Engineer - Operations is responsible for advising e and assisting the Supervisor of Operations in the direction of the

/,

Operating Section in order to povide for tne safe, efficient and reliable operation of the plant.

v p[#[Lj 1

                          \/   4.3 Day Shift Supervisor FI       h,                         4.3.1     The Day Shift Supervisor is responsible for:

4.3.1.1 Planning and coordinating plant testing and maintenance activities, and Operations work schedules to meet project schedules and achieve efficient manpower utilization. 4.3.1.2 Provides technical direction to the Shift Supervisors to achieve consistency between each of

                                                       ,. the operating shifts.

l

4.3.2 The Day Shift Supervisor assumes the responsibilities of the Supervisor of Operations during his absence.

4.4 Shift Supervisor 4.4.1 The primary responsibility of the Shift Supervisor is the safe, efficient and reliable operation of the plant on a N shift basis. He shall allow no other duties to interfere a with his primary responsibility. He is the senior manage =ent g - representative on site during off normal ~ working hours. He effects these responsibilities by: 4.4.1.1 Supervising and directing Unit Supervision to ensure safe plant operation under normal conditions

            @                                               and to maintain the plant la e safe condition under emergency conditions.

f *

4.4.1.2 Observing 2nd evaluating plant operations to determine that operators are qualified for their jobs, procedures are adequate, and efficient and

                                                 .           safe operating practices are utilized.

6 1

y . AD-00-026 I Revision 1 Page 4 of 18 4.4.1.3 Obtaining permissica from th'e Superintendent of

                    ;                        Plant /On Call Supervisor for the return to power of 8
                            .                either or both units af ter a trip or an unscheduled f                         or unexplained power reduction.

I

                  ;                4.4.1.4   Assuming responsibility for plant security in accordance with AD-00-024 and plant health physics with AD-00-021.

4.4.1.5 In the event that conditions warrant, he implements the Emergency Plan and assumes the responsibilities of the Emergency Director. 4.4.1.6 !faintaining the broadest perspective of operational conditions affecting the safety of the plant as a matter of highest priority at all times. He shall not allow himself to become totally involved in any

single operation during an emergency when multiple g operations are required. y 4.4.1.7 During normal conditions directing plant operations via the Unit Supervisors and observing and evaluating control room and plant operators for safe and efficient operation. During an emergency condition taking direct charge

                                        . . of the plant from the control room, assigning l                                             duties and directing operations as necessary to return to a safe plant condition.

If during an emergency the Shifc Supervisor is required to leave the control room on a temporary basis to evaluate the situation locally, he shall be properly relieved of responsibility for all plant activities ;y a qualified serfor licensed individual. I g 4.4.2 The responsibilities.of the Shift Supervisc. shall be

                  ~~
                     .             reviewed and approved by the Vice President. of Nuclear Operations.

c . Hi . l 5 1

t

 -(l-          .'

AD-00-026

                                                           ,                             Revision 1 Page 5 of 18 4.5 Unit Supervisor l       The Unit Supervisor is responsible for the safe, efficient and reliable operation of his assigned unit on a shift basis and effects these l        responsibilities by:

4.5.1 Supervising and directing his Assistant Unit Supervisor and shift coeple=ent to ensure safe unit operation under normal conditions and to maintain the unit in a safe condition under emergency conditions. 4.5.2 Coordinating all unit activities that could affect system operability in order to ensure that the limiting conditions

                                         'for operation' are met .

4.5.3 Determinin the circumstances and analyzing the cause of a trip or an unscheduled or unexplained unit power reduction. 4.5.4 P1'anning the sequence of operaticas to complete complex or complicated evolutions including the technical direction for returning the unit to power following a trip or an unscheduled or unexplained power reduction. r( 4.5.5 Supervising his shift of personnel regarding administrative _- and personnel matters. E 4.5.6- Approving changes in equipment and system operational status. bh ' 4.6 ,' Assistant Unit Supervisor The Assistant Unit Supervisor is responsible for operation of his assigned unit from the control room on a shift basis and effects these responsibilities by: ( l 4.6.1 Operating or directing the operation of unit equipment and systems as prescribed in approved operating procedures. 4.6.2 Continuously monitoring and assessing all displayed parameters and adj'usting or directing the adjustment of process variables to be within p;escribed safety limits. i 4.6~.3 Responding to system or unit abnormalities in accordance with

                                       ,  plant procedures, Technical Specifications, and NRC Regulations.
                         '4.6.4           Shutting down the reactor or initiating emergency safety systems as appropriate to maintain the reactor in a safe condition.

g6

                                  ,                 ,.,w--

   - lY      .

AD-00-026 Revision 1 Page 6 of 18 4.6.5 Under normal conditions the Assistant Unit Supervisor is l designated as the person in the control room directing the operation of the plant. During this time he shall not leave j l the control room area designated as "At the Controls" unless i properly relieved. I 4.7 Plant Control Operator The Plant Control Operator is responrible for: 4.7 1 Performing operations as directed by Shift Supervision, monitoring control room instrumentation and responding to system or plant abnormalities in accordance with approved plant procedures, technical specifications and NRC regulations. 4.7.2 Directing the activities of Nuclear Plant Operators and Auxiliary System Operators. 4.7.3 Shutting the reactor down when it is determined that the safety of the reactor is in jeopardy or when operating parameters exceed any of the reactor protection system setpoints and automatic shutdown does not occur. 4.7.4 Manually initiating engineered safety features during various transient and :: ident conditions if automatic operation was , not properly initiated. Shutdown of an automatically ! . initiated engineered safety feature shall be performed only

                    .              if continued operation will result in unsafe plant conditions and collaboration to this has been received from the Shift Supervisor.

4.7.5 Performing the functions as the System Operating representative in accordance with AD-00-030, Protective Permit and Tag System. l l 4.8 Nuclear Plant Operators and Auxiliary System Operators. l Nuclear Plant Operators and' Auxiliary System Operators receive operational direction from the Assistant Unit Supervisor either directly or through the Plant Control Operator and are responsible for operating assigned equipment and systems in a competent and safe manner in accordance with approved procedures. 4.9 All Operations Section personnel shall respond conservatively to instrument indications unless they are proved to be incorrect. Operational decisions should not be made based solely on a single plant s parameter indication when one or more confirmatory indications are i available. wM

'si

~ .

AD-00-026 Revision 1

                 .                                                                       Page 7 of 18 1

i NOTE: Throughout this procedure, the term Shift Supervision is used to denote either the Shif t Supervisor or the Unit Supervisor. j 5.0 PROCEDURE 5.1 Shift Manning 5.1.1 Shift Complament 5.1.1.1 The shift shall be manned with a complement sufficient to meet the minimum requirements of the Technic'.1 Specification Section 6.0, Table 6.2.2.1. 5.1.1.2 Additional operators are defined as " extra", for substitution purposes and may work any job normally assigned to the job title or any other jobs assigned to the job title below their own in the progression line The Day Shift Supt "sor reviews and approves the weekly work schedul o ensure an adequate number of people have been eduled to support all planned activites. . ges to the schedule will normally be made by th 'ay Shift Supervisor or in his absence the on-daty 5.t Supervisor.

'~

The Unit Supervisor ensures dequate numbers of

qualified personnel are assig '<d to perform scheduled evolutions. 5.1.1.3 The Operator's Instructions Mann. lists the minimum requirements for shift man _ r- including those to meet the Technical Specification requirements. 5.1.2 "At The Controls" Designation "At the Controls" is that area in front of the front panels

 -- ">                              as shown in Attachment "A".4 5.1.3     Shift Turnover                          -

t Operations personnel shall remain on shift with full responsibilities of their position until properly relieved. C1f They are considered to be properly relieved when a qualified relief has assumed the position. 'At ehist relief the U _ e " oncoming shift shall achieve a derstanding of s_ . plant conditions during the re ._f i_. rmation exchange. The

        ?'
     .                            .                                                                    (c>i) em

4) I .

AD-00-026 Revision 1 Page 8 of 18 information exchange requirements for shift relief are detailed in the Operations Instruction Manual. 5.1.4 Overtime Overtime Hours

        @                                 The rules governing the selection of personnel to work overtime comply with IE #80-02 and the substitution / overtime policy agreed to between Station Management and the C                                 Bargaining Unit. These rules are described in the Operations Instruction Manual and are designed to ensure that personnel or plant safety are not jeopardized due to operator fatigue.

5.2 Formal Directions 5.2.1 Operations Instructions / Temporary Instructions 5.2.1.1 Operations Instructions / Temporary Instructions are instructions issued by the Supervisor of Operations to guide Operations Personnel in the performance of activities. They are developed and issued as deemed necessary by the Supervisor of Operations and shall not replace or contradict approved plant procedures. 5.2.1.2. All Instructions shall contain the following sections:

1.0 Purpose

A brief and concise statement of the need for the inst:uction.

2.0 Respensibility

A statement of the instruction responsibilities of personnel who work directly or interface with the instruction. 3.0

References:

A list of those major documents which serve as sources of information or requirements for preparing or performing the

                                        .                                  instruction.

4.0 Prr.,cedure: A logical numbered step by step sequence of actions that should be performed to fulfill the purpose. LO\ [

AD-00-026 Revision 1 Page 9 of 18 1 1

5.0 Records

A statement defining the control of records generated as a result of implementing the instruction. 5.2.1.3 Form AD-00-026-1, Attachment "B", shall be completed as the first page of all testructions. 5.2.1.4 The Supervisor of Operations or designated alternate shall approve operations Instructions an d Temporary Instructions and maintain an index for

      ,                                      each category listing current Instructions in effect. These Instructions and the current indeses shall be maintained in the main control room for each unit.

5.2.2 Operations Procedures 5.2.2.1 Operating procedures furnish written instructions which provide the significant advantage of in-depth pre-analysis and pre planning. Even though operating procedures cover a broad and comprehensive rcnge of anticipated events, it is impossible to address every possible plant condition that could exist. In the event of an emergency or other plant condition not covered by

                                     . . . an approved procedure, operations personnel, through the direction of shift supervision, shall take action so as to minimize personnel injury and lamage to the facility and to protect health and
                                            . safety.

5.2.2.2 Operating procedure categories are written with different intents as far as procedural adherence. l The following provides direction and guidance ! concerning the implementation of cperating ! procedures. 5.2.2.2.1 Alarm Response Procedures - These procedures address actions that may be frequently repeated and therefore should be familiar to'the operator such that the procedure is not required to be directly referred to. The procedure should be referred to directly when the operator is

                                                . -             unfamiliar with the action to be taken or as a check on the action which was taken.

[. {()5L

AD-00-026 Revision 1 Page 10 of 18 t 5.2.2.2.2 Emergency Operating Procedures - The operator shall ce=mit the I==ediate Operator Actions to =emory. These procedures shall be referred to directly as soon as practical7 to i_T - " k correct actions.f It is reasonable to expect that operating personnel are familiar with Emergency Operating rocedures to the extent that they can

                                #                          place the affected system into service f[-                   y vithout reference o e nc a rr +jtog e rocedu,re.

n. -

                                                                                                       /
                                                                                                                 /

_ cfo 7,uc ha f 5.2.2.2.3GeneralOWrafingProc6dures-due'tothe complexity and inf - " nt use of these g( procedures, they shall e referred to while being imple_ d.

5 .2.2.2.4 1 Procedures - These procedures 6k hall, e referred to as soon as practical lement or check correct actions. It is reasonable to expect that operating personnel are familiar with Off-Normal procedure actions to the extent that they can be carried out without reference to the procedure.

Qh 5.2.2.2.5 Operating Procedures and Radv Np g > Egdk Procedures - These procedure M_ be

                                           -7 referred to while being implemessed -
                                                        ~excepc wnen short routine procedure actions that are frequently repeated are
                                            ,             implemented.

l 5.2.2.2.6 Surveillance Operating Procedures - These procedures shall be referred to directly, l t and followed step-by-step. Verification of completion of the procedure shall be indicated by completion of the procedure data sheet. e

  -(4~ ,       .'

AD-00-026 Revision 1 Page 11 of 18 5.2.2.2.7 Check Off List (COLs) - COLs shall be completed to docu=ent a co=ponent lineup for the purpose stated on the COL. Components lined up in an alternate l position are identified on the Deviation List for that COL, form AD-00-026-2, Attachnent "C". Instructions for running the component line up and Maintaining the Deviation List are contained in the Operation Instruction Manual. 5.2.3 Night Orders Book A Night Orders Book is maintained in the Shif t Supervisor's Office and is used by the Supervisor of Operations or Day Shift Supervis'or to provide written information of a short-

                     -                   teon nature to Shift Supervision. The book consists of a multiple sheet record in a hardbound book. Entries may include, but are not limited to, daily schedule matters, short term operational plans, precautions of a short term or special nature, special observation requirements or test.

Each day's entry is signed and dated by the Supervisor of Operations or Day Shif t Supervisor. Shift Supervision is required to read the entries =ade subsequent to their last review of the Night Order Book. They then initial after the entry signifying that they have read and understand the orders.

5.2.4 Review of Operations l

l 5.2.4.1- Review of Operations Meeting 5.2.4.1.1 When plant operations result in personnel injury, Unit shutdown or power reduction, l damage to plant equipment or as deemed necessary by the Supervisor of Operations an operations evaluation shall be conducted. Participants in the i evaluation shall include the individual primarily involved in the operation and that individuals line supervision to the Supervisor of Operations. In addition, I if contributing factors to the operation l involved the responsibility of other plant supervision they shall input into the evaluation.

lo9 L-

AD-00-026 Revision 1 Page 12 of 18 l I , 5.2.4.1.2 The evaluation shall address the operation perfor=ed, procedures governing

                                                                                                      .           thi operation, causes and reasons, conclusion, and reco=cendatics for prevention of further such occurances.

5.2.4.2 Review of Operations Report

                                                                 ,                                A report shall be written addressing as a mininum the following areas which shall also be subsection titles for the report:

5.2.4.2.1 Participants in the evaluation 5.2.4.2.2 Names and titles of persons involved 5.2.4.2.3 Experience and perfornance of individuals involved 5.2.4.2.4 Effects on eperation and service 5.2.4.2.5 Description of operation 5.2.4.2.6 Causes/ reasons 5.2.4.2.7 Conclusion 5.2.4.2.8 Recommendation for prevention 5.3 Operator Routine

5.3.1 Operator Rounds, Operators shall make rounds through assigned areas to check equipment, make general visual inspections, take log readings, wipe up oily or wet equipment and report l detrimental piant conditions to Shift Supervision. Operations Instructions detail the require =dats for making rounds. 5.3.2 Preventative Maintenance (P/M's) P/M's which are approved by the Supervisor of Operations, implement manufacturer's recommendations and PP&L P/M experience data, are scheduled on a periodic basis and performed by shift operators. The Operations Instructions ~ Manual provides instructions concerning P/M performance.

                                                                                                                                            .               LM em                                                                                 e

AD-00-026 Revision 1

                                                                            -                 Page 13 of 18 5.3.3                Logs 5.3.3.1     A vital portion of the shift records are the narrative log notations of plant conditions, operations, and events. The following logs shall be maintained on a shift basis to recoro events in chronological order:

5.3.3.1.1 Unit I Log 5.3.3.1.2 Unit II' Log 5.3.3.1.3 Radwaste Log 5.3.3.1.4 Shift Supervisor Log 5.3.3.1.5 NPO and ASO Logs Required Log entries, administrative controls,

                                                     , reviews and approvals are specified in the Operation Instruction Manual.

5.3.3.2 Equipment Logs will be kept on designated systems in accordance with the Operations Instruction Manual. 5.3.3.3 Computer generated logs consisting of periodic and accident logs are kept in accordance with the

                   ,                                  ,0perations Instruction Manual.

5.4 Administrative Controls of Equ;pment, Systems and Areas 5.4.1 System Status l It is important that operating personnel be aware of system l status at all times'and be consistent in their method for determining system status. Determining syster status shall be in accordance with the Operations Instruct. ion Manual, t 5.4.2 Control Room Access, t j' During normal plant conditions, the Senior Licensed Control Room Operator is responsible for controlling access to the control room. Access shall be limited to those individuals having a legitimate reason for being in the control room. 17". The identified area directly in _ front of the control panels, (/ chocolate brown carpet, shall not be used to conduct business that can be conducted elsewhere. In all cases, permission to d n enter this area must be received from the control room 1 k()(v i

                                          - - ..           _     . .       ~.- - -       L -    -

AD-00-026 Revision 1 Page 14 of 18 1 1 operator. During other than normal conditions, access shall be controlled by the Shift Supervisor, in his absence, the designated Unit Supervisor os other designated SRO individual. 5.4.3 Housekeeping The plant shall be naintained in a clean and orderly condition in the interest of safe and efficient operations. Shift Supervision is responsible for seeing that the plant is maintained in this condition as described-in the Operation Instruction Manual. 5.5 Training Personnel are assigned duties based on their qualifications and training. A current training / qualification matrix will be available to shift supervision to ensure that operators are qualified to perform the tasks assigned. 5.6 Notification / Permission 5.5.1 . Notification of Plant Management The Superintendent of Plant will assign an On Call Supervisor to be en call during back shifts, weekends and holidays. This individual is available to advise and consult with operating personnel and will make notifications to higher

                .                   management and outside organizations including the NRC.
                  .i.6.2            The following situations require prompt verbal notification to the On Call Supervisor:

5.6.2.1 Reactor Scram ( l 5.6.2.2 Inadvertant liquid or gaseous radioactivity release 5.6.2.3 Major equipment failure or malfunction 5.6.2.4 Unexplained reactivity changes or loss of shutdown margin . 5.6.2.5 Ioss of off-site power 5.6.2.6 Employee injury requiring outside medical care o'r radi.1 tion overexposure 5.6.2.7 Accidents occurring on plant property lo,

                            . usum                               e

AD-00-026 Revision 1 Page 15 of 18 l 5.6.2.8 Implementation of Technical Specification "LCO's. 5.6.2.9 Events requiring immediate or 24 heur notification to the NRC - 6.0 RECORDS 6.1 0perations records are comprised of: 6.1.1 Narratire logs 6.1.2 Equipment logs 6.1.3 operations Instructions 6.1.4 Temporary Instructions 6.1.5 Checkoff lists i 6.1. 6' Recorder charts 6.1.7 Generated Logs - 6.1.8 Records generated as a result of Operations Instructions or Temporary Instructions are identified in Records sections of the associated instruction. 6.2 Other than recorder charts which are sent to the Technical Section the

                 , above records are sent to DCC after they are no longer required by operations for Lunediate reference.

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J.. . ATTACID'.F.!;T ** jr' j . .. 1- AD-00-026 Revision i Page 16 of 18

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AD-00-026' ~ Revision 1 Page 17 of 18

                                                                       -ATTACHXD.T " 3' INSTRUCTION A* PROVAL TORM i

l l OPERATIONS INSTRUCTION . Effective Date i [ l l TEMPORART INSTRUCTION 1 ' Revision Number Instruction Number p.g. g og Instruction Title I Prepared by Approved by p g. Supervisor of Operations . 4 e . . 4

           . .. ./
                                                                                                                                                ~

l \ . : l I - :. l . !_ i :-_ . l ' l l _ _ _ Ftra AD-00-026-1, Rev. 1 Pcge 1 of 1 _ _ {g e4. r-t

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   ..       .,                                                                                                                          AD-OO-026 i                                                                                                                                    Revisien 1
                     .                                                                                                                 -Page 18 of 18
          .                                                                ATTACEEhi 'C "

DEVIATION LIST Devia' tion List For COL l CCL Approved Data f Component Alternate Position Returned To Normal Position a Date Ti=s Ti=e Initials Position Initials lDate , l l Form AD-OO-026-2, R h.=1 Page 1 of 1 _ . h({

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PENNsy:.VA IA PCw.R & T - .?An b 'T - j v# SUSquz? ,::':A SEs U: * . -

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S :0;1N AT10N 0N Y P20Cw=E A,r- e Pn - 7:0.1

                       . FUNCTIONAL UNIT 'PROCfDURE Effective Date

. TITLE: AD-00-101 REVISIO:' O-SHIFT TECHNICAL ADVISORS (STAS) PAGE 1 OF 3 DUTIES A';D RESPONSI3II.ITES PORC REVIE's REQUIPJtD: YES ( ) 50 ( ) Meeting :iumber ORIGINATOR: P. E. Taylor APPROVALS: SECTION liEAD DATE SUPERISTE :OEST OF PL.GT DATE 1.0 PURPOSE

        .     - To define the duties and responsiblities cf the Shif t Technical Advisors.

2.0 SCOPE - This procedure is applicable to all personnel perfor=ing the functions of Shife Technical Advisors.

3.0 REFERENCES

3.1 NUREd-0737 " Clarification of TMI Action Plan Requirements", section I.A.1.1 - 3.2 D. B. Vassallo (NRC) letters to Operating License candidates September 27, 1979, and November 9. 1979.

. T03.'t AD-UU-0U1-2, Rev. 1 ~ ((1

 -Page 1 of 1

4l./ . AD-00-101 Revision 0 Page 2 of 5 3.3 NUREG-0578 "T.fI-2 Lessons Learned Task Force Report", Reco=cendation 2.2.1.b. i 3.4 . Institute of Nuclear Power Operations (INPO) Position Paper " Nuclear Power Plant Shif t Technical Advisor - Rece=cendations for Positica

                       ,              Description, Qualifications, Education and Training", Revision 0, April 30, 1980.

4.0 RESPONSI3IIITIES 4.'1 The Technical Supervisor is responsible to S.:perintendent of Plant for: o Overall a<%inistration :f the STA program. o Ensuring that the p'rogram is in ec.pliance with regulatory requirements.

o Verifying that the Shift. Technical Advisors have and maintain the necessary qualification and training. 4.2 The Lead Shif t Technical Advisor is responsible to the Technical

                                     . Supervisor for:.

o Supervising and directing the day-to-day activities of the Shift Technical Advisors. o Coordinating-and reviewing STA work assignments. o Assisting in the performanc-c. of STA duties. 4.3 The Shift Technical Advisors: o During major transient.s and accidents STAS are responsible for providing the shift supervisor with an analysis and assessment of . - overall plant status and critical plant para =eters. o During normal plant operations STAS provide technical review and acalysis of plant operations frem a nuclear safety viewpoint, including assisting Shift.".anagement in the interpretation of Technical Specifications. They also perform other engineering duties as assigned.

                     .                  o'   During the Startup Test Program the STAS are responsible for directing the implementation of startup tests by- serving as test directors.

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erJ ' . AD-00-101 Revision 0 Page 3 of 5

    .-      5.0 INTERFACIS The Shift Technical Advisor is assi jed to operating shif ts to supplement the shift with engineering expertf ee. To that end, he shall serve in an
                    ' advisory capacity to the Shift Supervisor and never assu=e a co= mand or
                    ; control function. He shall always be able to report to the control room within 10 minutes during his shift.

While on shift he shall report directly to the Shift Supervisor when providing a transient and accident assess =ent function. For ad=inistrative purposes and normal work assignment he will be under the supervision of the Lead Shift Technical Advisor. When serving as a Startup Test Director he will receive direction from-the Startup Group Supervisor. , 6.0 PROCEDURE , 6.1~ Shift Technical Advisor duties during a transient or accident. 6.1.1 Compare existing critical parameters and system status with those predicted in the FSAR, to ascertain whether the plant is responding to the incidcat as predicted. Report an assessme.rt of any abnor=alities along with any appropriate recommendations to the Shift Supervisor. 6.1.2 Qualitatively assess plant parameters during and following an accident in order to ascertain whether core damage has occurred. 6.1.3 . Be observant of critical plant parameters, ascertain that there is adequate core cooling including availability of a heat sink for decressurization and cooldown of the pri=ary system. In the sent that critical parameters become l- unavailable due to instrument failure, perform calculations or through other means dete=nine approximate values for the parameters in question. 6.1.4 After a transient resulting in a turbine trip or scram, review the post trip and sequence of events logs _to determine

                                         . the cause of the transient, and to ensure that plant systems performed -in accordance with design specifications.

_6.2 Shift Technical Advisor Duties During Normal Operation Assist the Shift' Supervisor in interpreting and applying the

                  ~
                            - 6.'2.1 requirements of Technical Specifications.

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AD-00-101 Revision 0 Page 4 of 5 I 6.2.2 Investigate the causes of abnormal or unusual events occurring on assigned shifts and assess any adverse effects. Recommend changes to procedures or systems, as necessary, to prevent recurrences, and prepare any required reports including License Events Reports if applicable. 6.2.3 Evaluate industry experience obtained through means such as the Industry Events Review Program, License Events Reports, and Vendor Information. Based on the evaluation, reco==end changes to system, procedures and the training program. 6.2.4 Feedback pertinent operating experience information to operators and other station personnel and transmit information to the Nuclear Training Group for incorporation in appropriate training programs. 6.2.5 Review completed surveillance test results to assure that they meet the acceptance criteria. 0 a outi e b is, eview nd ev uste ant era

ng frff26 r edur f ad uacy, emplia ce w' the ate -

r ula ry equ' ements and ov rall .fect en . f niti ny pli able change . ,,,p ,y,, , p# re b,w,c efp7 6.2.7 Performengineeringevaluationsseeb-e{ec4 + _ thmenosaw of plant l$,,g,94 L operating procedures for Technical adequacy and ce=pliance with regulatory requirements. Initiate any applicable changes,

                    " 6.2.8        Develop and/or review special test procedures including the review of test results.

6.2.9 Summarize and discuss, at shift briefings, plant transients and other operating experience information. 6.3 Shift Technical Advisor Duties when serving as Startup Test Director: 6.3.1 Briefing and last minute coordination of test personnel. 6.3.2 Reviewing the startup test prior to performance. 6.3.3 Ensuring that the startup test is performed in accordance with the procedure. 6.3.4 Performing initial review of the test data. - G e&

                                                                  + , -

AD-00-101 Revision 0 Page 5 of 5 t 7.0 RECORDS Not Applicable O 9 e

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     .  . TITLii                          AD-00-103                                                          -

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 -                                        SELECTION PROCESS FOR OPERA                  *5            :i:ir.t       PAGE 1 0F           5 PORC RE': I. REQUI?J.3: YES ( ) ::0 ( )                                \, U
                                                                                                         ,     Meeting :;t::bar ORIGI::ATOR:                C. L. Adams t

APPROVALS: , SECTIO:s lif.AD

                                                                  ..                                                           DATE SUPERl:;III:Oi:;! 0F PL.C;T                                                       DATE 1.0 PURPOSE The purpose is to define the process by which a person, who is assigned to the Operations Section, is selected for pro =otion or selection from outside the.section to fill.any vacancies.

2.0 SC5PE

                        . ' This procedure applies to position assigped to rotating shifts in theJ Opera       as Section g he. yond             4hc sentraf ccnjlemen$ refar %

o ar ey L{s I r 2. , 3.0 REFERENCE , 3.1 AD-00-026, Conduct of Operations 3.2 NUREG 0660 - VfI Action Plans

                                   -                                                                                                                 ~

3.3 NDI 4.2.1, Licensed Operator 1 raining Program

       . TC.E AD-00-C'J1-1 Nov. I                                                                                                            kC Page 1 of 1                    ._                                                                       ~                  .

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                                                                                                    )

_ _ . ..- . 2. .. --.. . . . . '. u AD-00-103

Revision 0 Page 2 of 5 4.0 RESPONSIBILITIES 4.1 Supervisor of Operations is responsible for the implementation of this procedure. 4.2 Superintendent of Plant shall approve waivers to any require =ents specified in this procedure. 5.0 PROCEDURE 5.1 All candidates being considered for new job assignments shall meet the minimum requirements specified in Attach =ent A of this procedure or have a waiver approved by the Superintendent of Plant in his training record. 5.2 All candidates being considered for new job assign =ents shall have satisfactorily completed the selection process specified in Attach =ent B of this procedure and this completion documented in their personnel / training file. 5.3 Successful candidates for new positions are considered on probation for the first 6 month period following their prometion or placement in this position. At the end of their period, a performance review will be completed by their immediate supervisor. A satisfactory review is required to remain in the position. 6.0 RECORDS No records generated in this procedure. u8

Revision @ rigs 3 et 5 1 ATTACllMNT A Position /Sequirement Matriu gducation Emperience (Years)

FFht. Feelttoc keholar Total Training /CertIficatian Pwr Pit. Nuclear rouer sao Trainina pequiremente Comment e Cl settication . Dearco Superyteore ,

ll Shift Supervisor X suet (- . j 2 - including X Training of Personnel to A Shift Technical Advison i. .

 !                                    Inst ruc t                                                                        be licenasal by the NRC          punt be present if educa.         L.

opecific - 6 weeks above 203 tional requiremente are not met. { (see co w . I

                                                                                    - Startup to 20%                    ceneral Employes Training
                                                                                    - Startup prepe .

folloutng a refueltag ,, i.

                                                                                    - 1 year as a                                            .

licensed oper-star. k [' 3 2 - Including X Trainics of Personnet to 60 hours of technical coursee l tinit Sefervisor be licensed by the NRC in specified aream are - and !

                                                                                    - 6 weeks above 203                                                  required.

Anstatsant tinit i Superiteora

                                                                                    - 1 year as a                        Ceneral Employee Training       A Stilft Tectanical Advient        ,

licensed oper- must be present if educa-ator. Ret raining of Pre nonuel t sunal requiremente are licensed by flut HitC not met.

                                                                                    - 3 mantlie senigned to ehlft in train 4               Eacle candidate enmt be                                           '

certified by rurgmrate Q ing for a euper-visory position agement to be fully comsetent. N C"3 J, _c:2 SfidFE Ig$ M M t 2- ., Y . e

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AD-00-103 Revision 0 f Page 5 of 5

             !                                    ATTAC M NT B                          ;

Selection Process Position Requirements - All. - 1. Nuclear physical exam corresponsding to Code of Federal Regulation Section 55.11 and 55.60.

2. Psychological exam for nuclear operators NPO 1. Completion of academic testing and ASO 2. Interview with the Supervisor of Operations or a supervisor designated by him.

PCO 1. Completion of academic testing

2. Interview with the Supervisor of Operations and one or more plant managers.

d l Unit' or 1. Interview with the Supervisor of Operations 1 Asst Unit and one or more plant managers. ! Supervisor l Shift 1. In*erview with the Supervisor of Operations Supervisor and one or more plant managers.

2. Interview with the Vice President - Nuclear Operatio.ns.

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PEZSTI.VANIA PC".ER $ L*CHT CC!?ANY .

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PRou T .E AP? M*.*AL ?C*.3'. U j ,y ,g , Effective Cate TITI.E: EC-00-C21 REVISION O LP CC!CRCI. PAGE 10? !. PCRC RE" r %tRD: Y2S ( ) ND ( )

                                                                                          .%eeting 3;::er CRIGI:*.ATCR .                  P. I. Tayler                          -

P A . SEC CN ' ' \' DATE A T.T.!CI;CI'C C7 Pl.AST , DA.;

1. IN*RiCONDITICNS ,

j The entry cc ditices for'this precedure any of the folleving: ,

a. R?7 vater le,*al,.less than +13".

b. "Dryvell pressure greater than 1.69 psig. .

l ' . c. An isolatics conditic: exists which requires _or initiates reac:cr scra l (Group I, II, VI, VII isolaticus).

2. O? IRA *CR AC~ICNS .,

1 - CACTION SOT!?! SEIFT S' ?IR7150R ~0 CIJLSSI?Y TEI E7E'" A2D INI""LCE ,"_MENCY i PI.Ali IIC'LDwiiiSG FRCCDURES II A??RC?RIA~E. ,,

  .                                   2. a t  CONFI?Ji initirtion of a reac:cr scra= and PERTC?21 IO-00-001, Reac': cr Scra=, cc: currently .rith this precedure.
                                  . 2.b. CCNFID! initiatics of syste= isola:1cus ec=sisten: -ith FCE't A>CO-C31-1, Rev. 1 plant para eters.

Page' 1 of 1

                                                                                                                            ]M
                                                                                                      .                           : ._ ~

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EO-00-021 Revision 0 1 Page 2 of 4 [ 2.c. CONFIM automatic initiation of ECCS systems ag SBGT system consistent with plant pararecers. 2.d. CONFIM diesel generators start consistent with ' plant parameters. i 4 4 L 'I e 0 1 2 9 e h

                                    ~ . ~ . .

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EO-00-021 Revision 0 Page 3 of 4 CAUTION AVOID RPV HIGH WATER LEVEL TRIP (+54") 0F W PEMFS, RCIC, AND HPCI. ( 2.e. RESTORE and MAINTAIN RPV water level between

                              +13" and 3 4" with one or more of the following systems:

1.) Condensate /Feedwater per OP-44-001 - 1076 to O psig 2.) CRD per OP-55-001 - 1076 to O psig.

1. INCREASE flowrate to maximum, OPERATE two pumps if possible.

3.) RCIC per OP-50-001 - 1076 to 60 psig (600 gpm) 4.) HPCI per OP-52-001 - 1076 to 110 psig (5000 gpm) 5.) CS Loops A and B per OP-51-001 - 455 to o psig. (0 - 6350 gps / loop) 6.) LPCI Loops A and B per OP-49-001 - 455 to 0 psig. (0 - 21,300 gps / loop) 2.f. If RPV water level can be restored and [ maintained above +13". l l AND i it is determined that an emergency l does not exist Then E.V IER appropriate GO as determined by the Shift Supervisor, l 2.g. Il RPV water level cannot be maintained above +13" ( Then MAINTAIN RPV water level above 0" on

Fuel Zone Indicator M

9 EO-00-021 Revision 0 Page 4 of 4 2.h. If RPV water level cannot be maintained above 0" on Fuel Zone Indicator. Then ENTER EO-00-024 Level Restoration 2.1. If SRV's are cycling Then Manually open one SRV and reduce RPV pressure to below 926 psig. AND Start RCIC to minimize SRV cycling. 2.j. When RPV water level has stabilized Then ENTER E0-00-022, Cooldown.

3. DISCUSSION l

L This procedure provides the direction necessary to restore and stabilize RPV water level. l

4. REFERENCES 1

a. EO-00-001 Reactor Scram j b. EO-00-022 Cooldown

c. EO-00-024 Level Restoration

d. OP-44-001 Condensate and Feedwater System

e. 'OP-49-001 RER System j f. OP-50-001 Reactor Core Isolation Cooling System i

g. OP-51-001 Core Spray System

               ,. OP-52-001 Righ Pressure Coolant Injection System i

1. OP-55-001 Control Rod Drive Hydraulic System l

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PCC SYLVANIA PCF.3.1 5 L!CIC CC:"?.nY . t SUSQC:~3.A:0 A SES C 1!$ 1 J. 2 =

                 .                                                                            .       n         -    I, PROCEO7.E APP M.*?.L 70S*
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Iffective Da:e IITLE: EO-00-022 REVISION 0 C00LD0k'N PACE 1 07 4 PCRC REVII'* RIQUIRED: YES ( ) 50 ( ) Seeting :;cnner ORICE ATOR: P. E. Taylor - APPROVALS: DATE SECTIC"9'- . n pl.u:;TE::DE:: CI ?!.X.T . DATE

1. EITP,Y 'CO'CITIONS ~ .

This procedure is entered fre= EO-00-021, Level' Control, after the RPV vater level has been stabili:e'd'. . .

2. OPERATOR AC* IONS _.. .. ,

CAUTION . l

                   -    . DO MJT SECURE OR PLACE AN ECCS IN MANUAL IF.0DE UNLESS, 3T AT LEAST Ta'0 INDEPENDENT DOI ('AITONS, (1) MISOPERATION IN ALIOMATIC IS CONTIMIED, OR (2)

ADEQUATE. CORE COOLING IS ASSURED. 17 AN EC'.'. IS PLACID IN MANUAL, IT k'ILL NOT INITIAIE JETOMATICALLY. MAKE FREQL'e'T .*EECKS OF TEZ INITIATING OR CONIROLLU;G PAhAMETER. .km MANUAL OPERA 10N IS NO LONGER REQUIRED, RESTORE THE SYSTri TO ACTOMATIC/ STAND 3Y MODE IT POSSIBLE. 2.a. I,f_ Eigh dryvell pressure (1.69 psig) is present while depressurising the RPV and RPV level can

be maintaihed above +13 inches using the high pressure syste=s ,, Then PRE 7EC injection from the CS and LPC . systems prior to reaching the RPY pressure at which they

                                                      ' will inject. L' hen the high dryvell*

pressure condition clears, RESIOPI

                                                .         CS and LPCI to the standby condition.

PR:t AD-CO-C'J1-1. Rev. I ts31 og 1

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                                                                                                                              )%        .

_ -. .. ~

l j EO-00-022 Revision 0 Page 2 of 4 2.b. CCNTINUE MAINTAINING RPV water level between 0" on Fuel Zone indicator and +54" with one or more of the following systems: 1.) Condensate /Feedwater per OP-44-001 - 1076 to O psig 2.) CRD per OP-55-001 - 1076 to 0 psig a.) INCREASE flowrate to maxi:aum, OPERATE T.O pumps if possible. 3.) RCIC per OP-50-001 - 1076 to 60 psig (600 gpa) _ 4.) HPCI per OP-52-001 - 1076 to 110 psig (5000 gpm) 5.) CS Loops A and B . . . . . 455 to o psig (0 - 6250 gps / loop) 6.) LPCI Loops A and B per OP-49-001 - 455 to O psig (0 - 21,300 gpm/ loop) 2.c. If high suppression pool water level (23' 5") exists 0,,3 low CST level 3'7.5" exists Then C0hTIRM automatic transfer of HPCI and MANUALI.T TRANSFER ICIC suction from the CST to the suppression pool. 2.d. If RPV water level cannot be determined or maintained above 0" on Fuel Zone indicatee Then ENTER EO-00-024, level Restoration 2.e If SRV's are cycling Then MANUALLY OPEN en 27 and REDUCE RPV pressure to below 926 psig. AVD START RCIC to minimize SRV cycling

T EO-00-022 Revision 0 Page 3 of /* 1.f. DEPRESSURIZE and COOLDOWN the RPV at less than 100*F per hour per GO-00-004. 1.) Pressure reduction may be augmented in accordance with EO-00-025. CALTION DO NOT DEPRESSURIZE THE RPV BELOW 110 PSIG L3LESS MOTOR DRIVEN PLMPS SLTFICIENT TO MAINTAIN RPV WATER LEVEL ARE RUNNING AND AVAILABLE FOR INJECTION. 2.g. When the RER shutdown cooling hterlocks clear Then INITIATE the shutdown coo!ing mode of RER. 2.h. If the PHR shutdown cooling mode cannot be established and further cooldown is required Then CONTINUE to cooldown using one or more of the systems used fer depressurization. MAINTAIN RPV water temperature above 70*F. 2.i. If_ RPV cooldown is required but cannot be accomplished Then' PERFORM the following: 1.) INITIATE suppression pool cooling mode of RER. 2.) CLOSE the RPV head vents, MSIV's and main steam line drain valves if open. 3.) OPEN one SRV. l 4.) StokT.Y RAISE RPV water level to establish a water flow path through the open SRV back to the suppression pool 5.) START one CS or LPCI pump with suction from the suppression pool.

\26

                                                    -             -      ~~                 .  .__ ..

9 EO-00-022 Revision 0 Page 4 of 4 6.) When injection is established Then STABILIZE PJV pressure below 250 psig. a.) I' RPV pressure does not stabilize belov 250 psig Then OPEN another SRV 2.J. CONTROL suppression pool temperature to MAINTAIN RPV water temperatures above 70*F. 2.k. When plant conditions-permit, PROCEED to cold shutdown in accordance with GO-00-004, Reactor Shutdown from .* 4= - Power Operations to

                      -Cold Shutdown Conditions.

3. DISCUSSION This procedure provide = che direction necessary to depressuirze and cooldown the RPV to cold shutdewn conditions while maintaining RPV vatar level within a satisfactory range.

4. REFERENCES

( ! a. EO-00-021 Level Control l

b. EO-00-024 Level Restoration

c. EO-00-025 RPV Pressure Eeduction (preferred methods) -

d. GO-00-004 Reactor Shutdown from Minimus Power Operations to Cold Shutdown Conditions

                      -e.      OP-44-001 Condensate and Feedwater Systes

f. OP-49-001 RER Systes l

g. OP-50-001 Reactor Core Isolation Cooling Systes l

h. OP-51-001 Core Spray Systes

1. OP-52-001 High Pressure Coolant Injection Systes

j. OP-55-001 Control Rod Drive Hydraulic Systes 4

PDCISYL'.*ANIA PO*.3.R 5 LICliT C 3?ANY % {"" . sesa== .=:. SEs UNzIs t a :

                                                                                               .                     (       ,

PROCCF.E APPWA'AL FOO! Effective Os:e TITLE: EO-00-023 REVISION O . CONTA20ENT CONTROL PAGE 1 0F 10 PCRC RE'*!I7 REQTIRD: YES ( ) 30 ( )

                                             -                                               Maecing ;'u=:er CRICI%ATOR:                    P. E. Taylor AP?ROVALs:
                                           '"= W                                   _

o^u _\k - pDPI.R1;.4 . .t OF PLANT . DATE

                                 ~               '

1. CilU CONDITIONS -

The entry cond:.tions for,this procedure are any of the following:

1. Suppression Pool Water Temperature above 90*F.*

2. Drywell At:ngsphere Temperature above 135'F.

, 3. . Drywell Pressure above 1.69 psig. l 4 Suppression Pool Water Level above 24' . t

2. OPERATOR ACTIONS

                                                                  .. CAUTION                                               -

! IRRESPECTI7E CF THE ENTRY CONDITION, EITER HIS PROCEDIfRE AT STEPS 2.a, 2.b, ! 2.c, AND 2.d AND PERFORM THESE STEPS CONCI".LREITLY WIU ONE ANO nER. 1 l ' CAUTION , NOTI'IT SHIFT SUPERVISOR TO CI.ASSIFT THE E7EiT AND UTITIATE EMERGCICY M.AN ~ l DTLDENTING PROCEDURES IF APPROPRIATE. , j ... ro.u AD-;0-C01-L Rev. 1 Page 1 og 1

                          ~             .s i . =.                                   _ , _

l EO-00-023 Revision 0 Page 2 of 10 2.a. MONITOR and CONTROL suporession pool water temocrature

1) CLOSE any SRV's that are stuck open per ON-83-001, Inadvertant Opening of a Safety / Relief Valve

2) If a stuck SRV cannot be closed within 2 minutes Then SCRAM the reactor and PERFORM EO-00-001, Reactor' Scram, concurrently with this procedure.

CAUTION DO NOT DIVERT RHR PUMPS FROM THE LPCI MODE II CONTINUOUS LPCI OPERATION IS REQUIED TO ASSURE ADEQUATE CORE COOLING.

3) If_ Suppression pool water temperature reaches 90*F Then START all available suppression pool cooling.

4) If Suppression pool water temperature reaches 110*F

     -               Then       SCRAM the reactor and PERFORM EO-00-001, Reactor Scram, concurrently with this procedure.

CAUTION DO NOT DEPRESSURIZE THE RPV BELOW 110 PSIG UNLESS MOTOR DRIVEN PUMPS SUFFICIENT TO MAINTAIN RPV WATER LEVEL ARE RUNNING AND AVAILABLE FOR INJECTION. CAUTION C00LDOWN RATES ABOVE 100'F/HR MAY BE REQUIRED TO ACCCMPLISH THIS STEP.

- 2.

s . 1 i EO-00-023 Revision 0 Page 3 of 10

5) If Suppression pool water temperature cannot be maintained below the Heat Capacity Limit, Figure E0-00-023-1 Then MAINTAIN RPV pressure below the limit, using EO-00-026.

CAUTION DO NOT DEPRESSURIZE THE RPV BELOW 110 PSIG UNLESS MOTOR DRIVEN PUMPS SUFFICIENT TO MAINTAIN RPV WATER LEVEL ARE RUNNING AND AVAILABLE FOR INJECTION. CAUTION C00LDOWN RATES ABOVE 100'F/HR MAY BE REQUIRED TO ACCOMPLISH THIS STEP.

6) If Suppression pool water temperature and RPV pressure cannot be maintained below the Heat Capacity Limit, Figure EO-00-023-1.

Then OPEN a_li l ADS valves. a) f I_f, all ADS valves cannot be opened Then OPEN other SRV's until a total of 6 valves are open. b) f I_f, less than 3 SRV's can be opened Then RAPIDLY DEPRESSURIZE the RPV per EO-00-027. bl

a..w . : e .n e;.:, _ _ - _ _ ___. EO-00-023 Revision 0 Page 4 of 10 2.b. MONITOR and CONTROL Drvwell Temocrature

1) f I_f, drywell temperature exceeds 135*F.

Then OPERATE all available drywell coolers CAITIION WENEVER DRYWELL TEMPERATURE EXCEEDS TE TEMPERATURE IN TE TABLE, TE ACTUAL RPV WATER LEVEL MAY BE ANYWHERE BELOW THE ELEVATION OF THE 10'nT.R INSTRUMENT TAP MIEN TE INSTRUMF.NT READS BELCW TE INDICATED LEVEL IN THE TABLE. Dryvell Indicated Temperatue Level Instrument (later) (later) Shutdown Range (0 to +400 in.) (later) (later) Upset range (0 to +180 in.) (later) (later) Wide range (-150 to +60 in.) (later) (later) Narrow range (0 to +60 in.) (later) (later) Fuel zone (-150 to +50 in.) I CAUTION ! DO NOT DIVDtT RER PUM/S FROM TE LPCI MODE IF CONTINUOUS LPCI OPERATION IS REQUIRED TO ASSURE ADEQUATE CORE COOLING.

2) If drywell temperature reaches 340*F Then SHUTDOWN the Recirculation Pumps and the drywell cooling fans i

AND

INITIATE drywell sprays i

\33

E0-00-023 Revision 0 Page 5 of 10

3) M drywell temperature near the RPV level instrument reference leg vertical runs reaches the RPV saturation limit

     -                        Figure E0-00-023-2 Then      ENTER EO-00-025 RPV Flooding CAUTION DO NOT DEPRESSURIZE THE RPV BELOW 110 PSIG UNLESS MOTOR DRIVEN PUMPS SUFFICIENT TO MAINTAIN RPV WATER LEVEL ARE RUNNING AND AVAILABLE FOR INJECTION.

CAUTION C00LDOWN RATES ABOVE 100*F/HR MAY BE REQUIRED TO ACCOMPLISH THIS STEP.

4) M drywell temperature cannot be maintained below 340*F Then OPEN ay ADS valves a) M all ADS valves cannot be opened Then OPEN other SRV's until a total of 6 valves are open b) M less than 3 SRV's can be opened Then RAPIDLY DEPRESSURIZE the RPV per EO-00-027

E0-00-023 Revision 0 Page 6 of 10 2.c. MONITOR and C0hTROL primary containment pressure with the following systems as required: CAUTION START TE HYDROGEN RECOMBINER SYSTEM PRIOR TO PRLMARY COSTAINMENT HYDROGEN CONCENTRATION EXCEEDING 3.3 PERCENT BY VOLLME. CAUTION ELEVATED SUPPRESSION CHAMBER PRESSURE MAY TRIP THE RCIC OR HPCI TURBINES ON HIGH EXHAUST PRESSURE.

1) VENT the primary containment through the SEGT System only when the drywell temperature is less than 212*F per OP-70-001, Standby Gas Treatment System. ENSURE Chemistry samples and analyses primary containment atmosphere prior to venting.

CAUTION i DO NOT DIVERT RER PUMPS FROM TE LPCI MODE IF CONTINUOUS LPCI OPERATION IS l REQUIRED TO ASSURE ADEQUATE CORE COOLING. l 2) INITIATE suppression pool sprays before l Suppression chamber pressure reaches the Suppression Pool Spray Limit, Figure EO-00-023-3 CAUTION l DO NOT OPERATE TE REACTOR RECIRCULATION PCMPS OR PRIMARY CONTAIhTENT VENITLATION FANS WHEN SPRAYING TE DRYWELL. ( 3.5'

4 E0-00-023 Revision 0 Page 7 of 10

3) SHUTDOW the Recirculation Pumps and the Drywell Cooling Fans and INITIATE drywell sprays before suppression

! chamber pressure reaches the Pressure Suppression Limit, Figure EO-00-023-4

4) M suppression chamber pressure cannot be maintained below the Pressure Suppression Limit, Figure EO-00-023-4.

Then ENTER E0-00-025 J l a f

    . .     , - - m, .                   .-                        - . . _ . - , . . .                     .,        ,

I l _ . - - ~ _ . . - . _ _ _ _ _ _ _ . _ _ . . _ . . . 1 EO-00-023 Revision 0 Page 3 of 10 2.d. Monitor and Control Surpression Pool Water Level

1) 2'AINTAIN suppression pool water level between 22' and 24'. ENSURE Chemistry samples and analyzes suppression pool water level prior to discharging

2) M a high suppression pool level of 23'5" exists

_OR low condensate storage tani level (3'7.5") exists Then CONFIRM automatic transfer af EPCI and manually transfer RCIC suction from the CST to the suppression pool.

3) M the suppression pool water level is above 24' AND adequate core cooling vill continue to be assured Then TERMINATE injection into the reactor vessel from sources external to the primary containment.

CAL;ICN DO NOT DEPRESSURIZI THE RPV 3ELCW 110 PSIG UNLESS MOTOR DRIVEN PLTS SUTICIENT TO MAINTAIN APV VATER LTVEL ARE RUhTING 'AND AVAILA312 FCR ! INJECTION. CAUTION C00LD01.N RATES ABOVE 100*F/ER MAY RE REQUIRED TO ACCOMPEISH THIS STEP.

4) Il suppression pool water level casset be maintained below the Suppression Pool Load Limit, Figure E0-00-023-4 Then MAINTAIN RPV pressttre below the limit per EO-00-026 i

i

-w

d EO-00-023 Revision 0 Page 9 of 10 CAUTION DO NCf DEPRESSURIZE THE RPV EELCW 110 PSIG L3LISS MOTOR DRIVEN PCf?S SUFFICIENT TO MAINTAIN RPV WN17.R LEVEL ARE RUNNING AND AVAILA3LE FCR INJECTION. CAUTION COOLDOWN RATES ABOVE 100*F/HR MAY EE REQUIRED TO ACCOMPLISH THIS STEP.

5) M suppression pool water level and RPV pressure cannot be restored or maintained below the Suppression Pool Load Limit, Figure IO-00-023-4.

Then OPEN all ADS valves. a) . M all ADS valves cannot be opened Then OPEN other SRV's until a total of 6 valves are open. b) M less than 3 SRV's can be opened Then RAPIDLY DEPRESSLT ZE the RPV per EO-00-027. _, 6) M primary containment water level reaches 122.4 feet Then TERMINATE injection into the RPV from sources external to the primary . conta4 - nt. t

          -3. DISCUSSION This procedure provides the direction necessary to control primary -

containment temperatures, pressure, and level. This procedure is performed concurrently with the procedure from which it is entered.

                                                                                                     ~
                                                                                                 \38

' . -- . .m.- EO-00-023 Revision 0 Page 10 of ?0

4. RETERENCES

a. EO-00-001 Reactor Scram

b. 10-00-025 RPV Flooding

c. ZO-00-026 RPV Pressure Reduction - (Preferred Methods)

d. EO-00-027 RPV Pressure Reduction - (SRV Failure)

e. ON-83-001 Inadvertant Opening of a Safety / Relief Valve

f. OP-70-001 Standby Gas Treatment System O

FIGURE EO 023 - 2 RPV SATURATION LIMIT

                                                   ... s.                     s.._..____s.._.__.,                 s.   ,,       .      ,         s
                           .Ns
                                                      .                                                                                       ,       s s                                    .                      -

550 ' ~ ' N N N - . s Ns - s .s s Ns . s .

                                                                                                   -s A

s . . s

500 - - -

5 . w aus , e N -

             .u. .

M w o 450 s. s p . M, s -

                                           *               -        \,..                  L u

a N s - N - 5 \ - - .

n . w , -

c* M 400 - s -' N . g - , - \., , RPV saturation lisi: o - s s ' I , \ ' N w

               =             \

no

s x \

        =.
                                         ~

c - 350 - s

        !      .                   .s        N M                         's u        '

k u w a w 300-

            .=                 .

O U I k ! e o e 250-

i i 200'O 100 2'00 3do 460 500 600 700 800 900 1000 RP7 Pressure (psig) (4 D L.

                                                                                            . _ = . _ _ - ~                      ._            -                     . _ _ .                    . .              -           .-

FICLJRE EO 023 - 3 SUPPRESSION POOL SPRAf LDflT 55-

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20 ! . l / i Suppressien Pool Spray Limit / 15 > > - - 20 2h 3'O 35 40 45 50 55 Suppressifa Pool Level (ft.) 1.'

i l l

                                                                                        . -                                                                                                                      1 i   .

FIGURE EO 023 - 4 PRESSURE SUPPRESSION LIMIT 55 p /

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20

                                                                                                                                  -Pressure Suppression Limit 15 '20                         23                         36                           33                      40           45                       50        55 Primary Containment Water Level (ft.)                                                                     }Q b-

PCiNSTLVANIA PC'4ER & LIGHT CCMPANY SUSQUEHANNA SES UN!!S 1 & 2 , PRCCEDURE APPROVAL FORM Effective Date TITLE: E0-00-024 REVISION O LEVEL RESTORATION PAGE 1 CF 12 PORC RETII'J REQUIRED: TES ( ) NO ( ) Meeting Nun =er P. E. Taylor ORIGD:ATOR: APPROVALS: a(\k SEC* ~.\Dhb DATE KPERINTENDENTOFPLANT

1. ENTRY CONDITIONS This procedure is entered frem EO-00-021, Level Control, or EO-00-022, Cooldown when RPV vater level cannot be maintained above 0" on the Fuel Zene indicator.

2. OPERATOR ACTIONS 2.a. LINE UP for injection and START pumps in 2 or more of the following injection systems:

1) Condensate per OP-44-001

2) CS Loop A per 07-51-001 i

3) CS Loop 3 per 0?-51-001

4) LPCI Loop A per OP-49-001

5) LPCI loop B per OP-49-001 s

FORM AD-00-001-1, Rev.1 Page 1 of'l I L

                                                                '- . -  .~ .     . . .

EO-00-024 Revision 0 Page 2 of 12 2.b. If-- Less than 2 of the injection systems can be lined up Thet C0f0 FENCE LINING UP as many of the following alternate injection systems as possible:

1) RER Service Water cross tie by assuring the RER Service Water System is in operation and then opening HV 12 FO 73 (A&B) and HV 12 FO 75 (A&B) when injection is called for

2) SBLC Boron Tank to reactor per OP-55-001, Standby Liquid Control System

3) ECCS Keep-Full System, by confirming the Keep-Full System is lined up and assuring the condensate transfer header is pressurized per OP-37-001 '

+ M4

        '                   ~

EO-00-024 Revision 0 Page 3 of 12 2.c. Monitor RPV water level and pressure

1) REFER to Table EO-00-024-1 below to deter:nine the step to enter for existing RPV level and pressure conditions

2) M RPV water level trend reverses E

RPV pressure trend reverses RPV pressure changes region (in Table EO-00-024-1) Then RETURN to Step 2.c. of this procedure

3) M at any time RPV water level cannot be determined and' at least one nor:nal or alternate in3ctionsystemislinedup with at least one pump running Then ENTER EO-00-025, RPV Flooding (unless otherwise specified).

TABLE EO-00-024-1 RPV PRESSURE REGION i Greater Than Less Than 455 455 to 110 110 High Intermediate Low l s l RPV LVL INC. 2.d. 2.e. 2.f. I RPV LVL DEC. 2.g. 2.h. l l l

a-

         - - .. .. e      .

EO-00-024 Revision 0 Page 4 of 12 2.d. RPV level increasing and RPV pressure greater than 455 psig (High Region)

1) ENTER EO-00-021, I,evel Control at Step 2.e e

t f G i e i e P I I l. i-I l t-L

         -~-                                                - __ . _ _ _ _ ._ -      _ . _ . .

EO-00-024 Revision 0 Page 5 of 12 2.e RPV level increasing and RPV pressure between y55 and 110 psit (Intermediate Region) CA'i~0N DO NOT DEPRESSURIZE THE RPV BELOW 110 PSIG L3'LESS MOTOR DRIVEN PUMPS SUITICIENT TO MAIh'IAIN RPV WATER LEVEL ARE RLM*ING AND AVAII.ABLE FOR INJr.CTION. CAUTION C00LDOWN RATES ABOVE 100*F/HR MAY BE REQUIRED TO ACCOMPLISH THIS STEP.

1) M RCIC and HPCI are ng available AND RPV pressure is increasing Then OPEN aM ADS valves.

a) y all ADS valves cannot be opened Then OPEN other SRV's until a total of 6 valves are open. b) H less than 3 SRV's can be opened Then RAPIDLY DEPRESSURIZE the RPV per EO-00-027

2) y HPCI and RCIC are nit,available AND RPV pressure is not increasing Then ENTER EO-00-021,-Level Control at Step 2.e

3) When RPV water level reaches +13" Then ENTER EO-00-021, Level Control at Step 2.s lh

EO-00-024 Revisic: 0 Page 6 of 12 2.f. RPV level increasing a:d RPV pressure Less Than 110 psig (Low Region) CACTION C00IDCW RATES ABOVE 100*F/HR MAY BE REQUI'iED TO ACO:Af?LISH THIS STEP. ,

1) M RPV pressure is increasing nen OPIN all l ADS valvcs.

a) If all ADS valves e. snot be opened Then CPIN other SRV's until a total of 6 valves are open. b) g less than 3 SRV's can be opened Then RAPIDLT DEPPISSERIZI the RPV per EO-00-027

2) Wee RPV level exceeds 0" on the Fuel Zone indicator Then ENTER EO-00-021, Level Centrol at Step 2.e.

i

      ~ -- - - - _ -                           ._ _ --         .

b EO-00-024 Revision 0

,                                                                           Psge 7 of 12 2.g. RPV level decreasing and RPV pressure greater than 110 psig (Intermediate /High region)                            _

1) H HPCI and RCI.: are not operating Then RESTART HPCI per OP-52-001 and l RCIC per OP-50-001 CAUTION DO NOT DEPRESSURIZE THE RPV BELOW 110 PSIG UNLESS MOTOR DRIVEN PUMPS SUFFICIENT TO 1AINTAIN RPV WATER LEVEL ARE RUNNING AND AVAILABIl FOR INJECTION.

I i CAUTION C00LDOWN RATES ABOVE 100'F/HR MAY BE REQUIRED TO ACCOMPLISH THIS STEP.

2) H CRD is ng operating BUT at least 2 normal injection sys mas are lined up for injection with pumps running Then OPZN a_li l ADS val',es.

a) H all ADS valves cannot be opened ! Then OPEN other SRV's until a total of 6 valves are open. b) g less than 3 SRV's can be opened Then RAPIDLT DEPRESSURIZE the RPV per EO-00-027 i W1

                                                                             - -> -e E0-00-024 Revision 0 Page 8 of 12

3) If CRD is not operating S

h'o normal injection system is lined up for injection with at least one Pump running. Then START pumps in alternate injection systems that are line.d up for injection. _ 4) When the RPV water level drops to 0" on the Fuel Zone Indicator AND CRD not operating, and No alternate injection system is lined up for injection with pump running Then PERFOR!f the following steps: a) When RPV water level drops to -75" on the Fuel Zone Indicator QR RPV water level cannot be dete: mined Do Not, enter EO-00-025, RPV Ffooding) Then OPEN cne SRV b) As RPV pressure decreased, open additional SRV's as required Ff Table EO-00-024-2, (alphabetical opening sequence if possible).

l

                                                   =              ,,
                                                                       ,m   m     *1 6
                                                                                       .d*    . , , ,

EO-00-024 Revisica 0 Pa;;e 9 of 12 Table EO-00-024-2 s ot' Pressure (PSIG1 Total No. of SRV's Ooen Et wt .00 1

     . 6 een 800 and 500                             2 Between 500 and 350                              3 Between 350 and 250                              4 Between 250 and 175                              5 Between 175 and 125                              6 Below 125                                        7 CAUTION DO NOT DEPRESSURIZE THE RPV BELOW 100 PSIG UNIISS MOTOR DRIVEN PinfPS SUFFICIENT TO MAINTAIN RPV WATER I.EVEL ARE R15NLNG Ah) AVIALABII FOR INJECTION.

CAUTION C00LDOWN RATES ABOVE 100'F/HR MAY BE REQUIRED TO ACCOMPLISH THIS STEP. t

5) If the RPV water level drops to 0" on the Fuel Zone Indicator A.N_D_

l CRD is Operating, or a normal injection system is lined j up for injection with pump rtmning, or an alternate injection system is lined up for injection with pump running i i Then OPEN all ADS valves. 1 r W\ L

                               .         .    .               . . . .                                           i'
      ~ ~-            - - -
                                                                '-.L.-,

k i ., EO-00-02!. Revision 0 Page 10 of 12 a) M all ADS valves cannot be opened Then OPEN other SRV's until a total i of 6 valves are open. 't b). g less than 3 SRV's can be opened Then RAPIDLY DEPRESSURI2 the RPV ' ? per EO-00-027 i i 4 1 J I i ? I i r E

15 t . w

                                                             -- ~   __ ....          . . _       ..

10-00-02!. Revisic: C Page 11 of 12 2.h. PSV level decreasing and PJ7 pressure less than 110 psig (lev region)

1) If No 1:jection system is lised up f:r inj ectica .is 6 at least c:e p W .nssing Then START pumps in the alterna:e injeciten systems that are lised up for injectie:

CALTICN C00!.DOW RATIS A30VE ICO'I/ER SY 3E REQUIRED TO ACCCS LISH THIS STEP.

2) y RP7 pressure is increasi:g Then CPEN all ADS valves a) M All ADS valves cannot be cpened The: OPEN other SRV's until a total of 6 valves are open.

b) M less tha 3 SR7's ca be ope:ed The: RAPIDLY EEPRESSGIZE the RPV per 10-00-027

3) M RP7 pressure is -d increasi:g ASD RPV water level drops to 0" on the Iuel Zone Indicator The: CPEN all ADS valves.

a) If all ADS valves cauct be . ~ ;ed Then OPEN other SRV's u=til a total of 6 valves are epen. b) OPERATE CS with suction free the suppression pool. 1O

                   ^          -

EO-00-024 Revision 0 Page 12 of 12 c) When either CS Loop A or B is operating with suction from the suppression pool l 2 RPV pressure is below 105 psig

          .                Then       TIR!fINATE injection into the RPV from sources external to the primary containment

3. DISCUSSION This procedure provides the direction necessary to restore the RPV water level to above the top of the active fuel while maintaining an increasing or stable trend.

4. REFERENCES

a. EO-00-021 Level Control

b. EO-00-022 Cooldown

c. E0-00-025 RPV Flooding

d. EO-00-027 RPV Pressure Reduction - (SRV Tsilure)

e. OP-37-001 Condensate and Refueling Water Transfer

f. OP-44-001 Condensate and Feedwater System 3 OP-49-001 RHR Systea.

h. OP-50-001 Reactor Core Isolation Cooling System

1. OP-51-001 Core Spray System J. OP-52-001 High Pressure Coolant Injection System

k. OP-53-001 Standby Liquid Control System k

                                ,.         ,-~     .
                                                     . ,,    . -y                               _ _ _ . _ _ _ . . _

PENNSYLVANIA P0k*ER & LIGHT CCMPANY i SUSQUEHANNA SES UNITS 1 & 2 5 - 1 - PROCEOURE APPROVAL FORM Effective ?ste

                                    ..e l

TITLE: EO-00-025 REVISION O RPV FLOODING PAGE 1 OF 5 PORC REVII*4 REQUIRED: YES ( ) NO ( ) Meeting Nu=ber ORIGINATOR: P. E. Taylor APPROVALS: _ , (NN sd*'~

                            \NSUPERINTEGEiT OF PLLNT                                DATE

1. ENTRY CONDITION 3

'i This procedure is entered from EO-00-023 Contai:=ent Control or EO-00-024 Level Restoration when: RPV water level cannot be deter =ined SR Drywell temperature near the RPV level instrument reference leg vertical runs reaches the RPV Saturation Limit 91 ' Suppression chamber pressure cannot be maintained below the PressureSuppression Limit. l l l I l l FORM AD-00-001-1, Rev.1 Page 1 of 1 ($Y

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- L c _ _

E0-00-025 Revision 0 Page 2 of 5

2. OPERATOR ACTIONS CAUTION DO NOT PRESSURIZE THE RPV BELOW 110 PSIG UNLESS MOTOR DRIVEN PUMPS SUFFICIENT TO MAINTAIN RPV WATER LEVEL ARE RUNNING AND AVAILABLE FOR INJECTION.

CAUTION C00LDOWN RATES ABOVE 100'F/HR MAY BE REQUIRED TO ACCOMPLISH THIS STEP. _ 2.a. OPEN all ADS valves

1) M all ADS valves cannot be opened

hen OPEN other SRV's uniti a total of 6 valves are open

2) g less aan 3 SRV's can be opened Then RAPFJLY DEPRESSURIZE the RPV per EO-00-027 2.b. E at least 3 SRV's are open l

l Then CLOSE the following valves: l 1) MSIV's HV-41-F022A(B)(C)(D) and HV-41-F028A(B)(C)(D) 1 (- 2) Main steam line drains HV-41-7016 and HV-41-F019

3) HPCI isolation valves HV-55-F002, HV-55-F100, and HV-55-F003

4) RCIC isolation valves HV-49-F007, HV-49-F088, and HV-49-F008 j 5) RER steam c'ondensing isolation valves HV-51-F051A(B) l and HV-51-F052A(B) i

(- 6) RWCU isolation valves HV-144-F001 and HV-44-F004 . lW t u

                             < ?!'                 _.

o EO-00-025 Revision 0 Page ; of 5 2.c. INJECT water into the RPV with g of the following:

1) CRD per OP-55-001

2) Condensate Pump (s) per OP-44-001

3) CS Loop A per OP-51-001

4) CS Loop B per OP-51-001

5) LPCI Loop A per OP-49-001

6) LPCI Loop B per OP-49-001 2.d. M RPV pressure stabilizes within 7 minutes Then CYCLE one SRV closed then OPEN to determine the single SRV pressure rise.

2.e. If RPV pressure does not stabilize within 7 minutes gR, Single SRV pressure rise is less than (later) psig Then INJECT water into the RPV with ALL of the following:

1) RER service water cross-tie ty assuring the RER Service Water System is in operation and then opening HV-12-F073A(B) and HV-12-F075A(B)

2) SBLC Baron Tank to Reactor per OP-53-001

_ 3) ECCS keep full system by confirming the keep-full system is lined up and assuring the condensate transfer header is pressurized per OP-37-001. 2.f. M Suppression chamber pressure exceeds the Primary Containment Pressure Limit, Figure EO-00-025-1 Then VENT the primary containment in accordance with OP-73-001 2.g. FILL all RPV level instrument reference legs {N I

c

                            , -       v;
                                     -=

w . . . . - I E0-00-025 Revision 0 Page 4 of 5 2.h. If drywell temperature near the RPV level instrument reference leg vertical runs is below 212*F. AND RPV we.ter level instrumentation is available. Then CYCLE o.te SRV closed then open to determine the signal SRV pressure rise. 2.i. If The single SRV pressure rise is at least (later) psig S it can be determined that the RPV is filled Then PERFOR!f the following:

1) TERMINATE all injection into the RPV a) If RPV water level indication is restored Then ENTER EO-00-021 at Step 2.e.

2) Reduce RPV water level until RPV water level indication is restored a) If RPV 'n ter level indication is not restored within 7 minutes after injection into the RPV was terminated.

l Then RETURN to Step 2.c. of this' procedure b) If RPV level indication is restored within 7 minutes of terminating injection

                                                 'Then         ENTER EO-00-021 at Step 2.e

3. DISCUSSION This procedure provides the direction necessary to assure adequate core cooling and containment integrity by flooding the RPV.

kN

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EO-00-025 Revision 0 Page 5 of 5

4. REFERENCES

a. E0-00-021 Level Control

b. EO-00-023 Containment Control

c. EO-00-024 Level Restoration

d. EO-00-027 RPV Pressure Reduction - (SRV Failure)

e. OP-37-001 Condensate and Refueling Water Transfer

f. OP-49-001 RHR System

g. OP-51-001 Core Spray System

h. OP-53-001 Standby Liquid Control System

i. OP-55-001 Control Rod Drive Hydraulic

j. OP-73-001 Containment Atmosphere Control System

FIC"RI EO 025 - 1 FRI}'ARY C0!CAIID'E."? ?RESSIS. I LD'I' li, l l/l- ,! / f ,/ ,,/ ,/ ,. ,. s ,/ /

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II5 'O 2 23 30 35 40 45 50 53 Primary Contai= ment 'a'ater Level (f t.) {g P

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i e , , T PENNSTLVANIA PCWER & LIGHT CCMPANY SUSQUEHANNA SES UNITS 1 & 2 l""'"

g ! i i i PRCCEDURE APPROVAL FORM 't Effective Date TITI.E: EO-00-026 REVISION O RPV PRESSURE REDUC

ION - (PREFERRED METHOD) PAGE 1 0F 3 PORC RE7IEW REQUIRED: TES ( ) NO ( )

Meeting Number ORIGINATOR: P. E. Taylor APPROVALS: _d DATE V 3UPERINTENDENT OF PLANT DATE

1. ENTRY CONDITIONS t

This procedure is entered from EO-00-022 or EO-00-023 when it is required to depressurize the RPV using preferred methods at a continuous rate.

2. OPERATOR ACTIONS i

CAUTION ' \ _, DO NOT DEPRESSURIZE THE RPV 3ELOW 110 PSIG UNLESS MOTOR DRIVEN PUMPS SUTFICIENT IO MAINTAIN RPV WATER LEVEL ARE RUNhTIG AND AVAILABLE FOR l INJECTION. l l l i FORM ' AD-00-001-1, Rev.1 Page 1 of 1

j

         .   .9                 .

YY r EO-00-026 Revision 0 Page 2 of 3 2.a. Main Condenser Available _1. ) Use bypass valves to DEPRESSURIZE and C00LDOWN a? the RPV, per GO-00-004. 2.) Pressure reduction may be augmented with one or more of the following systems a.) HPCI per OP-52-001 b.) RCIC per OP-50-001 c.) Other steam driven equipment (1) Steam Jet Air Ejectors per OP-43-001 (2) Steam to Reactor Feed Pumps per OP-45-001 (3) Steam to Steam Seal Evaporator per OP-92-001 (4) Main Condenser Deaerating Steam per OP-44-001 d.) Reactor Water Cleanup (Recirculation Mode) per OP-61-001 e.) Main Steam Line Drains f.) Reactor Water Cleanup (Coolant Rejection) per OP-61-001. ENSURE Chemistry samples and analyzes primary coolant prior to rejection. CAUTION DO NOT DEPRESSURIZE THE RIV BELOW 110 PSIG UNLESS MOTOR DRIVEN PUMPS SUFFICIENT TO MAINTAIN EV WATER LEVEL ARE RUNNING AND AVAILABLE FOR INJECTION. 2.e. Main Condenser not available: 1.) DEPRESSURIZE a_ad COOLDOLN RPV at less than 100*F per hour using one or more of the following systems: a.) HPCI per OP-52-001 b.) RCIC per OP-50-001 c.) Reactor Water Cleanup System (Recirculation Modd per OP 001 d.) 1 essure reduction may be augs;ntad by: ( r( l

y e *, , a EO-00-026 Revision 0 Page 3 of 3 (1) SRV's (in alphabetical sequence if possible) (2) Reactor Water Cleanup (Coolant Rejection) per OP-61-001. ENSERE Chemistry samples and analyzes primary coolant prior to rejection. 2.h. If Instrument gas supply to the SRV's is lost (Instrument Gas Bottle HeaderA(B) Low Pressure Alarm) Then DEPRESSURIZE the RPV with sustained SRV opening l

3. DISCUSdION This procedure provides the direction necessary to select the proper method (s) to reduce RPV pressure at a centro 11ed rate.

4. REFERENCES

a. E0-00-022 Cooldown

b. EO-00-023 Containment Control i

e. OP-43-001- SJAE and Mechanical Vacuus Pump

d. OP-44-001 Condensate and Feedwater System

e. OP-45-001 Teedwater Turbine and Lube 011 System

f. OP-50-001 Reactor Core Isolation Cooling Systes 3 OP-52-001 High Pressure Coolant Injection System

h. OP-61-001 Reactor Wate: Cleanup System

i. OP-92-001 Ste_m Seal System J ., GO-00-004 Reactor Shutdown from Minimum Power Operations to Cold Shutdo m Conditions

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PENNSYLVANIA POWER & LIGHT CCMPANT - 4"

                   .r SUSQUEHANNA SES UNITS 1 & 2                                           ]

PROCEDURE APPROVAL FORM Effective Date d g *. EO-00-027 REVISION O RPV PRESSURE REDUCTION - (SRV FAILURE) PAGE 1 0F 2 PORC REVIEW REQUIRED: YES ( ) NO ( ) Meeting Number P. E. Taylor ORIGINATOR: APPROVALS: a\ SECTI DATE s RINTENDENT OF PLANT DATE

1. ENTRY CONDITIONS

                                          .This procedure is entered from EO-00-023 EO-00-024, and EO-00-025 when it is required to rapidly depressurize the RPV and less than 3 relief valves

. can be opened. l l

2. OPERATOR ACTIONS 2.a. OPEN all available SRV's.

2.b. AUGENT the pressure reduction by using one or more of the following systems (use in order which will minimize radioactive release to the environment): (1) Main Condenser per GO-00-004 I l l l l Mt

                             'PORM AD-00-401-1, Rev.1 I-                             Page 1 of 1'

c. - -

        . 4 . ;.                                         -
   . .. a 4

EO-00-027 Revision 0 Page 2 of 2 (2) Other steam driven equipment: (a) Steam Jet Air Ejectors per OP-43-001 (b) Steam to Reactor Feed Pumps per OP-45-001 (c) Steam to Steam Seal Evaporator per OP-92-001 (d) Main Condenser Demerating Steam per OP-44-001 (3) Main Steam Line Drains (4) Reactor Water Cleanup (Coolant hejection)per OP-61-001. ENSLIE Chemistry samples and analyzes primary coolant prior to rejection. (5) HPCI steam line (6) RCIC steam line (7) REV head vent

3. DISCUSSION' This procedare provides the direction necessary to rapidly reduce RPV pressure when less than 7 SRV's can be opened.

4. REFERENCES

a. EO-00-023 Containment Control

b. EO-00-024 Level Restoration

c. EO-00-025 RPV Flooding

d. GO-00-004 Reactor Shutdown from Minimum Power Operations to Cold Shutdown Conditions

e. OP-43-001 SJAE and Mechanical Vacuus Pump

f. OP-44-001 Condensate and Feedvater System 3 OP-45-001 Feedvater Turbine and Lube Oil System

h. OP-92-001 Steam Seal Systes

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                                                              .                 INSTRUCTION' APPR07 j

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                                                                                                                                                 \l ' '                                                    \
                   ' OPERATIONS INSTRCCTION
                                                                                                             /          ,i[ I factive Date r

C TEMP 01UJLY INSTRUCTION. j< [ i\ ,/ l i *' Revision Nu=ber 0 I' o Instruction Number OP-0I-001 ( 41 1\ Fase 1 of 5 V .. Instruction Title SHIFT MANNING -

                            ~
                                            .                                                                                                                                                            l Prepared by                        Fred Crsber Approved by                                                                                                      Date Supervisor of ' Operations
                    .1.0 PURPOSE                                . ..

i The purpose of this instruction-is to orovide requirements in manning a shift, establish a progression line of responsibility and to state maximum overtime hours that can be worked. ~ l *: _ . 2.0 RESPONSIBILIIT - 2.1 The Supervisor of Operations is responsibla for ensuring that this

                                             inst:uction meets the requirements.as set forth in the applicable                                                             .

regulations and that'it is implemente,d and followed'by the Operations

                         ..                    Section..

2.2 The Unit Supervisor is responsible for ensuring adequate numbers of

                                ..            qualified personnel 'are assigned to perform scheduled evolutions. He also.is responsible for ensuring the overtime policy set forth in this instruction is not violated.                                                                            ..
                                -2.3          The Day Shif t Supervisor is responsible for reviewing and app'reving the
                                      ,       weekly work schedule to 'ensdre an adequate number of qualified people
                                          'have been scheduled to support'all planned activities.

t ' l 025-1 Ra.. 0 - "

                                                                                                                                                                               '( b ge 1 of 1                                                                            .                                       .

                                                                .                                            I OP-0I-001 Revision 0
        ,                                                                        Page 2 of 5 l

1 2.4 The Nuclear Plant Specialist is responsible for providing a weekly work schedule to be approved by the Day Shift Supervisor. He also will maintain the Operations' Personnel Qualification Roster SUSO Form (later) to be utilized for assigning additional personnel to a shift as needed. -

3.0 REFERENCES

3.1 NUREG 0660 Section I.A.I.3 3.2 Technical Specifications Section 6.2.2 3.3 AD-26-001 Conduct of Operation 3.4 NDI 4.2.1 Licensed Operator Training Program 4.0 PROCEDURE 4.1 Shift Complement 4.1.1 The minimum shift complement at the time of Unit I fuel load and at all times thereafter shall be in accordance with Technical Specifications Section 6.2.2 and Table 6.2.2.1. 4.1.2 For the time up to Unit 1 fuel load, the minimum shift coverage shall be the following: 4.1.2.1 Management (permanant Shift Supervisor or permanent Unit Supervisor) -1 4.1.2.2 Plant Control Operator - 1 4.1.2.3

Nuclear Plant Operator - 1 4.1.2.4
Auxiliary Systems Operator - 1
Must be qualified for fire brigade members 4.1.3 Additional personnel may be assigned to the shift by the Supervisor of Operations or Shift Supervision as determined

                               - by plant conditions and anticipated operating activities.

4.1.4 - The Unit Supervisor shall designate the following on a shift basis: 4.1.4.1 The Plant Control Operator having responsibility for the Unit PCO function. ((o'[ O e

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                                  .-            x.. _..          . , . ~ -                    -

OP-0I-001 Revision 0 Page 3 of 5 4.1.4.2 The Nuclear Plant Operator having rounds p responsibility for the Unit NPO functions. 4.1.4.3 The Auxiliary . Systems Operator having rounds responsibility for the ASO function. 4.1.5 The Shift Supervisor shall have control of the Plant. 'Vhen not in the control room, he shall designate a Unit Supervisor or another senior reactor operator to assume his responsibilities. At all ti=es the progression line of responsibility shall be clear and understood by all personnel on shift prior to the Shift Supervisor leaving the control roos. 4.2 Scheduling

             . Scheduling of operation personnel is addressed in OP-01-004.

4.3 Overtime 4.3.1 The maximum time worked by all operations personnel assigned to rotating shift work shall be limited to the following conditions: 4.3.1.1 Not more than 12 consecutive hours with a 12 hour rest period between work periods. l 4.3.1.'2' Not more than 72 hours in a 7 day period. 4.3.1.3 Not more than 14 consecutive days without 2 l consecutive days off. l 4.3.2 Approval to deviate from these conditions shall be granted ! from the Supervisor of Operations. If it becomes necessary to deviate from the above conditions, the individual shall be assigned to duties outside the control room. These l i occurrences shall be documented on SUSO Form (later). l l 4.3.3 Selection of personnel to work overtime shall be in accordance with the substitution / overtime policy between l Station Management and the Bargaining Unit. l

 ,                 4.3.4     No control room operator shall be assigned to work more than 8 continuous hours with his prinary du?ies at the control board. If the occasion comes up that he must exceed 8 continuous ho,urs, he shall be periodically relieved of primary duties such that periods of duty at the board do not exceed 4 hours at a time.

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OP-0I-001 Revision 0 Page 4 of 5 4.3.5 If a reactor operator (RO) or senior reactor operator (SRO) has been working more than 12 hours at duties away from the control board, such individuals shall not be assigned shift l duty in the control room without at least a 12 hour break preceeding such assignment. I 4.4 Shift Qualification 4.4.1 Only qualified individuals will be assigned to work at a job title. 4.4.2 The Unit Supervisor will utilize the Operaticas Personnel Qualification Roster SUSO Form (later) in determining an individuals qualification for a particular position. 4.4.3 The Operations' Personnel Qualification Roster consists of the following: 424.3.1 A list of department personnel assigned to each of the department positions including: 4.4.3.1.1 Day Shift Supervisor 4.4.3.1.2 Shift Supervisor 4.4.3.1.3 Unit Supervisor 4.4.3.1.4 ' Assistant Unit Supervisor 4.4.3.1.5 Plant Control Operator 4.4.3.1.6 Nuclear Plant Operator 4.4.3.1.7 Auxiliary Systems Operator

4.4.3.2 Beside each name, positions qualified at including

4.4.3.2.1 ASO Water Systems 4.4.3.2.2 ASO Radwaste i 4.4.3.2.3 NPO Turbine Building fysitt 1 & 2) ( 4.4.3.2.4 NPO Reactor Build (99 ( site 1 & 2) i 4.4.3.2.5 PCO (Units 1 4 21 ! 4.4.3.2.6 Assistant Unit Supervisor (U;its 1 & 2) 0 ((0 (

l . : I

  ,1- '       .

i l l 1 OP-0I-001 Revision 0 Page 5 of 5 4.4.3.2.7 Unit Supervisor (Udits 1& 2) 4.4.0 2.8 Shift Supervisor l4.4.4 The master Operations Personnel Qualification Roster shall be maintained and updated by the Nuclear Plant Specialist. 4.4.5 A copy of the roster will be provided to the Unit Supervisor. 4.4.6 The Nuclear Training Department will provide the information needed to the Nuclear Plant Specialist who will revise the roster as necessary. 4.4.7 The Supervisor of Operations will review and approve each revision to th.e master roster. 4.4.8 A separate roster shall be maintained by the Nuclear Plant Specialist for personnel not qualified at the ASO level due a to new hire or new procotion into the position. This roster will include a list of names as well as the following areas: 4.4.8.I' Confined Space Entry 4.4.8.2 Health Physics Level I, II 4.4.8.3 General Erployee Training 4.4.8.4 MSA Training

i. ' 4.4.9 The Nuclear Plant Specialist shall naintain this roster as in the Operation Personnel Qualification Roster with a copy provided to the shift office.

4.4.10 As each individual qualifies as an ASO, the individual will be placed on the Operations Personnel Qualification Roster for further tracking of his qualifications. 5.0 RECORDS There are no records produced by this instruction.

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INSTRUCTION,APPROVAI.FOA,M /

                                                                                                                                                           )                               ,) {                             ,

OPERATIONS INSTRUCTION

                                                                                                                                              /
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                                                                                                                                                     /L I                   .

i f 1 ive Date

                                                                                                                                                                   . i TEMPORARY INSTRUCTION L,

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s 1 v Revision Number 0

                             !.                                                                                      Y                              -N Instruction Number                                              OP-OI-003                                                                                     Page 1 of                            5 Instruction Title                                              SHIFT TURNOVER
                                                                                                                             \

Prepared by J. D.' Everett _ Approved by - Data Supervisor of~ Operations {

                    ..      I'.0 PURPOSE                                  -

The purpose of this instruction is to describe the shif t relief of Operations personnel. - 2.0 RESPONSIBLITY - *

    .--                              2.1               The S' hift Sup,ervisor is responsible for ensuring that the provisions of this instruction are implemented.
                                ' 2.2 - All on shift personnel are required'.co relieve and' be relieved as l                        ..                         . specified for their position.                                                      .

3.0, REFERENCES *

                                 . 3.1 AD-OO-026, Conduct of Operations                                                                                                                  ,,

l 3.2 NUREG-0660, T.2 2 Action.: Plan -

                                                                                                                                                                              . ..e                                           -

l .. l -W 25-1 Re.. 0 ste-1 of 1 ' l l _ 13( E

OP-0I-003 Revision 0 Page 2 of 5 4.0 PROCEDURE Operations Shift Personnel are required to remain on shift with full responsibilities of their position until properly relieved. The relief of shif t positions shall be conducted as follows: 4.1 The Shift Supervisor relief shall be comprised of but not limited to:

   .-                     4 1.1           The oncoming relief as as minimum being briefed on:

4.1.1.1 General Plant Operating conditions and status of the plant. 3 4.1.1.2 Equipment outages and maintenance work in progress. 4.1.1.3 Implementation of special surveillances to meet

                                        .             Limiting Conditions of Operations.

4.1.1.4 Scheduled plant operations 4.1.1.5 Alarms and da'ily chemistry. 4.1.2 Reviewing the Shift Supervis ': 1:; *a hacome aware of L

unusual plant evolutions since his last

                           .1.3           Reviewing the Night Orders Boo       ince his las 4.1.4           Reviewing and signing the Shift Supervisors turnover check list, Attachment A (later). This check list contains the
                        ,                 following items as a minimum:

4.1.4.1 Critical plant parameters (with allowable limits). 4.1.4.2 A checklist entry for the alignment from the console of each system essential to the prevention and mitigation of operational transients and accidents (each criteria and the acceptable

l status). . 4.1.4.3 A listing of any systems and/or components that are in a degra.ded mode of operation permitted by the l 2r Technical Specifications and time of degradation. l List the length of time specified in the Technical l Specifications to an action statement and the actual time that it would be required to be implemented. 4.1.5 The oncoming Shift Supervisor assumes the plant responsibilities when all elements of the relief are completed including the signing of the turnover checklist.

                                                                                                           \~lol

4 OP-0I-003 Revision 0

                                                                                                .             Page 3 of 5 4.2 The Unit Supervisor relief shall be comprised of:

The encoming relief being as a minimum briefed on: 4.2.1.1 General Unit operating conditions and status of the unit. 4.2.1.2 Unit equipment outages and maintenance work in progress. 4.2.1.3 Implementation of special surveillances to meet unit limiting conditions of Operation. 4.2.1.4 Scheduled unit operation 4.2.1.5 Alarms and daily chemistry 4.2.1.6 Any pertinent information from the Night Orders Book. 4.2.2. Reviewing the appropriate Unit Log 4.2.3 Reviewing and signing the Unit Supervisor's turnover check list, Attachment B (later). This checklist itemizes the pertinent points to be addressed for a proper shift turnover. 4.2.4 The oncoming Unit Supervisor assumes the unit responsibility when all elements of the relief are completed including the signing.of the turnover checklist. 4.3, The Assistant Unit Supervisor relief shall be comprised of: 4.3.1 The oncoming relief as a minizam being briefed on: l - l 4.3.1.1 Control room operating conditions and the status of ! the unin. i 4.3.1.2 Unit equipment outages and naintenance' work in progress. 4.3.1.3 Implementation of special surveillances to meet ; unit Limiting Conditions for Operation l 4.3.1.4 Scheduled unit operation f 4.3.1.5 Alarms and daily chemistry 4.3.1.6 Any. pertinent information from the Night Orders Book. - 4.3.2 Reviewing the appropriate Unit Log. I '7 23

   * ' ' .    . - . _ _                                        _ - . . , _ ,               .. . __ . - ._.                         . _ . P"

zrl- .. OP-0I-003 Revision 0 Page 4 of 5 4.3.3 Reviewing and signing the Control Roc.e Operations Turnover Checklist, Attachment C (later). This. checklist contains the following items as a minimum: 4.3.3.1 Critical unit parameters (with allowable limits) 4.3.3.2 An item to check the aligoment from the console of

            ,                                       each system essential to the prevention and mitigation of operational transients and accidents (each criteria and the acceptable status).

4.3.3.3 List any systems and/or components that are in a degraded mode of operation permitted by the. Technical Specifications and time of degradiation. List the length of time specified in the Technical Specifications to an action statement and the acutal time that it would be required to be implemented. 4.3.4 The oncoming Assistant Unit Supervisor assumes the unit control room responsibility when all elements of the relief are completed including the signing of the turnover checklist. 4.4 The Plant Control Operator relief shall be comprised of: 4.4.1 The oncoming relief as a minimum being briefed on: 4.4.1.1.. Control room operating conditions and the status of the unit. 4.4.1.2 Unit equipment outages and maintenance work in progress. 4.4.1.3 Implementation of special surveillances to meet Limiting Conditions for Operations 4.4.1.4 Scheduled unit operation f 4.4.1.5 Alarms.and daily chemistry 4.4.1.6 Any pertinent information from the Night Orders Book. 4.4.2 Reviewing and signing the appropriate unit log. 4.4.3 Reviewing the Control Room Operators turnover checklist.

4.4.4 The oncoming Plant Control Operator assumes the position responsibility when all elements of the relief are complete including the signing of the appropriate Unit Log.

4.l- I .. OP-0I-003 Revision 0 Page 5 of 5 4.5 ' The Nuclear Plant Operator / Auxiliary Systems Operator's relief shall be comprised of: The oncoming relief as a minimum being briefed within their area of responsibility on: l,4.5.1 4.5.1.1 Status and condition of equipment and systems. 4.5.1.2 Outages and maintenance work in progress for equipment and/or systems. 4.5.1.3 Scheduled equipment operation. 4.5.1.5 Unusual equipment conditions. 4.5.1.6 Any pertinent info mation from the Night Orders Book,.

                   .         4.5.2       Reviewing and signing the appropriate equipment logs.

4.5.3 Re' viewing and signing the appropriate NP0/ASO Turnover Checklist, Attachment D (later). This checklist itemizes the pertinent point to be addressed for a proper shift turnover. 5.0 Records The turnover checklists generated as a result of this instruction are not permanent records. The checklist for a turnover shall be maintained until the subsequent turnover is complete. l l i l h $-

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                                                                .           INSTRUCTION APP                                  Al FORM
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W ' OPERATIONS INSTRUCIION f ffective Date 1I v I I TEMPORARY INSTRUCTION J -

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Instruction Number OP-0I-012 , Page 1 of 4 Instruction Title LOCKED COMPONENT ,

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Prepared by Fred Graber Approved by Date Supervisor of Operations 1.0 PURPOSE The purpose of this instruction is to provide a means for positive control of locked components including the methods for locking different types of ~

                               . components.

2.0 RESPONSIBILITY - 2.1 The Supervisoi"8f Operations is responsible for ensuring this

                                             , instruction meets the requirements set forth in government regulations.                                                               -
                       .. 2.2 The Unit Supervisor is responsible fo'r enstiring the control of. locked components follows the guidelines in this instruction.

3.bREFERENCIS -

NUREG 0660 Section II.E.4.2. .

4.0 PRdCEDURE

4.1.- Locke,d components are identified but not limited to any of the

                           .                 following sources:

4.1.1 P&ID's

4'.1. 2 Government Iagulations - .

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l i 1 i OP-0I-012 Revision 0

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      .                 4.1.3         Special tests 4.1.4         Supervisor of Operations Directions 4.1.5         Special or other plant procedures.                             -

4.2 A component is considered locked when the normal means of operating that component is prevented in a positive way. 4.3 The methods used depends of the type of ce=ponent and includes but not limited to any of the following: 4.3.1 Chain and key lock 4.3.2 Locking an installed device 4.3.3 Breaker racted in the desired positica and key locked 4.4 The method for 2ocking a component shall be as fallows: 4.4.1 Motor Operating Valves (MOV's) 4.4.1.1 The valve.is placed in the desired pesition. 4.4.1.2 The breaker is then placed in the open position and keylocked to prevent closing. 4.4.1'.3' A chain and lock is placed cn the local valve to prevent sacual movement of the valve. 4.4.2 Air Operated Valves 4.4.2.1 Air cperated valves may only be locked in their

                                  .                     failed positions.

4.4.2.2 Isolate and lock close, by chain and key lock, the

                                                       -air supply valve.

4.4.2.3 Allow air pressure to bleed off by disconnectinr,- the supply line to the valve and when the valv". reaches the desired position, reconnect the supply line. 4.4.3 Solenoid Operated Valves (SOV's) 4.4.3.1 Solenoid operated valves are not visually locked and cannot be locked in a position other than the failed positicn.

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f ., OP-0I-012 Revision 0 Page 3 of 4 4.4.3.2 Solenoid valves that need to be locked shall have their supply breaker opened and a protective device installed on the breaker control switch to prevent reclosing. 4.4.4 Manual Valves -

    .                                4.4.4.1      The valve is placed in the desired position.

4.4.4.2 A chain and lock is placed on the valve in such a way to prevent manual movement. 4.4.4.3 For valves with installed locking devices, a key lock will only be necessary co ensure positive control over the position of the valve. 4.4.5 Breakers (480V and above) 4.4.5.1 Breakers shall only be locked in the open position. 4.4.5.2 The breaker shall be opened or racked out. s 4.4.5.3 A key lock will be placed in the installed locking device. 4.4.6 Breakers (below 480V) 4.4.6.1 Breakers shall only be locked in the open position. 4.4.6.2 'The breaker shall be opened. 4.4.6.3 A protective device will be installed on the breaker such that it prevents the breaker from being reclosed. 4.5 The method for locking any other component not listed above shall come from appropriate personnel and be approved by the . Supervisor of Operations or his designated alternate. 4.6 Control of Locked Components 4.6.1 Locked components shall be identified by system using SUSO

Form (later) and will include location ~, date & time installed

                    /                or removed and signatures for individuals performing or i             -( ' 1     verifying the test.

f 4.6.2 ' A seperate SUSO Form shall be used to list all components by system that are required to be periodically checked. This

                                     ' form will include component, frequency of the check, date and

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OP-0I-012 Revision 0

                                                                      .              Page 4 of 4 time checked and signatures for individuals performing or verifying the check. These forms shall be maintained with the above forms in a log book.

4.6.3 This log shall be maintained in the control room under the control of the Unit Supervisar. 4.6.4 If a dual verification is required when installing or checking a lock on a componer.., a second qualified individual shall independently check it and sign the apprcpriate space on the SUS 0 forms. 5.0 RECORDS 5.1 The completed SUSO forms used for installing or removing locks on components shall remain in the Locked Component Log in the control room. 5.2 The completed SUSO forms used to verify periodic checks will be kept with the Locked Component Log for (later) time and then sent'to Document Control Center. f j - I I l l r t

SSES-FSAR 6.2.1.1.3.3.1.5 through 6.2.1.1.3.3.1.7. Results for this accident are shown in Figures 6.2-2 through 6.2-9. A chronological sequence of events for this accident from time zero is provided in Table 6.2-8. 6.2.1.1.3.3.2 lain Steamline Break _ The assumed sudden rupture of a main steamline between the reactor vessel and the flow limiter would result in the ma ximum flow rate of primary system fluid and energy to the dryvell. This would in turn result in the maximum drywell differential pressure. The sequence of events immediately following the rupture of a main steamline between the reactor vessel and the flow lia'.te r ha ve been determined. The flow in both sides of the break wi1.1. accelerate to the maximum allowed by the critical flow considerations. In the side adjacent to the reactor vessel, the flow will correspond to critica.1 flow in the steamline break area. B lo wdow n through the other aide of the break will occur because the steamlines are all interconnected at a point upstream of the turnine by the bypass neader. This interconnection allows primary system fluid to flow from the three unbroken steam lines, through the header, and back into the drywell via the broken line. Flow will be limited by critical flow in the steamline flow restrictor. The total effective flow a rea is given in Figure 6.2-10 which is the sum of the steamline cross-sectional area and the flow restrictor area. A slower closure rate of the isolation valves in the btrken line would result in a slightly longer time before the total valve area of the three unbroken lines equals the flow limiter area in the br (en line. The effective break area in this case would star to reduce at 4.35 seconds as demonst rated on Figure 6. 2-10. The peak drywell pressure occurs af ter the reduction in effective break area and i is therefore insensitive to a possible slower closure time of the i isolation valves in the broken line. Subsec tion 6. 2.1.3 provides the mass and energy release rates. Immediately following the break, the total s?.eam flow rate leaving the vessel would be approximately 84t 0 lb/sec, which [ exceeds the steam generation rate in the core of 3931 lb/sec. This steam flow to steam generation mismatch causes an initial i vessel depressurization of the reactor vessel at a rate of approximately 48 psi /sec. Void formation in the reactor vessel water causes a rapid rise in the water level, and it is conservatively assumed that the heter level reaches the vessel steam nozzles one second after the break occurs. The water level rise time of one second is the minimum that could occur under any reactor operating condition. From that time on, a two-phase sixture would be discharged f rom the break. During the first

 '                                     6.2-13

SSES-PSA2 second of the blowdown, the blowdown flow will consist of saturated steam. This steam will enter the containzent in a ' superheated condition of approxima tely 3300F. Figures 6.2-11 and 6.2-12 show the pressure and tesperature responses of the dryvell and suppression chamber during the primary syste: blowdown phase of the steamline break accident. Figure 6.2-12 shows that the drywell at:osphere temperature approaches 3000F at approxi:ately one second of primary systes steam blovdown. At that time, the water level in the vessel will reach the steamline nozzle elevation and the blowdown flow will change to a two phase sixture. This increased flow causes a sore rapid drywell-pressure rise. The peak differential pressure occurs shortly af ter the vent clea ring tra n s ie n t. As the blowdown proceeds, the primary syste: pressure and fluid inventory vill decrease and this will result in reduced break flow rates. As a consequence, the flow rate in the vent s yst e s and the dif ferential pressure between the drywell and suppression chamber begin to decrease. Table 6.2-5 presents the peak pressures, pea k tespe ra ture s and times of this accident as compared to the recirculation line break. Approxi: 1tely 55 seconds af ter the start of the accident, the prisa;i system pressure will have dropped to the drywell pressure and the blordown will be over. At this time the drywell vill contain pri=arily steam, and the dryvell and suppression chamber pressures will stabilize. The pressure difference corresponds to the hydrostatic pressure of vent submergence. The dryvell and suppression pool will remain in this equilibrium condition until the reactor vessel refloods. During this period, the emergency core cooling pumps will be injecting cooling water from the suppression pool into the reactor. This injection of water will-eventually flood the reactor vessel to the level of the steaaline nozzles and the ECCS flow will spill into the dryvell. The water spillage will condense the steam in the dryvell and thus reduce the dryvell pressure. As soon as the drywell pressure drops below the suppression chamber pressure, the drywell vacuus breakers will open and noncondensable gases from the suppression chamber ~ vill flow back into the dryvell until the pressure in the two regions equalize. 1

                             *e 6.2-14                                     -

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SSES-FSAR 6.2.1.1.3.J.J,__ Hot Stdnlhv Accid ent_ Ana lysig This subsection is ,not applicable to Susquehanna SES which is a BWR 4 - {g2.1.1.3.3.4 Intermediate Size 3 eakg The f ailure of a recirculation line results in the most severe _pt,e,ss,ure , loading on, -the dryvell structure. However, as part of the containmene performance evaluation, the consequences of intermediate breaks are also analyzed. This classifica tion covers those breaks for which the blowdown will result in reactor

     -depLeessur-i z a t io n- -a-n d- -o p e r a t i o n o f the ICCS. This section describes the consequences to the containment of a 0.1 sq ft break uelow the RP7 water level.                    This brea k a rea was chosen as being representative of the intermellate size break area range.

Thes,e breaks can involve either reactor steam or liquid blowdown. Pol'l'o wing the 0.1 sq ft break, the drywell pressure increases at

approximately 1 psi per second. This drywell pressure transient is sufficiently slow so that the dynamic ef f ect of the wa ter in the vents is negligible and the vents will clear when the drywell-to-suppression chamber dif ferential pressure is equal to t.he,, vent su.bmergencc hydrosta tic pressure.

     ,fi;Ta' rep -6.-2-14 ,a nd 6.J- 15 show the 'dryweil and suppression
     ~chamb~e'r. ; pressure and temperature response, respectively.                   The
     ,EC.CS .r_e.s.pon.se is , discussed 'n Section 6.3.                Approximately 5
     .sd.co:n.ds a f ter _t he .0.1 sq ft break occurs, air, steam, and wa te r vill s~ tart to fliov from the dryvell to- the' suppression penl: the

- steam will be condensed and the air will enter the suppressicn chamber free space. The continual puriing of drywell air to the suppression chamber will result in a , tual pressurization of

     .both, the v.et_vell and drywell to about ' Ind 32 psig, respectively. The containment will continue to gradually
     ' increase in pressure due to the long-term pool heatup.

The ECCS will be initiated as a result of the 0.1 sq f t break and will provide emergency cooling of the core. The operation of the'se systems is such that the reactor will be depressurized in _approximately 600 seconds. Th is will. terminate the blowdown

     .ptase of the transient.

In addition, the suppression pool end of blowdown temperature vill be the same as that of the DS A because ?ssentially the same amount of primary system energy is released during the blowdown. After reactor depressurization and reflood, water from the ECCS 6.2-15 18a,

SSES-FSA3

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will begin to flow out the break. This flow will condense the drywell steam and eventually cause the dryvell and suppression ' chamber pressures to equalize in the same sanner as following a recirculation line rupture. The subsequent long term suppression pool and containment heat-up transient that follows is essentia lly the sa me as for the recirculation line break. From this description, it can be concluded that the consequences of an intermediate size break are less severe than from a recirculat ion line rupture. 6.2.1.1.3.3.5 Small Sizo 3reaks 62 2.1.1.3.3.5.1__gaactor_Svstem BloyJgyn_ Considerations Seh ThisAsection discusses the containment transient associated with The sizes of primary system small pri=ary systems blowdowns. ruptures in this category are those blowdowns that will not result in reactor depressurization due either to loss of reactor coolant or automatic operation of the ECCS equipment. Following the occurrence of a break of this size, it is assumed that the reactor operators will initiate an orderly plant shutdown and depressurization of the reactor system. The thermodynamic process associa ted with the blowdown of primary system fluid is one of constant enthalpy. If the primary system brect is below the water level, the bicwdown flow will consist of reactor water. Blowdown f rom reactor pressure to the drywell pressure will flash approrizately one-third of this water to steam and two-thirds will remain as liquid. Both phases will be at satura tion conditions corresponding to the dr ywell pressure. If the primary system rupture is located so that the blowdown flow consists of reactor steam only, the resultant steam temperature in the containment is significantly higher than the temperature associated with liquid blowdown. This is because the constant enthalpy depressurization of high pressure, saturated steam will result in superhea ted conditions. For example, decompression of 1000 psia saturated steas to atsospheric pressure will result in 2980F superheated steam (860F of superheat) . A small reactor steam leak (resulting in superheated steam) will impose the most severe tenperature conditions on the dryvell structures and the safety equipsent in the d ryt all. For larger steamline breaks, the superheat temperature in nearly the same as 6.2-16 - i 19 3

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SSES-PSAR 1 f or s mall breaks, but the duration of the high temperature condition for the larger break is less. This is because the larger breaks will depressurize the reactor more rapidly than the orderly reactor shutdown that is assumed to terminate the small break. 6.2 1 1 3.3.5.2 containment Response

     ,For drywell design considerations, the following sequence of events is assumed to occur. With the reactor and containment operating at the maximum normal conditions, a small break occu rs that allows blowdown of reactor steam to the drywell. The resulting pressure increase in the drywell will lead to a high
     -drywell pressure signal that will scran the reactor and activate the containment isolation system. Tne dryvell pressure will continue to increase at a rate dependent upon the size of the steam leak. The pressure increase will lower the water level in the vents until the level reaches the bottom of the vents. At this time, air and steam will start to enter the suppression p oo l. The steam will be condensed and the air will be carried over to the suppression chamber free space. The air carryover will result in a gradual pressurization of the suppression chamber at a rate dependent upon the size of the steam leak.

Once all the drywell air is carried over the suppression chamber,

     . pressurization of the suppression chamber will cease and the
     , system will reach an equilibrium condition. The drywell will contain only superheated steam, and continued blowdown of reactor steam will condense in the suppression pool. The suppression pool temperature will continue to increase until the RSR heat
     -exchanger heat renoval rate is greater than the decay heat release rate.

Recovery Operations l 1 .... 62 1 1.3.3.5.3

     ".The reactor operators will be alerted to the incident by the high drywell pressure signal and the reactor scran. For the purposes of evaluating the duration of the superheat condition in the
     . d ry we ll, it is assumed that their response is to shut the reactor down in an orderly manner using saic condenser while limiting the reactor cooldown rate to 1000F per hour. This will result in the reactor primary system being depressurized within six hours. At this time, the blowdown flow to the drywell will cease and the superheat condition will be terminated. If the plant operators elect to cool down and depressurize the reactor primary systen more Rev. 0 7/78                    6.2-17 lB9

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         !                           SSES-FSA2 f

I rapidly than a t 1000F per hour, then the drywell superheat condition will be shorter. l 6 2 2 1.1.3.1.5.4__2rywo11 Dosion Temcoriture co n sid e ra tion s

   ' For! drywell design purposes, it is assu ed that there is a blowdown of reactor steam for the six-hour ccoldown period. The corresponding design temperature is determined by finding the combination of primary system pressure and drywall pressure that produces the maxi:us superheat te s pe ra tu re. This temperature is then assumed to exist f or the entire six-hou r period. The maximum drywell steam temperature occurs when the primary system is at approximately 450 psia and the drywell pressure is eaxisu:.

For design purposes, it is assu=ed that the drywell is at 35 psig; this results n a temperature of 3400F. 6.2.1.1.3.4 Accident Analysis 9odels 6.2.1.J.3.4.1 _Short Ters _Pressurizat ion Model The analytical models, assumptions, and methods used by General Electric to evaluate the containment response during the reactor blowdown phase of a LOCA are described in Ref s. 6. 2- 1 and 6. 2- 2. 6.2.1.1.3.4.2 .Lono Ter: Cooline_ Mode Once the ap? blowdown phase of the LOCA is ove r, a fairly simple model of the dr ywell and suppression cha ber say be used. l During the long term, post-blowdown containment cooling transient, the ECCS flow path is a closed loop and the suppression pool mass will be constant. Sc h esa tically 4 the cooling model loop is shown on Figure 6.2-10. Since t nere is no change in. sass storage in the systes (the RP7 is ref]Joded during the blowdown phase of the accident), the mass flow r tes shown in the figure are equal, thus:

                                $g = .k = $         (Eq. 6.2-1) o    o
                  .                   6.2-13                                   ~

los?

SSES-PSAR Certain other valves are physically locked in their normal position; access to the keys to the locks is controlled administratively. In other cases, two isolation valves are provided in series to minimize the possibility of inter- or intra- system leakage. Again, such valves are identified in the

        " Function" column of Table 6.3-9.

12 Remote position indication of manual valves which are in the main flowpaths of the ECCS (except for makeup gas supply to the ADS valve accumulators) and which will be innaccessible during normal operation is provided in the control room. Proper administrative controls and/or surveillance testing are relied upon to assure the position of the remaining valves. j.3.3 ECCS PERFORMA.WCE EV A LU AT IO N The performance of the ECCS is determined through application of the 10CFB50 Appendix K evaluation models and then conformance to the acceptance criteria of 10CFR50.46 is shown. N EDO- 2056 6 (Reference 6. 3-2) provides a complete description of the methods used to perform the calculations. These methods are summarized herein. A summary description of the loss-of-coolant accidents is also provided herein. For a complete description of the LOCA events see Refe rence 6.3-2. {' The ECCS performance is evaluated for the entire spectrum of break sizes for postulated LOCAs. The accidents, as listed in Chapter 15, for which ECCS Operation is required are: 15.2.8 Feedwater piping break 15.6.4 Spectrum of BWa steam system piping failures outside of containment 15.6.5 Loss-of-coolant accidents Chapter 15 provides the radiological conseguences of the above listed events. Rev. 17[9/80 6. 3- 2 0e IBio

i SSES-PSAR This page has been intentionally left blank. f l t 1 i i i l i 1 I v Rev. 17, 9/80 6. 3- 20f t i IB7

i ( SSES-FSAR 6.3.3.1 ECCS Bases for Technical Specifica tions ks The maximum average planar linear heat generation rates l calculated in this perf ormance analysis provide the basis for l Technical Specifications designed to ensure conformance with the acceptance criteria of 10CFR50.46. Minimum ECCS functional requirements are specified in Subsections 6.3.3.4 and 6.3.3.5, and testing -m,uirements are discussed in subsection 6.3.4 Limits on minimum suppression pool wa ter level are discussed in Section 6. 2 ( 6.3.3.2 Acceptance Criteria for ECCS Performance The applicable acceptance criteria, extracted from 10 CFR 50.46, are listed and for each criterion, applicable parts of Subsection 6.3.3 where conformance is demonstrated are indicated. A detailed description of the methods used to show complian ce are shown in Heference 6. 3-2. Criteriot 1, peak Cladding Temperature - "The calcula t*d maximum fuel element cladding temperature shall not exceed 22000F." Conformance to Criterion 1 is shown in Subsections 6.3.3.7.3 (Break Spectrum), 6.3.3.7.4 (Design Basis Accide nt) , 6.3.3.7.5 (Transition Break) , 6.3.3.7.6 (S mall 3reak) , and specifically in Table 6. 3-6 (maximum average l planar linear heat generation rate, maximun local oxidation, ( .. and pes k cladding temperature versus exposure) . Eriterion 2. Marisus Claddinq Oxidation - "Th e calcula ted total local oxidation of the cladding sh all nowhere exceed 0.17 times the total cladding thickness before oxidation.d Conformance to Criterion 2 is shown in Figure 6.3-10 (brea k spectrum plot) , Table 6.3-6 (local oxida tion versus e xposure) a nd in Ta ble 6. 3- 3 (break spectrum summary) . Eriterion 3, Marinus Hydrogen Generation "The calculated total amount of hydrogen generated f rom the chemical reaction of the cladding with water or steam shall not exceed 0.01 times the hypothetical amount that would be generated if all the metal in the cladding cylinder surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react." Conformance to Criterion 3 is shown in Table 6.3-6. l Criterion 4 Coolas .e Geometry " Calculated changes in core geometry shall be such that the core remains amenable to cooling." As described in Reference 6.3-2, section III, conformance to Criterion 4 is demonstrated by conformance to criteria 1 and 2. REV. 4, 1/79 6.3- 21

SS ES-FFS D Criterion 5, Long-Tees Cooling "After any calculated successful initial operation of the ECCS, the calculated core temperature shall be maintained at an acceptably low value ' and decay heet shall be rezovec for the extended period of time required by the long-lived radioactivity remaining in the core." Conformance to criterion 5 is demonstrated generically for General Electric BWRs in Reference 6.3-2, Section III.A. Briefly summa rized, the core remains covere to at least the jet pump suction elevation and the unec' v ered region is cooled by spray cooling and/or by stean generated in the covered part of the core.

6.3.3.3 Single Failure Considerations The functional consequences of potential single failures, in the ECCS are discussed in Subsection 6.3. 2. 5. There it was shown that all potential single failures are no more severo than one of the single failures identified in Table 6.3-5. It is therefore only necessary to consider each of these single f ailures in the emergency core cooling system performance a naly ses. For large breaks, failure of *he LPCI injection valve directing water to the unbroken loop is .ne most severa f ailure. A single failure in the ADS (one ADS valve) has no effect in large breaks. Therefore, as a matter of calculational convenience, it is assumed in all calculations that one ADS valve fails to operate in addition to the identified single failure. l This assumption reduces the number of calculations required in l the performance analysis and bounds the effects of one ADS valve feilure and HPCI f ailure by themselves. The or.ly eff ect of the ascused ADS valve failure on the calculations is a small increase (on the order of 1000F) in the calculated temperatures following small breaks. 6.3.3.4 System Performance Durino the Accident In general, the system response to an accident can be described as:

1) receiving an initiation signal,

2) a small lag time (to open all valves and have the pumps up to rated speed) , and

3) finally the ECCS flow entering the vessel.

Key ECCS actuation set points and time delavs for all the ECC systems are provided in Table 6.3-2. The minimization of the REV. 4, 1/79 6.3- 22 (B1

l SS2S-FSAR delay frcs the receipt of signal until the ECCS pumps have reached rated speed is limited by the physical ccnstraints on accelera t ing the dieseJ-qenerators and pumps. The delay time due ! ( '" to valve motion la the cese of high pressure system provides a I suitably ccnservative a;'owance

                                          .        for valves available for tnis           l application. In the case of the low pressure system, the time            I delay for valve motion is such that the pumps are at rated speed prior to the time the vessel pressure reaches the pump shutoff pressure.

The flow' delivery rates analyzed in Subsection 6.3.3 can be determined from the head-flow curves in Figures 6.3-3, 6.3-6, a nd 6.3-7 of Subsection 6.3.2 and the pressure versus time plots discussed in Subsection 6.3.3.7. Simplified piping and instrumentation and functional control diagrams for the ECCS are provided in Subsection 6.3.2. The operational sequence of ECCS for the DBA is shown in Table 6.3-1. Operator action is not required, except as a monitoring function, during the short term cocling period following the LOCA. During the long term cooling period, the operator will take action as specified in Subsection 6.2.2.2 to place the containment cooling system into operation, j,J,12 5 Use of Dual Function Components for ECCS (' ' - With the exception of the LPCI systes, the systems of the ECCS are- designed to accomplish only one f unction: to cool the reactor core following a loss of reactor coolant. To this extent, components or portions of these systems (except for pressure relief) are not required for operation of other systems which have emergency core cooling functions, or vice versa. Because - Ather the ADS initiating signal or the overpressure signal opens the safety relief valve, no conflict exists. The LPCI subsystem, however, uses the R'HR pumps and some of the BBR valves and piping. When the reactor water level is low, th e LPCI subsystea has priority through the valve control logic over the other RHR subsystems for containment cooling, shutdown cooling, or steam condensing. Immediately following . LOL % the RHR system is directed to the LPCI mode. 523232f___ limits on_ICCS_Systeg Parameters The limits on the ECCS systes parameters are discussed in S ubsection s 6. 3. 3.1 and 6.3. 3.7.1. Any number of components in any given system may be out of service, up to and including the entire systes. The maximum 6.3-23 130

SSES-FSAR l allowable out of service time is a function of the level of redundance and the s?ecified test intervals as discussed in 3 Section 15A.S.

62 )2]27_ ECCS Analyses for_LOCA

    .52 232221__ LOCA Anal 22_is Procedures and Input __VQriable; The procedures approved for LCCA analysis conformance calculations are described in detail in Reference 6.3-2.      These procedures were used in the calculations documented in Subsection 6.3.3. For convenience, the four computer codes are triefly
,    described below. The interfaces between the codes are shown schematically in Piqures II-2a, II-2b, and II-2c ir. the
     " Documentation of Evaluation Models" section II.A of Reference 6.3-2. The maior interfaces are briefly noted below.

SHORT-TERM THERMAL HYDRAULIC MODEL (LAMB) The LAMS code is a model which is used to analyre the short-term thermodynamic and thermal-hydraulic behavior of the ccolant in the vessel during a postulated LOCA. In particular, LAMB predicts the core flow, core inlet enthalpy and core pressure during the early stages of the reactor vessel blowdown. For a detailed description of the model and a discussion regarding sources of input to the model refer to the " LAMB Code Documentation" Section II. A.3 of Reference 6.3-2. TRANSIENT CRITICAL POWEB MODEL (SC AT) The SCAT code is used to evaluate the short-term thermal-hydraulic response of the coolant in the core during a postulated LOCA. SCAT receives input from LAMB and analyres the convective heat transfer process in the thermally limiting fuel bundle. For a detailed description of the model and a discussion regarding sources of inout to the model refer to the " SCAT Code Documentation" Section II.A.4 of Reference 6.3-2. LC3G-TERM THERMAL HYDRAULIC MCDEL AND RETILL/REFLOOD MODEL ( (FAFE/REFLCOD) The SAFE /REFLOOD code is a model which is used to analyze the long-term thermodynamic behavict of the coolant in the vessel. The SAFE /REFLOOD code calculates the uncovery and reflooding of the core and the duration of spray cooling and (f cc small breaks) the peak cladding temperature. ' For a detailed description of the model and a discussion regarding sources of input to the model refer to the " SAFE code 6.3-24 i

i SSES-PSAR l and! HEFLOOD code documentation" Sections II. A.1 and II. A.2 of e . Reference 6.3-2, and References 6.3-3 and 6.3-5. !11 CORE HE ATUP MODEL (CHASTE) The CHASTE code solves the transient heat transter equations for specific axial planes or each fuel bundle type, for large breaks. , CHASTE receives input tros SCAT, SAFE and REFLOOD and calcula tes cladding tempera tures and local cladding oxidation during the

          ' entire LOCA transient. For a detailed description of the CHASTE model and a discussion regarding sources of input, refer to the
           " CHASTE code documentation" Section II. A.5 of Reference 6. 3-2, and R eferences 6. 3-3 and 6.3-5.                                     l11 The signiticant input variables used by the LOCA codes are listed in To ble 6. 3-2 and tigure 6.3-9.                                   l4 6,3.1. 7. 2   Accident De scri p tion _

A detailed description of the LOCA calculation is provided in Reference 6.3-2. For con venience, a short description of the major events during the design Dasis accident (DBA) is included here. Immediately after the postulated double-ended recirculation line { break, vessel pressure and core flow begin to decrease. The initial pressure response (Figure 6. 3-11) is governed by the l4 closure ot the main steam isolation valves and the relative values' of energy added to the system by decay heat and energy removed tros the system by the initial blowdown ot fluid from the downcomer. The initial core flow decrea se (Fig ure 6.3-12) is l4 rapid because the recirculation pump in the broken loop ceases tv pump almost immediately because it has lost suction. The pump in i the intact loop coasts down relatively slowly. This pump l coastdown governs the core tlow response for the next several I seconds. When the jet pump suctions uncover, calculated core flow decreases to near zero. When the recirculation pump suction nozzle uncovers, the energy release rate from the break increases significantly and the pressure begins to decay more rapidly. As a result of the increased rate of vessel pressure loss, the initially subcooled water in the lower plenum saturates and flashes up through the co re, increasing the core flow. This lower plenum flashing continues at a reduced rate for the next

j. several seconds.

Heat transter rates on the tuel cladding (Figure 6.3-17) during 4 the early stages at the blowdown are governed primarily by the core flow response. Nucleate bolling continues in the high power pla ne until shortly after jet pump uncovery. Boiling transition l follows shortly atter the core flow loss that results from jet REV. 11, 7/79 6. 3- 25

\Q3

l I I l !' SSES-FSAR ] pump uncovery. . Film boiling heat transter rates then apply, with , increasing heat transfer resulting from the core flow increase J' : 4 l t I. i i + ; 4 I

i

1 1 i f i r. I, i-t i r V L.

6. - 25a REVJ,_11, 7/79 19 3

6:. . .- . .~..-....-._;...-. . - . . . . _ - _ _ - . _ - _ _ _ - _ _ . - _

t SSES-FS.Ut i

\,s

> THIS PAGE HAS BEEN IhTEhTIONALLY LEFT BLiSK. - h I l I t l C i i I l l t ) I i I i i I l 6.3-25b I34

I l i i SSES-PSAR during the lower pienus flashing period. Heat transfer then 'i slowly decreases until the high power axial plane uncovers. At that time, convective heat transfer is assumed to cease. 4l Water level inside the shroud (Figure 6.3-15) remains high during the early stages of the blowdown because of flashing of the water in the core. After a short time, the level inside the shroud has decreased to uncover the core. Several seconds later the ECCS is actuated. As a result the vessel water level begins to increase. Some time later, the lower plenum is filled, and the core is subsequently rapidly recovered. 4l The cladding temperature at the high power plane (Figure 6. 3-18) decreases initially because nucleate boiling is maintained, the heat input decreases and the sink temperature decreases. A rapid, short duration cladding heatup follows the time of boiling transition when film boiling occurs and the cladding temperature approaches that of the fuel. The subsequent heatup is slower, being governed by decay heat and core spray heat transfer. F # 9slly the heatup is terminated when the core is recovered by tue accumulation of ECCS water. 6.3 2 3.7.3__ Breag_Spectgnm Calculations 4 A complete spectrum of postulated break sizes a nd locations is considered in the evaluation of ECCS performance. The general analytical procedures for conducting break spectrum calculations are discussed in Section III.B o f Reference 6. 3-2. For ease o f reference, a su= mary of all figures and tables presented in Subsection 6.3.3 is shown in Table 6.3-4. A summary of the results of the break spectrum calculations is shown in tabular form in Table 6.3-3 and graphically in Figrre 16 l 4l 6.3-10. Conformance to the acceptance criteria (PCT 5 22000F, local oxidation 517% and core wide metal-water reaction 51%) is demonstrated. Details of calculations for specific breaks are included in subsequent pa ragra phs. For convenience in describing the LOCA phenomena, the break spectrum has been separated into three regions: small breaks, intermedia te breaks, and large breaks. The selection of the break sizes to be included in each region is dependent on the most limiting single f ailure and the ECCS evaluation sethod used. 4 The s mall break region is defined as that portion of t'.e break spectrum where the high pressure coolant injection (HPCI) is the most limiting single failure. In this region, the small break methods (SBM) are used. The intermediate break region is defined as that portion of the break spectrus ap to the transition break where the LPCI y Rev. 16, 7/80 6. 3- 26

lW

i SSES-FSAR injection valve is the most limiting sing le failure. The

,    transition break is defined as the 1.0 f t2 break size. This

( break size has been chosen in order to be consistent with previous analyses. The calculational techniques employed in the S85 are intended to conservatively model small reaks only. As the break size increases (> 1. 0 f t2) , the SBM becomes overly conservative and does not appropriately describe some of the phenomena (e.g., radiation heat transfer, blowdown heat trans f er) . The transition break has been analyzed with both the large and small break methods with the same single failure to allow comparison between the methods. In the intermediate break region, small break methods are used. The large break region is defined as that portion of the break spectrum between the transition break and the DBA. The DBA is defined as the complete severence of the largest pipe in that portion of the system which yields the highest peak cladding temperature when the most limiting single failure is assumed. The most limiting single failure in this region is the failure of the LPCI injection valve. In the large break region, large break methods are used. As demonstrated in Table 6.3-5, plants which incorporate the LPCI modification have a different complement of ECCS components available depending on break location (recirculation discharge or suction piping) and single failure assumptions. Analyses are performed for both locations to determine at which location the DBA occurs. The other location is defined as the second most (' limiting location and treated as a large break. For this analy sis, large break methods are used. 12122 7.4 Large Recirculation Line Break Calculations In this region, the vessel depressurizes rapidly and the HPCI has an insignficant effect on the event. Consequently, f ailure of the core spary or LPCI is more severe. Analyses have demonstrated that f ailure of the LPCI is the most severe failure among the low pressure ECCS because, unlike the core spray which must pass through the CCFL regions at the top of the core, LPCI is injected into the lower plenum through the jet pumps. Thus, the LPCI injection valve is the worst single f ailure in the large break region. This is the case for a break occurring in either the suction or discharge piping. For a brea k in the discharge piping, this failure results in no LPCI flow, and for a suction line failure, LPCI flow is minimized. Comparison of the calculated PCTs for the maximum size break 1.1 the suction and discharge piping determines which is the DBA and which is the second most limiting location. The discharge break is the most limiting location (Table 6. 3-3) . The characteristics REV. 4, 1/79 6.3- 27 l9(o

S S ES-FS A R that determine which is the most limiting break area at the DBA location are:

1. The calculated hot node reflooding timo;

2. The calculated hot node unco ver y time, and

3. The time of calculated boiling transition.

The time of calculated boiling transition increases with decreasina break size, since jet pump suction uncovery (w hich leads to bailing transition) 1. determined prima rily by the creak size for a pa rticular plant. The calculated hot node u ac o ver y time also generally increases with decreasing break si s, as it is primarily determined by inventory loss during the blowdown. The hot node reflooding time is determined b y a number of interacting phenomena such as depressurization rate, counter current flow limiting, and a combination of available ECCS. The period between hot node uncovery and reflooding is the period when the hot node has the lowest heat transfer. Hence, the break that results in the longest period during which the hot node remains uncovered results in the highest calculated PCT. If two breaks have similar times during which the hot node remains uncovered, then the larger of the two breaks will be limiting as it would have an earlier boiling transition time (i. e. , the larger break would have a more severe LAMB / SCAT blowdown heat transfer analysis). Figure 6.3-73 shows the variation with break size of the calculated time the hot node remains uncovered. Based on these calcula tions, the 0.68 DBA was determined to be the break that results in the longest time the hot node remains uncovered. Because of the decrease in the time of calculated boiling transition between the DBA and the 0.68 DBA, a break area larger 6.han the 0.68 DBA could be the most limiting break (result in highest PCT) . To cover this possibility, tt:2 conservative approach of applying the LAMB /SC AT results f or the 0.80 DB A with I the 0.68 DB A SAFE /REFLOOD analysis was taken. This results in a conservative (earlier) time of calculated boiling transition being combined with the longest time of hot node uncovery and assures identification of the so;t limiting case. Important variables f rom this analysis are shown in Figures 6.3-11 thorugh 6. 3-20. These variables are: (1) Core average pressure as a function of time from LAMB. (2) Core flow as a function of time from LAMB. l (3) Core inlet enthalpy as a function of time from LAMB. l s. REV. 4,1/79 6.3- 28

      ,                                    SSES-PSAR (4)    Minimum critical power ratio as a function of time f rom SCAT.

(S) Water level as a function fo time f rom S AFE/REFLOOD. (6)' Pressure as a function of tita from SAF'E/REFLOOD. (7) Fuel rod convective heat transfer coefficient as a function of time from CHASTE. (8) Peak cladding temperature as a function of tima from CHASTE. (9) Averag'e fuel temperature as a function of time f rom CHASTE. (10) PC7 rod internal pressure as a function of time from CH 4,STE. . The maximum average planar linear heat generation rate, maximum local oxidation, and peak cladding temperature as a f unction of exposure f rom the CH ASTE analysis of the 0.6 8 CBA are show in Table 6.3-6. The DBA (the complete severence of the recirculation discharge piping) results are shown on Figures 6.3.3.21 through 6.J.J.28. The second most limiting location for the LOCA is the

k. . recirculation suction line. Figure 6.3-74 shows the variation with break size of the calculated time the hot node remains uncovered for a recirculation suction line break. Based on t hese calculations, the maximum recirculation suction line break was determined to be the suction line break which yields the highest peak cladding temperature. The results of the ma ximum berak in this piping are shown on Figures 6.3.3-29 through 6.3.3-36.

l 6.3.3.7.5 Tra nsiti2n Recircula11on_line Bgeak Calculationg l Important variables f rom the analysis of the t ra nsitio n (1.0 f tz) break are shown in Figures 6.3-37 through 6. 3-48. Theso l variables are:

1) Core average pressure (large break methods) as a function of time from LAMB.

(2) Core flow (large break methods) as a function of time from

                                                                       ~    ~

LAMB. REY. 4, 1/79 6.3- 29

                                                                                   $9b i

i SSES-FSAW (3) Core inlet enthalpy (large break methods) as a function of time from LA33. -

4) Minimum critical power ratio (large break methods) as a function of time from SCAT.

5) Vater level (large break met hod s) as a function of time from SAFE /REFLOOD.

         *6) l    Pressure (large break methods) as a function of time f rom S A F E/R EFL OOD.

7) Fuel rad convective heat transfer coefficient (large break methots) as a function of time from OH ASTE.

8) Peak cladding temperature (large break method s) as a function of time from CHASTE.

9) Water level (small break met ho d s) as a function of time from SAFE /REFLOOD.

10) Pressure (small breaks methods) as a function of time from SAFE /REFLOOD.

11) Convective ~ heat transfer coefficients (small break methods) as a function of time from REFLOOD.

4 12) Peak cladding temperature (small break methods) as a function of time from HEFLOOD. 17 l 6sl431225-__lBall_ ERG 1EGuligion Lin e Btga k_Calculatigns Important variables from the analysis of the small break yielding 4 the highest cladding temperature are shown in Figures 6.3-49 thru 6.3-52 These variables are:

1) Water level as a function of time from SAFE /REFLOOD.

2) Prer2'2re as a f unction of time from S AFE/REFLOOD.

3) Convective heat transfer coefficients as a function of time j from REFLOOD.

4) Peak cladding temperature as a function of time from g REFLOOD.

The same variables resulting from the analysis of a less limiting 4l small break are shown in Figures 6. 3-53 thru 6. 3-56. m Rev. 17, 9/80

                                                .- 0 I93

I - SSES-FSAR E 6,J,3.7.7 Calculations for_ Other Break Locations Reactor water level and vessel pressure from SAFE /REFLOOD aal peak cladding temperature and convective heat transfer coefficients from REFLOOD are shown in Figures 6.3-57 thru h.3-60 4 for the core spray line break, Figures 6.3-61 thru 6. 3-o4 fu the feedwater line break, and in Figures 6.3-65 and 6.3-66 for rho main steamline break inside the containment. These plots tre taken from the lead plant analysis for this proiuct line. An analysis was done for the main steamline break ou tside '30 containment. Reactor water level &nd vessel pressure from SAFE /REFLOOD and peak cladding tenporature and convective hett transfer coef ficients f rom REFLOOD are shown in Figures 6. 3-69 14 through 6.3-72. I 6M . 8 LOCWn,alysis Conclusions Having shown compliance with the applicable acceptance criterta of Stibsection 6.3. 3.2, it is concluded that the ECCS will petfora its f unction in an acceptable manner and meet all of the

 ,~         10CFH50.46 acceptance criteria, given operation a t or below the

(. sarimum average planar linear hea t generation ra*es in Taole u . .l- 4 6. 6.3.4 TESTS A ND_ INSPECTIONS 6.3.4.1 JCCS Performance Tests All systems of the ECCS are tested for their operational ECCS function during the pre-operational and/or startup test p ro Jra m. Each componen t is tested for power source, range, direction of rotation, set point, limi t switc h set ting, torqu e s sit ch ner

In.J.

etc. Each pump is tested for flow capacity for comparison wi'.h vendor data. (This test is also used to verify flow mea s u rin .; c apa b ilit y) . The flow tests involve the same suction and discharge source; i.e., suppression pool or con.tetisar -i t o r t .; - tank. All logic elements are teste.1 in.liva lually and then sa a s ya-om to verify complete system responau to eme rge ncy signa ls inela. tin ; Rev. 17, 9/80 6.1-30a M

SSES-FSAR a) Fan failure, each non-safety related fan b) High pressure drop across filters. c) High or low pressure in.the zone or one of the poten tially contamina ted areas d) Low fit temperature entering cooling c' oils (freeze protec tion) , on coils handling outside air e) High pressure differential across' the upstream HEPA filter bank of each filter train f) Pre-ignit io t and ignition charcoal absorber temperatures q) High temperature dif f erential across charcoal absorber bed All instruments and' control's performing safety related functions are qualified to the Seismic Category I requirements. The redundancy and separation of instrumentation and controls conforms to the redundancy and separation of the equipment they control or monitor.

    /     9.4.2.2    Safety _!aldigd_and_gCIC Air cooling _gystems
 . \.                           .

The following equipment and systems are covered under this heading:

1) The RHB, HPCI, RCIC, and core spray pump rooms unit coolers.

               '2)   Emergency SWGR cooling units with associated ductwork.

\ 9.4.2.2.1 Design Dagis. The above cool'ing systems are designed to: a) Maintain' temperature at a maximum of 1300F in the ECCS i pump rooms after a DBA. b) Maintain emergency SWGR room temperature below a maximuk

of 1300 F 'af ter a DBA and 1040 F during plant normal operation. The coolers, asso.ciated ductwork, and supporting structures are safety related and are Seismic Category I. .

s 9.4-27

                          ~
                                                                               @t

SSES-PSAR 9 322 23]__Sv0t*M Doscription G222211 Tho sifotv related air cooline systems are snown on the reactor b;;lling, Ione I, air flow diagram (Fiqure 9.4-4). See Iable 9.4-4 for the system design parameters. All coolers are supplied with emercency service water. The emergency SVGR room cooling units also contain chilled water cooling coils, for use during normal operation. The controls and instrumentation associated with each system are an integral oart of that system. The instruments and controls are shown on Figure 9.4-6. ICCS and PCIC Eugg_3oog_gnit_ Coolers . Each ECCS and RCIC pump room unit cooler recirculates and cools the respectiva room air, and is capable of carrying the following cooling loads: a) RHR and core spray pump room coolers - total cooling load associated with operation of a single ECCS pump (one out of two in each room) b) RCIC and HPCI pump room coolers - the total room cooling load. Nach unit cooler consists of a cabinet with a cleanable emergency service water cooling coil, a direct drive vane-axial fan mounted

          'outside of the cabinet, and except for RHR pump room coolers, a sheetmetal transition section with a supply air register.        The unit coolers are mounted adjacent to the pumps they serve, and they start automatically when the pump starts.       Each cooler is also provided with a hand switch in the control room for manual operdtion. During plant normal operation, the reactorebuilling ven*;ilation system is used to maintain the design conditions in the ECCS and RCIC pump rooms (see Subsection 9.4.2.1) .

Each pair ot 3CIC and itpCI room coolers is providad with additional hand selector switches in the control room f or selection of t.he lead and standby units. In addition each cooler is provided with a temperature switch to transfer to the standby l unit on detection of high air temperature at the discharge of the running unit and to annunciate this condition in the control room. EmercengI_SWGR_and Load _ContgI_ Room _Cooli_ng Units Two 100 percent capacity cooling units are provided for the emergency SWGR and load center rooms. Each unit consists of a cabinet with the following com ponen ts, in'the direction of sne air flow: crefilters, emergency service water cooling coil, a 9.4-28 1 l ,

SS ES- FS A R chilled wa ter cooling coil, and a belt driven centrif ugal f an. 7 ( The air discha rge of each u nit is connected to a common supply air duct. Air enters the unit inlet directly from the surrounding area. Duct penetrations for the supply air, and the transter grilles f: tha retura 11: to and fra: eaca roo:, are redundant and parallel, and am f urnished vi.th fire protection dampers. During normal operation chilled water flow through the coil is modulated by a three-way mixing valve controlled by the discharge air temperature controller. After a DBA the chilled water is not available, and the emergency snevice water cooling coils are used. Emergency service water flow through the coils is unrestricted with no supply air temperature or water flow control. only one cooling unit is running during plant normal or emergency operation. When loss cf air flow or high discha rge air temperature f rom the running unit is detected that unit's dischat4e damner closes and the fan is tripped. The standby unit starts a utomatically. Both the high temperature and the running unit trip are alarmed in the control room. Each unit is provided with a three position (a u t o, sta r t, stop) hand switch in the control room, a flow switch and a temperature

   ,-     switch both mounted on a common supply air duct.

Av 9.4.2 223 Sa f et y ' Ev31uation For failure. mode and effect analysis see Table 9.4-5, for safety related modes of operation. All units, ductwork and supports, and other systems components,

except for discharge air temperature pneumatic control loop, meet l

Seismic Category I requirements and single failure criteria.

l 9.4.2 2 4 Tesis and Inspectiong With the exception of items (4) and ('7 ) through (9) all tests and j inspections described in Table 9.4-1 apply to the coolers and i associated ductwork system. The system will be preoperationally tested in accordance with the requirements of Chapter 14. 4 a ( 9.4-29

                    ~
                                      .                        P80RORR E                   6e

SSES-FSAR

9. 4. 2. 2. 5 In .s t r ta an t s t io n_Heg u irem a n t s The discJssio1 for inst'rumenta tion say be f ou nd in Subsection 9 . u . 2. ; . 5.

9.4.j_ hADWASTj_FLILDING_VXE_TILATION SYSTjn 1.s.4.3 l- - - D421 4nddaes The Radvaste Building HVAC systems have no safety'related functions. . The Radvaste Building Heating, Ventilating, and Air ConditiGning (HVAC) systems are-designed to operate during normal operations and accomplish the following objectives: a) Provide a supply of filtered and tempered outside air to all areas of the building b) Maintain airflow f rom areas of lesser to a reas of greater ootential contamination c) Maintain the building spaces below the following sazimum tem pe ra tures: General Areas 1000F Eq uipme nt - Rooms 1040F Tank Rooms 1200F

                'd)            Maintain the building minimum tempera ture of 400F e)            Maintain the building at a slightly negative pressure to minimize erfiltration to the outside atmosphere j                 f)            Filte,r through charcoal and particulate filters all air

exhausted from

                           'The tank' vent system I

Liquid radwaste filters Liquid radwaste demineralizer, Spent resin tank 9.4-30 L O a L

                                                                           .                   M h .

O}}

ML20003C860: Difference between revisions

Latest revision as of 15:23, 15 March 2020

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Dear.Mr. Youngblood:

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ML20003C860: Difference between revisions

Latest revision as of 15:23, 15 March 2020

Text

Dear.Mr. Youngblood:

Subject:

Subject:

Subject:

GENERAL COMMENT

SUMMARY

Attachment:

2.0 Scope

3.0 REFERENCES

3.0 REFERENCES

1.0 Purpose

2.0 Respensibility

References:

5.0 Records

3.0 REFERENCES

3.0 REFERENCES

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