ML19254D781

Forwards Response to DB Vassallo 790927 Ltr Re NRC short-term Requirements Resulting from TMI-2 Incident

ML19254D781
Person / Time
Site:	North Anna
Issue date:	10/25/1979
From:	Stallings C VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.)
To:	Harold Denton, Vassallo D Office of Nuclear Reactor Regulation
References
806-092779, 806-92779, NUDOCS 7910300140
Download: ML19254D781 (41)

Text

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V-no rNrA ELECTRIC AND Powen COMPANY Rzcumonn,VznotazA const October 25, 1979 Mr. Harold R. Denton, Director Serial No. 806/092779 Office of Nuclear Reactor Regulation LQA/ESG:shs Attn: Mr. D. B. Vassallo, Acting Director Division of Project Management Docket No. 50-339 U. S. Nuclear Regulatory Commission Washington, DC '0555 Dear Mr. Dent.

Enclosed la . North Anna Unit No. 2 response to Mr. Vassallo's letter of September 27, 1979, which forwarded the NRR Staff positions concerning the status and applicability of its reviews of the Three Mile Island accident to pending operating license applications. As has been discussed with the Staff, the attached responses supplement and supercede those sent with our letter of August 24, 1979 Several of the earlier responses have been revised to reflect additional Staff guidance and interpretations provided, and generic industry efforts undertaken, since NUREG-0578 was originally issued. In addition, the current status of modifications to Unit 2 has been indicated.

We stand ready to discuss these issues with you, should you require further explanation or clarification.

Very truly yours, k'f. et(b Ir, C. M. Stallings Vice President-Power Supply and Production Operations Enclosure 1237 320 7910300

Enclosure North Anna Power Station Unit 2 Response to NRC Short Term Requirements Resulting from the Three Mile 1: land Incident Section 1 Responses to items (c), (d) and (e) of September 27, 1979 letter Section 2 Responses to requirements of NUREG 0578 Section 3 Response to Enclosure 7 of Sep tembe r 27, 1979 letter, on emergency preparedness 1237 321

1-1 Section 1 Re sponse to items (c), (d) and (e) of NRC letter of September 27, 19 79, for North Anna Power Station.

NRC Position (c) The ACRS comments on the shift technical advisor have resulted in our reassessment of the possible means of achieving the two functions which the Task Force intended to provide by this requirement. The two functions are accident assessment and operating experience assessment by people onsite with engineer-ing competence and certain other characteristics. We have con-cluded that the shift technical advisor concept is the preferable short-term method of supplying these functions.

We have also concluded that some flexibility in .mplementation may yield the desired r'esults if there is management innovation by individual licenaces. We have prepared a statement of functional characteristics for the shift technical advisor that will be used by the staff in the review of any alter-natives proposed by licensees. A copy is provided as Enclosure 2.

Response

Beginning January 1,1980 we will increast our manning to provide, on each shift, a shift technical advisor. Specific information regarding the shift technical advisor is included in our response to NUREG 0578 item 2.2.1.b.

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1-2 NRC Position (d) Three additional instrumentation requirements for short-term action were developed during the ACRS review of NUREG-0578. These items relate to containment pressure, containment water level and contain-ment hydrogen monitors designed to follow the course of an accident.

Descriptions of these items are provided in Enclosure 3.

(Enclosure 3)

Consistent with satisfying the requirements set forth in General Desigr.

Criterion 13 to provide the capability in the control room to ascertain containment conditions during the course of an accident, the following requirements shall be implemented:

(1) A contineous incication of containment pressure shall be provided in the control room. Measurement and indication capability shall include three times the design pressure of the containment for concrete, four times the design pressure for steel, and minus five psig for all containments.

(2) A continuous indication of hydrogen concentration in the cantainment atmosphere shall be provided in che control room. Measurement capa-bility shall be provided over the range of 0 to IO% hydrogen concen-tration under both positive and negative ambient pressure.

(3) A continuous indication of containment water level shall be provided in the control room for all plants. A narrow range instrument shall be provided for FWR's and cover the range from the bottom to the top of the containment sump. Also for PWR's, a wide range instrument shall be provided and cover the range from the bottom of the contain-ment to the elevation equivalent to a 500,000 gallon capacity. For BWR's, a wide range instrument shall be provided and cover the range from the bottom to 5 feet above the normal water le"el of the suppression pool.

The containment pressure, hydrogen concentration and wide range containment water level measurements shall meet the design and qualification provisions of Regulatory Guide 1.97, including qualification, redundancy and testability. The narrow range containment water level measurement instrumentation shall be qualified to meet the requirements of Regulatory Guide 1.89 and shall be capable of being periodically tested.

Response

(1) The present design has four channels of protection grade containment pressure transmitters with indication in the control room. Their power supply is from Vital Buses I, II, III, IV, respectively. The range of indication is 0-60 PSIA. The lower range requirement is met. However, the upper limit of indication must be increased to approx. 180 PSIA.

(59.7 PSIA x 3 = 180). This will be evaluated and the appropriate design completed by July 1980. The installation will be completed durin3 the first scheduled refueling outage.

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1-3 (2) Our present design has two H2 analyzers capable of being lined up to either containment. Their range of inuication is 0 to 10% H 2. These units must be nanually lined up for operation following an accident.

Either unit can moni6or either containment. This system will require modifications to provide remote isolation valves and control room readout. This will be accomplished by January 1,1981.

(3) The present design has two containment water level channels (LI-RS-151A,B) which cover the range from the bottom of the containment to 10 feet. Since the existing rang.a encompasses ovec 500,000 gallons, no modifications are necessary.

NRC POSITION (e) Each applicant and licensee shall install reactor coolant system and reactor vessel head high point vents remotely operated from the control room. Since these vents foru a part of the reactor coolant pressure boundary, the design of the vents shall conform to the requirements of Appendix A to 10 CFR Part 50 General Design Criteria. In particular, these vents shall be safety grade, and shall satisfy the single failure criterion and the requirements of IEEE-279 in order to insure the low probability of inadvertant actuation.

RESPONSE

A design change study h?s been initiated and will be submitted by January 1,1980 or prior to OL, whichever is later. The design will be expedited and the installation accomplished at the first scheduled outage of sufficient duration after material receipt.

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2-1 Section 2 Response to recommendations of NUREG 0578 for North Anna Power Station.

TITLE: Pressurizer Heater Power Supply (Section 2.1.1. 3.1)

NRC POSITION

1. The pressurizer heater power supply design shall provide the capability to supply, from either the offsite power source or the emergency power source (when of fsite power is not available), a predetermined number of pressurizer heaters and associated controls necessary to establish and maintain natural circulation at hot standby conditions. The required heaters and their controls shall be connected to the emergency buses in a manner that will provide redundant power supply capability.

2. Procedures and training shall be established to make the operator aware of when and how the required pressurizer heaters shall be connected to the emergency buses. If required, the procedures shall identify under what conditions selected emergency loads can be shed from the emergency power source to provide sufficient capacity for the connection of the pressuri-zer heaters.

3. The time required to accomplish the connection of the preselected pressuri-zer heater to the emergency buses shall be consistent with the timely initiation and maintenance of oatural circulation co;ditions.

4. Pressurizer heater motive and control power interfaces with the emergency buses shall be accomplished through devices that have been qualifit9 in accordance with safety-grade requirements.

RESPONSE

1. Two of the five pressurizer heater groups are fed from separate redundant safety related 480 volt load centers. The NSSS vendor indicates that 125 kw is needed to provide natural circulation. The two backup heater groups are rated at 270 and 215 kw.

2. The pressurizer heaters may be connected to the emergency buses within the limitation of the diesel generator at any time following a loss of of fsite power ace'Jent. If all loads that could be automatically connected to the emergenc bus are connected, the heaters cannot be connected to the emer-gency bus af ter a loss of of fsite power accident until a reduction in load has been accomplished. During natural circulation operation many of the emergency loads will not be connected. There is a kw meter on each of the emergency diesel generator control panel, in the rain control room, so that the operator can observe the diesel load and keep it within limits. Station operating procedutes will be developed by January 1,1980 or prior to OL, whichever is later, for the load shedding sequences, and for instruction of the operator in the use of pressurizer heaters in establishing and maintaini:g natural circulation.

3. The NSSS vendor specifies that pressurizer heaters should be available with-in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> in order to initiate and maintain natural circulation. Restorn-tion of pressurizer heaters can be accomplished within a few minutes.

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4. Motive and Control power interface equipment meets safety grade require-ments except the supports for the tray sections that enter the bottom of the pressurizer. Although the cabling between the pressurizer heater distribution panels and the heaters themselves are not color-coded, the cabling is in separate raceways and meets the intent of the color-coded separation requirements in the FSAR. The tray section to the heaters will be upgraded to withstand seismic loads. Upgrading the tray sections to withstand seismic loadings has been completed on Unit 2.

TITLE: Power Supply for Pressurizer Relief and Block Valves and Pressurizer Level Indicators (Section 2.1.1.3.2)

NRC POSITION

1. Motive and control components of the power-operated relief valves (PORV's) shall be capable of being supplied from either the offsite power source or the emergency power source when the of fsite power is not ava11ab1( .

2. Motive and control components associated with the PORV b'ock valves shall be capable of being supplied from either the offsite pow c source or the emergency power source when the offsite power is not available.

3. Motive and control power connections to the emergency buses for the PORV 's and their associated block valves shall be through devices that have been qualified in accordance with safety-grade requirements.

4. The pressurizer level indication instrument channels shall be powered from the vital instrument buses. These buses shall have the capability of being supplied from either the offsite power source or the emergency power source when offsite power is not available.

RESPONSE

Position 1 Control and indication circuits for the PORV's are powered from redundant safety grade emergency buses. Motive power for the power operated relief valves (PORV's) 2455C and 2456 is currently provided only by containment instrument air. Nitrogen supply tanks are provided as a redundant source of motive power for the PORV's as a part of the overpressurization system employed during solid water operation. Motive power for the PORV's will be upgraded by the addition of a line and three (3) spring loaded check valves to the nitrogen supply system. This will provide another source of motive power. The nitrogen supply system is composed of seismically supported, stainless steel components and is sized for 120 valve operations. This modification has been completed on Unit 2.

Position 2 Motive power and control for the block valves is from redundant safety grade emergency buses.

Position 3 Electrical motive and control power to the PORV's and associated block valves is qualified safety grade.

Position 4 The pressurizer level indication instrument channels are powered from vital buses that are powered from redundant safety grade emergency buses.

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2-3 TITLE: Relief and Safety Valve Testing (Section 2.1.2)

NRC POSITION Pressurized water reactor and boiling water reactor licensees and applicants shall conduct testing to qualify the reactor coolant system relief and safety valves under expected.cperating conditions for design basis transients and accidents. The licensees and ap'plicants 'shall determine the expected valve operating conditions through the use of analyses of accidents and anticipated single failures applied to these analyses shall be chosen so that the dynamic forces on the safety and relief valves are maximized. Test procedures shall be the highest predicted by conventional safety analysis procedures. Reactor coolant system relief and safety valve qualification shall include qualifica-tion of associated control circuitry piping and supports as well as the valves themselves.

RESPONSE

Vepco is participating in an Owners Group formed by utilities utilizing Westinghouse reactors. The Westinghouse Owners Group is working with other PWR owners and the Electric Power Research Institute (EPRI) to develop a program for qualification of relief and safety valves under expected operating conditions involving solid-water and two-phase flow conditions. The program description and schedule will be submitted by January 1,1980.

Information developed from the test program will be utilized in a review of the pressurizer relief and safety valve design and piping configurations at North Anna.

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2-4 TITLE: Direct Indication of Valve Position (Section 2.1.3.a)

NRC POSITION Reactor 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.

RESPONSE

Pressurizer power operated relief valves 2455C and 2456 have direct indication derived from limit switches on each valve that indicate open-close position and are displayed in that control room. The indication is powered from a vital source. In addition, an indirect indication is available by temperature indication of the P.O.R.V. discharge header. Motor operated block valves 2535 and 2536 in series with the P.O.R.V. 's have direct indication derived from limit switches on each valve that indicate open-close position and are displayed in the control room. The indication is powered from a vital source.

No direct indication of safety valve position exists. Indication of valve position through indirect means is available by temperature indication in the control room of the discharge pipe downstream of each valve.

We have evaluated two possible methods of monitoring the position of the safety valves. These methods are 1) direct indication of the safety valve position by mounting a limit switch on the safety valve, and 2) menitoring the flow in the discharge pipe with acoustic devices. We believe that the acoustical method is superior to the use of limit switches.

A purchase order for the acoustical monitoring equipment has been placed and installation of the equipment will be complete on Unit 2 by January 1, 1980 or prior to OL, whichever is later.

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2-5 TITLE: Instrumentation for Detection of Inadequate Core Cooling in PWR's and BWR's (Section 2.1. 3.b. )

NRC POSITION

1. Licensees shall develop procedures to be used by the operator to recognize inadequate core cooling with currently available instrumen-tation. The licensee shall pr vide a description of the existing instrumentation for the operators to use to recognize these conditions.

A detailed description of the analyses needed to form the basis for operator training and procedure development shall be provided pursuant to another short-term requirement, " Analysis of Of f-Normal Conditions, Including Natural Circulation"- (see Section 2.1.9 of this appendix).

In addition, each PWR shall install a primary coolant saturation meter to provide on-line indication of coolant saturation condition. Operator instruction as to use of this meter shall include consideration that the meter is not to be used exclusive of other related plant parameters.

2. Licensees shall provide a description of any additional instrumentation or controls (primary or backup) proposed for the plant to supplement those devices cited in the preceding section giving an unambiguous, easy-to-interpret indication of inadequate core cooling. A description of the functional design requirements for the system shall also be incluted. 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.

RESPONSE

1. Changes to emergency procedures have been made to emphasize the need to insure adequate coolant flow and to insure that reactor coolant tem-perature and pressure are maintained or immediately restored to achieve a margin to saturation of at least 50*F. All licensed reactor operators and current trait +;. have received special instruction in the TMI type incident with particular emphasis on the use of existing instrumentation to determine core conditions.

We are participating in a Westinghouse Owners Group to more effectively deal with the generic issues resulting from the TMI incident. Included in the scope of work currently authorized by the group is a complete review and rewriting of the Westinghouse Generic Emergency Operating Instructions to incorporate lessons learned from the TMI incident. Specific concerns to be cddressed in this review include the use of existing instrumentation co determine core conditions and the adequacy of core cooling. The scope and scheduling of this work is to be handled through the Bulletins and Orders Task Force. Improvements developed as part of the generic procedures review will be incorporated into the North Anna emergency procedures. While the specific procedural applications of this owner's group ef fort are incomplete, Westinghouse has developed an identification and categorization of those instruments which are essential for diagnosis of of f normal conditions.

The minimum set of instrumentation that is required for operator information in order to diagnose the type of plant event, take the necessary manual actions, and to monitor critical parameters is as follows.

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2-6 Wide Range Reactor Coolant System Pressure Wide Range RTD - hot legs Wide Range RTD - cold legs Pressurizer Level Incore Thermocouples RWST Level Containment Sump Level Righ Head Safety Injection Flow Auxiliary Feedwater Flow Condensate Storage Tank Level Containment Pressure Containment Radiation Steamline Pressure Steam Ganerator Narrow Range Level Steam Generator Wide Range Level Air Ejector Radiation Steam Generator Blowdown Radiation Boric Acid Tank Level Control Room and Auxiliary Building Area Radiation Konitors North Anna currently has all of this instrumentation.

We are developing a design for a reactor coolant saturation meter. We will make every ef fort to have this meter installed as soon as possible, with a target completion date of January 1,1980 or prior to OL, whichever is later.

However, this date may be unattainable due to design and procurement uncertainties.

Mechanisms have been provided to allow the operator to immediately assess the primary coolant's margin to saturation conditions.

An operator can initiate a trend of system saturation temperature and one or more of the above listed temperatures. A saturation curve has been posted on the control board and provided in current procedures. This curve, combined with nearby indications of reactor coolant system temperatures and pressures, enables the operator to quickly determine the system's margin to saturation.

2. The identification of the need for at; additional instrumentation will be made in conjunction with the ongoing analyses and procedural reviews. At this time, no definite additions or modifications have been determined to be necessary.

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2-7 TITLE: Diverse Containment Isolation (Section 2.1.4)

NRC POSITION

1. All containment isolation system designs shall comply with the recommenda-tions of SRP 6.2.4; i.e., that there be diversity in the parameters sensed for the initiation of containment isolation.

2. All plants shall give careful reconsideration to the definition of essential and non-essential systems, shall identify each system determined to be essential, shall describe the basis for selection of each essential system shall modify their containment isolation designs accordingly, and shall report the results of the reevaluation to the NRC.

3. All non-essential systees shall be automatically isolated by the contain-ment isolation signal.

4. The design of control systems for automatic containment isolation valves shall be such that resetting the isolation signal will not tesult in the automatic reopening of containment isolation valves. Reopening of contain-ment isolation valves shall require deliberate operator action.

RESPONSE

1. The North Anna containment Phase A isolation system complies with the signal diversity requirements of SRP-6.2.4. All non-essential systems having auto-matic containment isolation valves and not required for an orderly reactor shutdown or to maintain containment atmospheric conditions, are closed on Phase A isolation which is initiated by a safety injection actuation signal.

Safety injection is actuated by any one of the following input parameters:

(1) high steam line flow with either low steam line pressure or low low T average, (2) high containment pressure, (3) high steam line differential pressure, (4) low pressurizer pressure, and (5) manual actuation. These four sources provide for the required diversity of parameters sensed which is in conformance with Section 6.2.4. of the Standard Review Plan.

2. Tables I through III list the essential and non-essential containment penetrations. The essential systems are divided into two categories (levels) which are based on their ability to mitigate the severity of varicus types of accidents. Level 1 of the essential systems are defined as Engineered Safety Features (ESF) and Containment Depressurization systems required to operate af ter a LOCA. These systems are listed in Table I.

The essential Level 2 systems are defined as those required to maintain the operation of critical systems and functions such as the containment heat removal and, therefore, remain unisstated from the containment until a design basis LOCA is indicated (Phase B isolation) or when these systems are no longer required. These Level 2 systems are listed in Table II.

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3. The non-essential systems listed in Table III are either isolated on Phase A actuation signal (SIS) or are closed during normal plant operation. Some

..on-essential systems listed in Table III may be utilized f ollowing a LOCA Lf conditions warrant.

4. Once Containment Phase A isolation has been initiated by a safety injection actuation signal, the automatic isolation valves can be opened only upon manual reset of the actuating signal and deliberate remote manual operation of the individual valve (refer to Section 6.2.4.3. of the FSAR).

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2-9 TABLE I ESSENTIAL SYSTEMS - LEVEL 1 System Descrf.ption Valve Position After SIS

• Righ Head Safety Injection to the Cold Leg Open Righ Head Safety Injection to the Hot Leg Closed Low Head Safety Injection to the Cold Leg Open Low Head Safety Injection to the Hot Leg Closed Low Head Safety Injection From the Sump Closed Containment Atmospheric Cleanup Closed Seal Water Injection to RC Pump Open Quench Spray Pump Discharge ** Clo s ed *

• Recirculation Spray Suction / Casing Cooling Open Discharge **

Recirculation Spray Discharge Open Service Water into the Recirculation Spray Closed ***

Heat Exchenger Service Water Return From the Recirculation Cicsed***

Spray Beat Exchanger NOTES

• Isolation valves designated as closed receive a signal to close immediately af ter safety injection actuation and are opened by the operator or automatic controls at some period of time follow-ing a LOCA.

• • Quench spray pumps and casing cooling pumps are selectively isolated af ter it is established that the system is no longer required.

• • • Valves remain closed on SIS (Phase A) containment isolation. Valves open on a Containment Depressurization Actuation (CDA), containment isolation Phase B.

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2-10 TABLE II ESSENTIAL SYSTEMS - LEVEL 2 System Description Mode of Containment Isolation Component Cooling from RC Pump Thermal Barriers Phase B Component Cooling from Containment Air Recirculation Cooling Coils Phase B Component Cooling to RC Pump Motor Phase B Component Cooling from RC Pump Motor Phase B Main Steam Relief Set Point Pressure Auxiliary Feedwater

• Component Cooling Water Return RER Heat Exchanger Phase B

• Auxiliary feedwater is !solated when the condensate storage tank has been depleted.

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2--11 TABLE III NON-ESSENTIAL SYSTEMS Mode of System Description Containment Isolation Charging-CVCS Phase A*

Charging System Letdown Phase A*

RC Pumps Seal Water Return Phase A*

Containment Air Radiation Monitor Phase A*

Sampic Pressurizer Relief Tank Gas and Liquid Phase A*

Space Samples Primary Coolant Hot Leg Sample Phase A*

Priu ry Coolant Cold Leg Sample Phase A*

Pressurizer Vapor Space Sample Phase A*

Residual Heat Removal Sample Phase A*

Component Cooling Water Return from RHR Heat Exchanger Phase A*

Safety Injection Accumulator Makeup Manual Locked-closed RHR Return to RWST Manual Lockedclosed Steam Cen. Wet Layup Manual Locked-closed Primary Drain Transfer Discharge Phase A*

Containment Sump Pump Discharge Phase A*

Steam Cen. Blowdown Phase A*

Service Air Manual Locked-closed Primary Grade Water Phase A*

RC Loop Fill Manual Locked-closed Primary Vent Header Phase A*

Nitrogen to Waste Gas Charcoal Pilttes Phase A*

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2-12 TABLE III (CONT'D.)

Mode of System Description Containment Isolation Nitrogen to Pressurizer Relief Tank Phase A*

Primary Vent Pot Vent Manual Locked-closed Containment Leakage Monitoring Phase A*

Steam Generator Blowdown Sample Phase A*

Condenser Air Ejector Vent Phase A*

Containment Purge Air Ducts Locked-closed Containment Air Ejector Suction Locked - Closed Pressurizer Dead Wt. Calibrator Manual Locked-closed Refueling Purifier Inlet and Outlet Manual Locked-closed Accumulator Tanks Test Line Phase A*

Feedwater Chemical Addition **

Main Steam (TRIP) - Shares Pen. with M.S. Relief LinJs ***

Feedwater - Sharts Pen. with Auxiliary Feedwater Lines ***

NOTES:

• Valves may be opened by the control room operator at some time af ter a LOCA, if required.

• • Closed system inside and check valve to provide containment isolatioa.

• • • Isolated either by intermediate high-high containment pressure, high steam line flow with low steam line pressure, or low low T average.

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2-13 TITLE: Dedicated H7 Control Penetration (Section 2.1.5.a)

NRC POSITION Plants using external recombiners or purge systems for post-accident combustible gas control of the containment atmosphere should provide containment isolation systems for external recombiner or purge systems that are dedicated to that service only, that meet the redundancy and single failure requirements of General Design Criteria 54 and 56 of Appendix A to 10 CFR Part 50, and that are sized to satisfy the flow requirements of the recombiner or purge system.

RESPONSE

The post-accident hydrogen recombiners take suction from the containment through the same containment penetration used for the suction of the containment vacumn pumps. The recombiner discharges back to the containment through its own dedicated penetration. The suction penetrations are considered to be dedicated to the hydrogen recombiner during accident conditions since the containment vacuum system is not required for containment depressurization during accident conditions.

The reconbiner system is in no way connected to the purge system. The containment isolation for these penetrations meets the redundancy and single failure criteria.

Deviations from General Design Criteria 54 and 56 are necessary to provide access tc the automatic trip valves in order to ensure operability of the hydrogen recombicer and are documented in Section 6 of the FSAR. The two inch hydrogen recombiner lines tie into the two inch containment vacuum lines downstream of the containment isolation valves. To establish operation of the recombiner system, a manual valve (not subject to single active failure by spurious motor-operator movement), which is accessible on the 274' elevation of the Auxiliary Building near the containment vacuum pumps, must be closed to isolate the containmcat atmosphere from the containment vacuum system. This can be accom-plished without excessive exposure to plant operating personnel. ihe existing arrangement, therefore, satisfies the intent of NUREG 0578.

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2-14 TITLE: Inerting BWR Containments (Section 2.1.5.b)

NRC POSITION It shall be required that the Vermont Yankee and Hatch 2 Mark I BWR contain-ments be inerted in a manner similar to other operating BWR plants. Inerting shall also be required for near term OL licensing of Mark I and Mark II BWRs.

RESPONSE

This item is not applicable to North Anna.

TITLE: Capabilitv to Install Hydrogen Recombiner at Each Light Water Nuclear Power Plant (2.1.5.c)

NRC POSITION

1. All licensees of light water reactor plants shall have the capability to obtain and install recombiners in their plants within a few days follow-ing an accident if containment access is impaired and if such a system is needed for long-term post-accident combustible gas control.

2. The procedures and bases upon which the recombiners would be used on all plants should be the subject of a review by the licensees in considering shielding requirements and personnel exposure limitations as demonstrated to be necessary in the case of TMI-2.

RESPONSE

North Anna has two (2) Post Accident Hydrogen Recombiners rated at 50 scfm each that are shared between unita 1 and 2. The recombiners are separate and independent. Technical Specification 3.6.4.2. and 4.6.4.2 governs the opera-bility and surveillance requirements. Each recombiner is capable of beieg manually valved to either containment. The procedures and bases upon which the recembiners would be used will be reviewed in considering shielding re-quirements and personnel exposure limitations. This effort will ne completed in conjunction with the plant shielding review (estimated completion date, January 1,1980.)

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2-15 TITLE: Integrity of Systems Outside Containment Likely to Contain Radioactive Materials (Engineered Safety Systems and Auxiliary Systems) for FWR's and BVR's 2.1.6.a.

NRC POSITION Applicants and licensees shall immediately 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-low-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 carry radioactive fluid outside of containment.

L. Measure actual leakage rates with system 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 a frequency not to exceed refueling cycle intervals.

RESPONSE

A prerequisite to the establishment of the requested leakage program is the identification of those systems located outside containment which are likely to contain primary coolant immediately following an accident. This will include portions of the accident mitigation systems located outsida containment (Safety Injection System, Recirculation Spray System).

We are currently conducting a review of other systems to identify any additional systems which may be used in response to or recovery from an accident. A similar parallel review of systems use under post accident conditions is being conducted by Westinghouse for the Owners Group. It is expected that these reviews will be completed by January 1,1980 or prior to OL, whichever is later.

A leak reduction program for the accident mitigation systems will be developed and implemented by January 1,1980 or prior to OL, whichever is later. If the above mentioned reviews indicate the need for leakage reduction programs in other systems, these additional leakage reduction programs will be developed by March 1,1980 and implemented as soon as operation permits.

Following is relevant information on the location and functions of the Residual Heat Removal System, Chemical and Volume Control System, Safety Injection System, and Recirculation Spray System. The Residual that Removal System (RHR) is lo-cated entirely within the containment. The RRR system does not perform any ESF functions. The Chemical and Volume Control System (CVCS) is leak tested as a portion of the Reactor Coolant System (RCS) and is int 1ated by a safety injec-tion actuation. This leakage testing is governed by ;echnical Specification 1237 339

2-16 Table 4.1.2.A and is performed at least once each day. Portions of other sys-tems such as the Safety Injection System (SI), and the Recirculation Spray Sys-tem (RS) are located outside the containment. The RS system is located within the Safeguards Building and the containment where the need for personnel access would be minimal. The outside recirculation spray system is normally aligned for operation and forms a part of the containment boundary. Since North Anna uses,a_subatmospheric containment, any significant leakage in the outside re-

, - 'circulatin spray system would be obvious during operation due to its impact on establishing or maintaining a vacuum. The Low Head Safety Injection (LHSI) pumps are also located within the Safeguards Building where LHSI lines, when in the recirculation phase, are returned directly to the containment without traversing another building. The LHSI lines to the charging pumps (or High Head Injection Pumps) suction are directed through portions of the Auxiliary Building where the charging pumps are located.

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2-17 TITLE: plant Shielding Review (Section 2.1.6.b)

NRC POSITION With the assumption of a post-accident release of radioactivity equivalent to that described in Regulatory Guides 1.3 and 1.4, each licensee shall perform a radiation and shielding design review of the spaces around systems that nay, as a result of an accident, contain highly radioactive materials. The design review should identify the location of vital areas and equipment, such as the control room, radwaste control stations, emergency power supplies, motor control centers, and instrument areas, in which personnel occupancy may be unduly limited or safety equipment may be unduly degraded by the radiation fields during post-accident operations of these systems.

Each licensee shall provide for adequate access to vital areas and protection of safety equipment by design changes, increased permanent or temporary shielding, or post-accident procedural controls.

RESPONSE

A plant shielding review will be performed to evaluate the ability to operate essential systems required after a LOCA with significant core damage. This review will evaluate activity levels in vital areas of the plant which must be accessible to permit operation of essential systems and to ensure that safety grade equipment can perform its intended function in the resulting radiatir.n field. Design changes, increased permanent or temporary shielding and/or post accident procedural controls will be implemented, where required, to assure the proper operation of vital systems.

As with the leakage reduction program, a prerequisits to the completion of the shielding review is the identification of those systems which are likely to contain highly radioactive materials following an accident. As explained in our response to item 2.1.b.a., internal and Owners Group studies are underway to detemine which systems, in addition to mitigation systems should be included within the scope of the shielding and leakage reviews.

We are preceding with radiation level calculations for the accident mitigation aystems (safety injection and recirculation spray). If the ongoing reviews indicate the need for a shielding review of additional systems, calculations for those system will follow. The identification of any shielding requirements or other corrective actions will be made following the completion of all radiation level calculations.

We expect thesshielding geview and entificatic f correctivractions to be completed by }$trch 31' ation cor tive 'tions M n by January 1,198V,198{ eme g m,a w6 OrN A n a (~ ' f b A M f "" Y p ac,_S. ch..p a.o k e eq Md  % ""' 1 h N N 2'  ?"'"

, w h. a lo3r~ .

1237 34I

2-18 TITLE: Auto Initiation of Auxiliary Feed (Section 2.1.7.a)

KRC POSITION Consistent with satisfying the requirements of General Design Criterion 20 of Appendix A to 10 CFR Part 50 with respect to the timely initiation of the auxiliary feedwater system, the following requirements shall be implemented in the short term:

1. The design shall provide for the automatic initiation of the auxiliary feedwater system.

2. The automatic initiation signals and circuits shall be designed so that a single failure vill not result in the loss of auxiliary feeduater system function.

3. Testability of the initiating signals and circuits shall be a feature of the design.

4. The initiating signals and circuits shall be powered from the emergency buses.

5. Manual capability to initiate the auxiliary feedwater system from the control room shall be retained and shall be implemented so that a single failure in the manual circuits will not result in the loss of system function.

6. The a-c motor driven pumps and valves in the auxiliary feedwater system shall be included in the automatic actuation (simultaneous and/or sequential) of the loads to the emergency buses.

7. The automatic initiating signals and circuits shall be designed so that their failure will not result in the loss of manual capability to initiate the AFWS from the control room.

In the long term, the automatic initiation signals and circuits shall be upgraded in accordance with safety-grade requirements.

RESPONSE

1. The current design of the Auxiliary Feedwater System provides for automatic initiation.

2. All initiation signals and circuits are designed to prevent a single failure from causing a loss of the Auxiliary Feedwater System.

3. The Auxiliary Feedwater System is initiated automatically by a safety in-jection signal., loss of offsite power, and on low-low steam generator level of any one steam generator. These actuation signals are testable and these signals are the system actuations on which the FSAR Chapter 14 accident analysis is based. The Auxiliary Feedwater System is also automatically initiated on loss of the main feedwater pumps in anticipation of low steam generator level. This anticipatory actuation is not testable during normal operation.

1237 342

2- 19

4. All initiating circuits which automatically start the Auxiliary Feedwater System, are powered from vital buses and are backed-up by the emergency power system,

5. The capability presently exists to manually initiate the Auxiliary Feed-water System from the control room. A single failure in the manual circuits will not result in the loss of system function.

6. The AC motor feed pumps in the Auxiliary Feedwater System are automatically initiated. The motor operated valves and air operated hand control valves required to establish a flow path from the discharge of these pumps to the steam ger.erators are lef t in the open position and do not receive automatic signals. These valves are under strict administrative control and can be operated from the control room. Therefore, an automatic signal is not required. To further alert the operator if one of these valves is shut, an alarm will be added in the control room which will alarm if any of these normally open valves are not full open. The motor operated valves are powered from the emergency bus. The air operated hand control valves are powered by the vital bus. The valve controls will be powered from a vital bus.

The AC motor driven pumps are protected by automatic pressure control valves in the pump discharge lines. These valves prevent destructive pump runout in the event of a break in the pump discharge line. These valves are normally closed and automatically open on pump startup to maintain the pump discharge above 900 psig. To alert the operator that the pressure control valves may not be functioning properly af ter pump startup, an alarm will be added in the control room which will alarm if these valves have not opened.

These modifications have been completed on Unit 2.

7. The automatic signals are designed in such a manner that their failure will not result in the loss of manual capability to start the Auxiliary Feedwater System.

8. The automatic initiation circuits are presently safety-grade equipment and meet the long-term requirements.

1237 343

2-20 TITLE: Auxiliary Feed Flow Indication (Section 2.1.7.b)

NRC POSITION Consistent with satisf ying the requirements set forth in GDC 13 to provide the capability in the control room to ascertain the actual performance of the AFWS when it is called to perform its intended function, the following requirements shall be implemented:

1. Safety-grade indication of auxiliary feedwater flow to each steam generator shall be provided in the control room.

2. The auxiliary feedwater flow instrument channels shall be powered from the emergency buses consistent with satisf ying the emergency power diversity requirements of the auxiliary feedwater system set forth in Auxiliary Systems Branch Technical Position 10-1 of the Standard Review Plan, Section 10.4.9.

RESPONSE

1. Auxiliary Feedwater Flow indication to each steam generator which is displayed in the control room is safety grade equipment with the exception of power supply diversity.

2. Auxiliary Feedwater flow indication is powered from the eaergency bus via the semi vital bus, which does not meet the diversity requirements of ASTB 10-1 of the standard review plan Section 10.4.9. To meet the diversity requirements of ASTB 10-1 the Auxiliary Feedwater flow indi-cation power supples will be moved to an existing cabinet which meets the diversity requirements. This change will meet the position and has been completed on Unit 2.

3. This change will result in safety-grade indication in the control room of auxiliary feedwater flow to each steam generator and thus satisfies all the requirements, including implementation category B, in NUREG-0578.

1237 344

2-21 TITLE: Improved Post Accident Sampling Capability (Section 2.1.8.a)

NRC POSITION A design and operational review of the reactor coolant and containment atmosphere sampling system sha?1 be performed to determine the capability of personnel to promptly obtain (less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />) a sample under accident conditions without incurring a radiation exposure to any individual in excess of 3 and 18 3/4 Rems to the whole body or extremeties, respectively. Accident conditions should assume a Regulatory Guide 1.3 or 1.4 release of fission p rod uct s . If the review indicates that personnel could not promptly and safely obtain the samples, additional design change features or shielding should be provided to meet the criteria.

A design and operational review of the radiological spectrum analysis facili-ties shall be performed to determine the capability to promptly quantify (less than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />) certain radioisotopes that are indicators of the degree of core damage. Such radionuclides are noble gases (which indicate cladding failure),

iodines and cesiums (which indicate high fuel temperature), and non-volatile isotopes (which indicate fuel melting) . The initial reactor coolant spectrum should correspond to a Regulatory Guide 1.3 or 1.4 release. The review should also consider the ef fects of direct radiation from piping and components in the auxiliary building and possible contamination and direct radiation from airborne effluents. If the review indicates that the analyses required cannot be performed in a prompt manner with existing equipment, then design modifi-cations or equipment procurement shall be undertaken to meet the criteria.

In addition to the radiological analyses, certain chemical analyses are necessary for monitoring reactor conditions. 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 term) . Both analysis shall be capable of being completed promptly; i.e., the boron sample analyses within an hour and the chloride sample analy,is within a shif t.

RESPONSE

A design and operational review of the reactor coolant and containment atmos-phere sampling will be performed to determine the capability of personnel to promptly obtain samples under accident conditions without incurring a radiation exposure to any individual in excess of limits specified in 10 CFR 20.

If this review indicatas that samples cannot be promptly and safely obtained, we will provide a description of proposed modifications by January 1,1980.

A design and operational review of the radiological spectrum analysis facili-ties will be performed to determine the capability of promptly quantif ying core radioisotopes. If this review indicates that the required analysis cannot be performed promptly with the existing facilities, we will provide a description of proposed actions to meet the criteria by January 1,1980 or prior to OL, whichever is later.

These reviews represent preliminary reviews of general sampling capability.

We have not addressed certain specific analysis stated in your position because we believe that additional clarification and discussion is needed to identify specific post accident time and sampling requirements. For example, determinaticn of pH should be considered in preference to chlorides. We suggest that these requirements can best be addressed in a topical meeting with the Owners Group.

1237 345

2-22 TITLE: Increased Range of Radiation Monitors (Section 2.1.8.b)

NRC POSITION The requirements associated wit's this recommendation should be considered as advanced implementation of certain requirements to be included in a revision to Regulatory Guide 1.97, " Instrumentation to Follow the Course of an Accident," which has already been initiated, and in other Regulatory Guides, which will be promulgated in the near-term.

1. Noble gas effluent monitors shall be installed with an extended range designed to function drring accident conditions as well as during normal operating conditions; multiple monitors are considered to be necessary to cover the ranges of interest.

a. Noglegaseffluentmonitorswithanupperrangecapacityof 10 uCi/cc (Xe-133) are considered to be practical and should be installed in all operating plants.

b. Noble gas effluent monitoring shall be provided for the potal range of concentration extenging from a minimum of 10 u Ci/cc (Xe-133) to a maxmimum of 10 uCi/cc (Ke-133) . Multiple monitors are considered to be necessary to cover the ranges of interest.

The range capacity of individual monitors shall overlap by a factor of ten.

2. Since iodine gaseous effluent monitors for the accident condition are not considered to be practical at this time, capability for ef fluent monitoring of radiciodines for the accident condition shall be provided with sampling conducted by absorption on charcoal or other media, followed by onsite laboratory analysis.

3. In-containment radiation level monitors with a maximum range of 10 rad /hr shall be installed. A minimum of two such monitors that are physically separated shall be provided. Monitors shall be designed and qualified to function in an accident environment.

RESPONSE

Noble gas effluent and radiation level monitors capable of providing the extended ranges recommended in Section 2.1.8.b do not appear to be commercially available at this time. Studies are being performed, however, to determine appropriate, conservative monitoring ranges based on plant specific parameters These studies may show that commercially available equipment which approaches but does not reach the recommended range extremes can provide the necessary monitoring capability with an adequate margin of conservatism. Additional studies will be performed to determine how best to utilize existing station equipment for monitoring of radiolodines in gaseous effluents under accident conditions.

The findings of the above studies will be implemented to provide appropriate monitoring capability during the first refueling or extended outage following Jan.1,1981 or sconer if possible.

1237 346

2-23 TITLE: Improved In-plant Iodine Instrumentation (Section 2.1.8.c.)

NRC POSITION Each licensee shall provide equipment and associated training and procedures for accurately determining the airborne iodine concentration throughout the plant under accident conditions.

RESPONSE

Lmproved capability for the assessment of in-plant airborne radioiodine con-centrations under accident conditions will be provided by the following measures.

1. An adequate stock of " silver zeolite" sampling cartridges will be purchased and maintained at the station for emergency use. Exicting station equipment will be used to perform gamma spectral analysis on collected samples to accurately assess iodine concentrations.

2. Procedures will be revised to instruct appropriate personnel in the proper precautions to be taken when sampling with charcoal cartridges.

The procedure will address acceptable methods for removal of noble gases from charcoal cartridges, prior to performing gamma spectral analysis.

These measures will be implemented by January 1,1980, 1237 347

I-24 TITLE: Analysis of Design and Off-N'o rmal Transients and Accident (Section 2.1.9)

KRC POSITION Analyses, procedures, and training addressing the following are required:

1. Small break loss-of-accident accidents;

2. Inadequate core cooling; and

3. Transients and accidents.

Some analysis requirements for small breaks have already been specified by the Bulletins and Orders Task Force. These should be completed. In addition, pretest calculations of some of the Loss of Fluid Test (LOFT) small break tests (scheduled to start in September 1979) shall be performed as means to verify the analyses performed in support of the small break emergency pro-cedures and in support of an eventual long term verification of compliance with Appendix K of 10 CFR Part 50.

In the analysis of inadequate core cooling, the following conditions shall be analyzed using realistic (best-estimate) methods:

1. Low reactor coolant system inventory (two examples will be required -

LOCA with forced flow, LOCA without forced flow).

2. Loss of natural circulation (due to loss of heat sink).

These calculations shall include the period of time during which inadequate core cooling is approached as well as the period of time during which in-adequate core cooling exists. The calculations shall be carried out in real time far enough that all impor cant phenomena and instrument indications are included. Each case should then be repeated taking credit for correct operater action. These additional cases will provide the basis for developing appropriate emergency procedures. These calculations should also provide the analytical basis for the design of any additional instrumentation needed to provide operators with an une;51guous indication of vessel water level and core cooling adequacy (see Sectx7n 2.1.3.b in this appendix) .

The analysis of transients and accidents shall include the design basis events specified in Section 15 of each FSAR. The analysis shall include a single active failure for each system called upon to function for a particular event.

Consequential failures shall also be considered. Failures of the operators to perform required control manipulations shall be given consideration for permutations of the analyses. Operator actions that could cause the complete loss of function of a safety system shall be considered. At present, these analyses need not address passive failures or multiple system failures in the short term. In the recent analysis of small break LOCAs, complete loss of auxiliary feedwater was considered. The complete loss of auxiliary feedwater may be added to the failures being considered in the analysis of transients and accideats if it is concluded that more is needed in operator training beyond the short-term actions to upgrade auxiliary feedwater system reliability. Similarly, 11 the long term, multiple failures and passive failures may be considered depending in part on staff review of the results of the short-term analyser.

1237 348

2-25 The transient and accident analyses shall include event tree analyses, which are supplemented by computer calculations for those cases in which the system response to operarnt action is unclear or these calculations could be used to provide important quantitative information not available from an event tree. For example, failure to initiate high-pressure injection could lead to core uncovery for some transients, and a computer calculation could provide information on the amount of time available for corrective action. Reactor simulators may provide some information in defining the event trees and would be useful in studying the information available to the oper . tors. The transient and accident analyses are to be performed for the purpose e c identifying appropriate and inappropriate operator actions relating to important safety considerations such as natural circulation, prevention of aora uncovery, and prevention of more serious accidents.

The information derived from the preceding analyses shall be included in the plant emergency proceditres and operator training. It is expected that analyses performed by the NSSS vendors shall be put in the form of emergency procedure guidelines and that the changes in the procedures will be implemented by each licensee or applicant.

In addition to the analyses performed by the reactor vendors, analyses of selected transients should be performed by the NRC Office of Research, using the best available computer codes, to provide the basis for comparisons with the analytical methods being used by the reactor vendors. These compari-sons together with comparisons to date, including LOFT small break test data, will constitute the short-term verification effort to assure the adequacy of the analytical methods being used to generate emergency procedures.

RESPONSE

Analyses of small break loss-of-coolant accidents, symptoms of inadequate core cooling and required actions to restore core cooling, and analyses of transf ent and accident scenarios including operator actions not previously analyzed are being performed on a generic basis by the Westinghouse Owners Group. The small break analyses have been completed and 5:are reported in WCAP-9600, which was sub-mitted to the Bulletins and Orders Task Force b, the Owners Graup on June 29, 19 79. Work required to address the other two areas, inadequate core cooling and other transient and accident scenarios, is being performed in conjunction with the Bulletins and Orders Task Force. Definitions of requirements and schedules for submittal of program results are being established with the Task Force. The results of these programs will determine if the need exists for any additional instrumentation or controls as required by Item 2.1.3.b.

In addition to the above program, the Owners Group is providing pre-teut predictive analysis of the LOFT test program in accordance with the schedule established by the Bulletins and Orders Task Force.

The information from these analyses will be included in the plant emergency procedures. The initial Westinghouse review and revision of generic emergency procedures has been completed. The revised procedures were mailed to the NRC on October 16, 19 79. Review of the revised procedures by Vepco training and operations personnel is currently in progress. Following acceptance of these procedures by the NRC, station specific procedures will be revised to incorporate the new generic guidelines. Operator training will be updated to include the bases and specifics of the revised procedures, i237 349

2-26 by additional procedural changes determined to be necessary as a result of angoing analyses will be implemented in a timely manner.

Our responses concerning containment pressure, water level, and hydrogen instrumentation and reactor vessel venting are included in Section 1.

1237 350

2-27 TITLE: Shift Supervisors Responsibilities (Section 2.2.1.a)

NRC POSITION

1. The highest level of corporate management of each licensee shall issue and periodically reissue a management directive that emphasizes the primary management responsiblity of the shif t supervisor for safe operation of the plant under all conditions on his shif t and that clearly establishes his command duties.

2. Plant pcocedures shall be reviewed to assure that the duties, responsi-bilities, and authority of the shif t supervisor and control room operators are properly defined to ef fect the establishment of a definite lina of command and clear delineation of the command decision authority of the shif t supervisor in the control room relative to other plant management personnel. Particular emphasis shall be placed on the following:

a. The responsiblity and authority of the shif t supervisor shall be to maintain the broadest perspective of operational conditions affecting the safety of the plant as a matter of highest priority at all times when oa duty in the control room.

b. The shif t supervisor, until properly relieved, shall remain in the control room at all times during accident situations to direct the activities of control room operators. Persons authorized to relieve the shif t supervisor shall be specified.

c. L the shif t supervisor is temporarily absent from the control room during routine operations, a lead control room operator shall be designated to assume the control room command function.

These temporary duties, responsibilities and auttsrity shall be clearly specified.

3. Training programs for shif t supervisor shall emphasize and reiaforce the responsiblity for safe operation and the management function the shif t supervisor is to provide for assuring safety.

4. The administrative duties of the shift supervisor shall be reviewed by the senior of fic' " each utility responsible for plant operations.

Administrative functions that detract from or are subordinate to the management responsbility for assuring the safe operatin of the plant shall be delegated to other operations personnel not on duty in the control room.

RESPONSE

1.) A directive will be issued by the Vice President-Production, Operations and Maintenance which emphasizes the primary management responsiblity of the shif t supervisor for safe operation of the plant under all conditions and clearly establishes his command duties. This directive will be issued prior to January 1,1980 and at approximately yearly intervals thereaf ter.

1237 351

2-28 2a,b,&c.) Existing administrative procedures delineate the responsibilities of station supervisory and operations personnel, including the authority of the shif t supervisor. These procedures will be reviewed and revised by January 1,1980 to include or emphasize the points cited in your position.

In addition, we will increase shift staf fing by adding a SRO to allow the shif t supervisor to maintain a broader oversight of plant safety and operating conditions. Shift staffing will th'n include two SRO's for one unit operation and three SRO's for two u..it operation.

At least one of these senior reactor operators will be in the control room at all times. The shif t supervisor will maintain an overview of plant conditions, make decisions regarding plant operations, and direct the actions of the control room operators.

3. Training programs for shif t supervisors and SRO's will be improved by January 1,1980 to provide greater emphasis on and reinforcement of the responsibility for safe operatica and the management function the shif t supervisor is to provide. Additional details on this training are included in our response to your position on Shif t Technical Advisors.

4. The administrative duties of the shif t supervisor will be reviewed by our Director of Nuclear Operations. This review will be completed by January 1,1980. Additicnal control room manning, as discussed above, will allow the delegation of routine administrative duties to other control room personnel.

As explained in response to Item 2.2.1.b., the extra SRO is being added so that an SRO-Shif t Technical Advisor will be on each shif t. The additional SRO on each shif t will begin on January 1,1980.

}2b7

2-29 TITLE: Shif t Technical Advisor (Section 2.2.1.b)

NRC POSITION Each licensee shall provide an on-shif t technical advisor to the shift supe rvisor. The shift technical advisor may serve more than one unit at a multi-unit site if qualified to perform the advisor function for the various units.

The shif t technical advisor shall have a bachelor's degree or equivalent in a scientific or engineering discipline and have received specific training in the response and analysis of the plant for transients and accidents. The shift technical advisor shall also receive training in plant design and Ir,vut, iaciuding the capabilities of instrumentation and controls in the control room. The licensee shall assign normal duties to the shift technical advisors that pertain to the engineering aspects of assuring safe operations of the plant, including the review and evaluation of operating experience.

RESPONSE

As explained in Enclosure 3 of your September 13, 1979 letter, improvements are needed in the following two general areas:

1) Accident assessment capability

2) Review and utilization of operating experience.

Accident Assessment Capability As explained in response to Item 2.2.1.a we intend to increase shif t staf fing to include an additional SRO. This additional staffing will begin on January 1, 1980. During 1980 a portion of the station SRO's will begin an advanced training program to qualify them as shift technical advisors. During 1980 least one SRO who is participating in this training program will be on each shif t and will be designated as the shif t technical advisor (STA). In the event of an accident the shift technical advisor will withdraw from normal operational duties and will be dedicated to assessing plant conditions and advising the shif t supervisor.

The shift technical advisors will complete a training program including the following subject:

1. Thermodynamics

2. Fluid Mechanics

3. Heat Transfer

4. Fuel Element Metallurgical Characteristics

5. Natural Circulation

6. Reactor Cooling Alternatives

7. Transients / Accidents * - performed on the Surry Simulator (including, but not limited to)

a. FSAR accidents

b. Low RCS pressure

c. Low RCS flow

d. Loss of coolant

e. High RCS temperature

f. High reactor power

g. Uncontrolled cooldowns

• Will include multiple failures

\. F}

b

2-30 It is estimated that this program will involve approximately 160 hours0.00185 days <br />0.0444 hours <br />2.645503e-4 weeks <br />6.088e-5 months <br /> of classroom instruction and an equal time in independent study. Specific course details including content and schedul'_ng will be finalized by January 1, 1980.

During 1980, those SRO's in training for shif t technical advisor will complete the above training program so that beginning in January 1981 each shif t will be manned with a fully trained shif t technical advisor.

If during 1980, due to manpower constraints an SR0/STA in training is not available, we reserve the option of substituting a degreed engineer with at least two years of nuclear power plant experience.

Ir the longer term we intend to upgrade SRO training to include the above training so that all SR0's wi'1. be qualified as shift technical advisors.

Review and Utilization of Operating Experience Beginning not later than January 1,1981, an individual with the tspropriate technical knowledge and operating experience will be assigned full time to the review of internal and industry operating experiences. This person will ini-tiate improvements to plant facilities or operational practices based on the knowledge and erperience gained at our stations and throughout the industry.

This individual will insure that the praper personnel including the STA's and training personnel receive the necessar experience reports and implement the lessons learned from them.

During 1980, due to manpower constraints, this function will be performed by the Operating Supervisor.

\lb

2-31 TITLE: Shif t and Relief Turnover Procedures (Section 2.2.1.c.)

NRC POSITION The licensees shall review and revise as necessary the plant procedure for shift and relief turnover to assure the following:

1. A checklist shall be provided for the oncoming and of fgoing control room operators and the oncoming shif t supervisor to complete and sign. The following items, as a minimum, shall be included in the checklist:

a. Assurance that critical plant parameters are within allowable limits (parameters and allowable limits shall be listed on the checklist).

b. Assurance of availabilty and proper alignment of all systems essential to the prevention and mitigation of operational transients and accidents by a check of the control console (vhat to check and criteria for acceptable status shall be ir. eluded on the checklist);

c. Identification of systems and components that are in a degraded mode of operation permitted by the Technical Specifications.

For such systems and components, the length of time in the degraded mode shall be compared with the Technical Specifications action statement (this shall be recorded as a separate entry on the checklist).

2. Checklists or logs shall be provided for completion by the of fgoing and oncoming auxiliary operators and technicians. Such checklista er logs shall include any equipment under maintenance or test tha-by themselves could degrade a system critical to the prevention ani mitigation of operational transients and accidents or initiate an operational transient (what to check and criteria for acceptable status shall be included on the checklist); and

3. A system shall be established to evaluate the effectiveness of the shif t and relief turnover procedure (for example, periodic indepen-ent verification of system alignments).

RESPONSE

Presently, Administrative Procedures outline the requirements for shif t turnover. This procedure will be revised by January 1,1980 to incorporate signed of f checklists to verify that systems important to safety are not in a degraded mode. The checklist will verify that primary plant parameters are in a normal band, and system alignments (ie, breaker controls and valve switches) are in accordance with the requirements of the mode of operation which the Unit is in. The checklist will require that the Minimum Equipment Status Record be reviewed with a verification of the time remaining until the Limiting Condition of Operation must be satisfied or the mode of operation changed.

)lb b

2-32

2. 2.1.c page 2 Checklists will be implemented for the auxiliary operating stations which vill require that they list maintenance activities in the.i area on safety related systems which could af fect plant operation.

The checklists will require the signature of the oncoming and offgoing operator in each area and the oncoming shif t supervisor. These checklists will be implemented by January 1,1980.

The company quality assurance department conducts periodic audits and in-spections to verify compliance with administrative controls including shif t turnover procedures.

1 37 356

2-33 TITLE: Control Room Access (Section 2. 2. 2.a .)

NRC POSITION The licensee shall make provisions for limiting access to the control room to those individuals responsible for the direct operation of the nuclear power plant (e.g. , operations supervisor, shif t supervisor, and control room operators), to technical advisors who may be requested or required to support the operation, and to predesignated NRC personnel. Provisions shall include the following:

1. Develop and implement an administrative procedure that establishes the authority and responsibility of the person in charge of the control room to limit access.

2. Develop and implement procedures that establish a clear line of authority and responsibility in the control room in the event of an emergency. The line of succession for the person in charge of the control room shall be established and limited to persons possessing a current senior reactor operator's license.

The plan shall clearly define the lines of communication and authority for plant management personnel not in direct command of operations, including those who report to stations outside of the control room.

RESPONSE

Existing administrative procedures establish the line of authority from the Station Manager through the Superintendent Operations, Operating Supervisor and the Shif t Supervisor. The procedure is explicit in that it states that "the shift supervisor has the responsiblity of directing the actions of the station operators, to ensure safe and prudent operation of the facility".

The Superintendent Operations, Operating Supervisor, Shif t Supervisors and the Assistant Shif t Supervisors are SRO's as mandated by Technical Specifi-cation 6.2.2.

The administrative procedures will be changed by January 1,1980 to establish that the Shif t Supervisor or Assistant Shif t Supervisor has the authority and the responsibility to limit access to the control room during normal as well as emergency situations. The administrative procedure will establish clear lines of authority and responsiblity during emergency situations. Those persons in charge of the control room and with the authority to direct control room operations, shall be limited to Senior Reactor Operator licensed persons.

The administrative procedure will clearly define the lines of communication and authority for plant management personnel not in direct command of opera-tions, including those who report to stations outside of the control room.

The administrative procedure w111 clearly limit access to those individuals responsible for direct operation of the station plus other technical advisors as needed by operations. Technical advisors, including non-Vepco peraonnel will be limited in number during any emergency or abnormal conditions.

These administrative procedure changes will be completed by January 1,1980.

1237 357

2-34 TITLE: Onsite Technical Support Center (Section 2.2.2.b.)

NRC POSITION Each operating nuclear power plant shall maintain an onsite technical support center separate from and in close proximity to the control room that has the capability to display and transmit plant status to those individuals who are knowledgeable of and responsible for engineering and management support of reactor operations in the event of an accident. The center shall be habitable to the same degree as the control room for postulated accident conditicas. The licensee shall revise his emergency plans as necessary to incorporate the role and location of the technical support center.

Records that pertain to the as-built conditions and layout of structures, systems, and components shall be stored and filed at the site and accessible to the technical support center under emergency conditions. Examples of such records include system descriptions, general arrangement drawings, piping and it.atrument diagrams, piping system isometrics, electrical schematics, wire and cable lists and single line electrical diagrams. It is not the intent that all records described in ANSI N45.2.9-19-1974 be stored and filed at site and accessible to the technical support center under emergency conditions; however, as stated in the standard, storage systems shall provide for accurate retrieval of all pertinent information without undue delay.

RESPONSE

The Onsite Technical Support Center will be established in the Records Building.

The Records Build 2 ng is adjacent to the power station inside the protected security area. The Records Building has a complete controlled set of drawings, technical manuals, and other records which are properly stored and accesaible.

Communications w1:.1 be upgraded by establishing NRC phone systems in the build-ing as well as placing adequate commercial phones in the Center. The station PA system is also be available in the Center. We are investigating the installa-tion of a typewriter accessing the Unit 1 process computer in the OTSC. This typewriter could trend critical plant parameters for review by the technical support staff and consultants. If possible this installation will be completed by Janaury 1,1980. We are currentiv investigating a more versatile permanent data link for the OTSC.

The Emergency Plan and Emergency Plan Implementing Procedures (EPIP's) will be revised to incorporate the role of the Technical Support Center. The Onsite Technical Support Center will be established as soon as possible, but no later than January 1,1980. The Emergency Plan and EPIP's will be updated to reflect these changes by January 1,1980.

1237 35B

2-35 TITLE: Onsite Operational Support Center (Section 2.2.2.c)

NRC POSITION An area to be designated as the onsite operational support center shall be established. It shall be separate from the control room and shall be the place to which the operations support personnel will report in an emergency situation. Communications with the control room shall be provided. The emergency plan shall be revised to reflect the existence of the center and to establish the methods and lines of communication and management.

RESPONSE

Places of assembly at the onset of an emergency are designated by the Emergency Plan Implementing Procedures (EPIP's). The Emergency Director will announce that all persons are to report to their normal place of assembly for accoun-tablity. This plan of action immediately establishes a situation whereby the shif t supervisor or the Emergency Director can locate the needed assistance; i.e. H. P. Techs in 6he H.P. of fice, instrument techs in the instrument shop, etc.

The procedures will be changed whereby operators not required for control room operations will gather in the plant assembly room unless performing an operations function outside of the control room or otherwise instructed by the Shif t Supervisor. Existing procedures now instruct other emergency teams such as the fire brigade and the first aid teams to assemble in the plant assembly room so as to be readily accessible to the Emergency Director.

Other support groups such as Health Physics, Instrument Technicians, Chemistry Technicians, Engineers, and the maintenance personnel will assemble in their respective work areas.

Revised EPIP's will include specific instructions that prohibits their entry into the control room unless requested by the shif t supervisor. All of the above areas are served by adequate communications including commercial intraplant telephone and the station PA system. An intraplant telephone will be installed in the plant assembly room to allow bette communications from the Control Room to the Operations Support Center. A station PA system is already available.

Procedures will be revised to reflect the above changes by January 1,1980.

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3- 1 Section 3 Response to Enclosure 7 of September 13, 1979 letter, "Near Term Requirements for Improving Emergency Preparedness".

NRC POSITION (1) Upgrade licensee emergency plans to satisfy Regulatory Guide 1.101, with special attention the development of uniform action level criteria based on plant parameters.

(2) Assure the implementation of the related recommendations of the Lessons learned Task Force involving instrumentation to follow the course of an accident and relate the information provided by this instrumentation to the emergency plan action levels. This will include instrumentation for post-accident sampling, high range radioactivity monitors, and improved in-plant radiolodine instrumentation. The implementation of the Lessons Learned Task Force's recommendations on instrumentation for detection of inadequate core cooling will also be factored into the emergency plan action level criteria.

(3) Determine that an emergency operations center for Federal, State and Local personnel has been established with suitable communications to the plant, and that upgrading of the facility in accordance with the Lessons Learned Task Force's recommendation for an in-plant technical support center is underway.

(4) Assure that improved licensee of fsite monitoring capabilities (including additional thermoluminescent dosimeters or the equivalent) have been provided for all sites.

(5) Assess the relationship of State / local plans to the licensees' and Federal plans so as to assure the capability to take appropriate emergency actions. Assure that this capability will be extended to a distance of ten miles. This item will be performed in conjunction with the Office of State Programs and the Office of Inspection and Enforcement.

(6) Require test exercises of approved emergency plans (Federal, State, local and licensees), review plans for such exercises, and participate in a limited number of joint exercises. Tests of licensee plans will be required to be conducted as soon as practical for all facilities and before reactor startup for new licensees. Exercises of State plans will be performed in conjunction with the concurrence reviews of the Office of State Programs. As a preliminary planning bases, assume that joint test exercises involving Federal, State, local and licensees will be conducted at the rate of about ten per year, which would result in all sites being exercised once each five years. Revised planning guidance may result from the ongoing rulemaking.

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RESPONSE

(1) The Emergency Plan that is currently in effect at North Anna Power Station satisfies the requirements of Regulatory Gide 1.101.

(2) Our responses to the Lessons Learned Task Force recommendations regarding instrumentation to follow the course of an accident are included in Section 2 of this response. Existing emergency pro-cedures use currently installed instrumentation in establishing emergency action levels. By January 1, 1981, following installation of additional instrumentation, emergency plans will be revised to include definitive criteria for emergency action levels using the new and existing instrumentation.

(3) The station visitors center has been designated as the emergency operations center for Federal, State and local personnel. This facility will be upgraded in conjunction with the Onsite Technical Support Center. We are currently evaluating locations for an alternate emergency center. An alternate center will be designated by January 1, 1980.

(4) Offsite monitoring capabilities will be rev!'wed and improved as required by January 1,1980.

(5) We have reviewed state / local plans and are satisfied with their capa .ility to take appropriate emergency action.

(6) Emergency exercises for site personnel are conducted yearly. Coordinated emergency exercises involving Federal, State, and local agencies will be conducted every 5 years.

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