ML17272B062

Advises of Status of BWR Owners Group Technical Positions on NUREG-0578.Schedule for Submittal of Documents Encl

ML17272B062
Person / Time
Site:	Vermont Yankee File:NorthStar Vermont Yankee icon.png
Issue date:	10/17/1979
From:	Keenan T VERMONT YANKEE NUCLEAR POWER CORP.
To:	Eisenhut D Office of Nuclear Reactor Regulation
References
RTR-NUREG-0578, RTR-NUREG-578 NUDOCS 7910230474
Download: ML17272B062 (44)

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0 NUREG-0578 AND IMPLEMENTATION LETTER RE(UIREMENTS BMR OMNERS'ROUP IMPLEMENTATION CRITERIA Prepared by:

BMR OMNERS'UREG-0578 IMPLEMENTATION SUBGROUP October, 1979

FOREWORD This report contains generic BWR implementation criteria for the short-term requirements of the USNRC Lessons Learned Task Force (Ref. 1), as modified by the enclosures to the imple-mentation letter to operating plants (Ref. 2), and by the NRC interpretation presented at the Inspection and Enforcement Regional Meetings (Ref. 3). These criteria also include in-terpretations drawing from formal and informal discussions with the NRC staff, notably from a September 20, 1979, meeting to discuss oeneric LWR issues relative to NUREG-0578 imple-mentation, and from Topical Meetings on selected issues on October 10-12, 1979.

These criteria were developed by the BWR Owners'roup NUREG-0578 Implementation Subgroup for use by individual utilities in preparing their own NUREG-0578 implementation comnitments as reauired by Reference 2. This document does not constitute or imply a commi talent by any individual utility to the criteria:

such comnitments will be made by each utility individually, and there will necessarily be plant-specific differences.

Each implementation criterion is prefaced by a statement of the NRC position and a discussion of the BMR Owners'roup position.

For compactness, the N:lC positions from the main text of NUREG-mittall 0578 are cited: the Owners'roup has, however, used the more detailed positions in Appendix A of NUREG-0578, plus References 2 and 3, for definitive guidance.

The following NUREG-0578 requirements are not part of this sub-for the reasons stated:

2.1.5A: Criteria will be plant-unique 2.1.5B: Deferred for additional study by USNRC 2.1.5C: Criteria will be plant-unique 2.1.7A: Applies only,to PMRs 2,1.7B: Applies only to PWRs 2.2.3 : Deferred for additional study by USNRC Requirement 2.1.1, although intended to apply strictly to PMRs, has been examined for its applicability to BMRs and is included in this submittal.

FORE'JORO (p. 2)

References:

l. USNRC, "TMI-2 Lessons Learned Task Force Status Report and Short-Term Recommendations." NUREG-0578, July, 1979.

2. Letter, D. G. Eisenhut to All Operating Nuclear Power Plants, "Followup Actions Resulting From the NRC Staff Reviews Regarding the Three Mile Island Unit 2 Accident,"

September 13, 1979.

3. USNRC, "Regional Meetings - TMI Short-Term Implementation Action," handout material at Inspection and Enforcement Regional Meetings, September 24-28, 1979,

NURER-0678 Reouir ement 2. 1.1:

0 "Emergency Power Supp'ly Requirements Por the Pr'assur1zar Heaters, Power<perated Relief Yalves, and Pressurizer Level Indicators in PMRs" Provide redundant emergency power for the minimum number of pressurizer heaters required to maintain natural circulation conditions in the event of loss of offsite power, Also provide emergency power to the control and motive power systems for the power-operated relief valves and associ-ated block valves and to the pressurizer level indication instrument channels.

Discussion:

As discussed in NED0-24708, natural circulation 'in the BMR is strong and inherent in all off-normal modes of operation, independent of any powered system, as long as sufficient inventory is maintained. This is because even in normal operation the BMR is essentially an augmen ed natural circulation machine. Because the BMR operates in all modes with both liquid and steam in the reactor pressure vessel, saturation conditions are always maintained irrespective of system pressure (the BMR does not nave a pressurizer). Thus there is no need for emergency power to maintain natural circulation or to keep the system pr essurized, The power-operated relief valves in BMR's are already powered by emergency power. They have no block valves.

The reactor vessel level indication instrument channels for safety system activation and control are already powered by emergency power.

BMR Owners'roup Imvlementation Criteria:

For the reasons stated above, there is no need for action in response to Reconmendation 2.1.1 for any General Electric BMR.

NUREG-0578 Requirement 2.1.2: "Performance Testing for BMR and PMR Relief and Safety Valves" Comit. to provide performance verification by full scale prototypical testing for all relief and safety valves. Test conditions shall include two-phase slug flow and subcooled liquid flow calculated to occur for design-basis transients and accidents, Oiscussion:

The BMR design basis includes no transients or accidents in which two-phase flow or subcooled liquid flow at high pressure througn relief, safety/

relief, or'afety valves is calculated or expected~. The BWR therefore satisfies the intent of the requirement in the strictest sense. The need for performance veriiication, nowever, has been stuaiea in a broader sense. Tne remainder of this discussion is intended to demonstrate that performance verification in the field fully satisfies the broad intent of the requirement.

In determining the need for special testing of BMR safety and relief valves it is essential to consider the service duty to which the primary system relief and safety valves of the BMR are exposed, and the conse-quences of maloperation of these valves. Relief valves are routinely used to mitigate the effects of system transients. A stuck-open valve is no. an event of great significance in a BMR: in 300 reactor years of experience, 54 cases have occurred. Tables 2.1.2-1 and 2.1.2-2 smrari=e the experience to date. This experience, as will be explained, clearly shows that there is no need for an ex ensive testing program for BMR safety and relief valves.

A. BMR Safety and Relief Yalves Table 2.1-3 of NEDO-24708 shows tl e complement of safety and relief valves for all domestic operating BMR's. Most BMR's have relief valves or dual-function safety/relief valves (5/RV), the discharges of which are piped to the suppression pool. Spring safety valves discharge directly to the drywell (or the containment in a drv containment), except for Humbold Bay, in which the sa ety valves discharge to the suppression pool.

B. Valve Usage (1) Relief valves and dual-function S/RY 's in BMR/2-6. The relief valves and dual-function S/RV's are designed to rou inely mitigate the effect of system transients".Their discharges are pip'ed to the containment suppression pool. This massive hea. sink prevents significant containment heatup. Compli-cation of a system transient by a stuck-open valve has es-sentially no 'effect on reac or vessel water level measur ment or on forced or natural circulation capability. The flow through the valve is saturated steam. If the valve cannot be closed by opera. or ac.ion the plant can be shut down using ,amiliar and uncomplica-.ed proc dures.

"Liquic flow is expe ted as an alternate shutdown mode in some units.

Tnis flow, however, is controlled and occurs at low pressure.

2.1.2 (p. 2)

B. (2) Spring safety valves in BWR/2-4. The safety valve set-point is sufficiently higher than the relief valve set-point that the safety valves are almost never required to operate (Table 2.1.2-3 documents the three cases in which safety valves have ever listed in BWR operation). Should a safety valve in-advertently lift, which has never happened in BMR operation, the effect is the same as a small steam line break inside containment. Even in this renote event, the flow through the valves will be saturated steam at all times.

(3) Dresden 1. For pressurization events, such as a turbine trip, the two relief valves, which are located downstream of the main steam isolation valves (NSIY), are sized to relieve pressure directly to the main condenser without requiring safety valve action. In the event of MSIY closure, reactor scram is in..tiated from HSIY position switches, which also initiate the redundant isolat'.on condensers. Even one isolation condenser will limit reactor pressure to well below the safety valve set-point. The results of a stuck-open safety valve would be as described in (2) above.

(4) Big Rock Point. An isolation condenser is provided, containing redundant cooling 1oops either one of which (when automatically actuated at 1450 psig) keeps reactor pressure below the spring safety valve mt-point. The results of a stuck-open-safety valve would be as described in (2) above.

(5) Humboldt Bay. All spring safety valves are piped to the contain-ment suppression pool. Therefore, the results of a stuck-open valve would be as described in (1) above.

C. Two-Phase Flow.

Expected operating conditions and transients do not include two-phase flow throuah S/RY's, safety, or relief valves. However, on three occasions, circumstances combined to cause high pressure water to flow down the steamlines and a steam/water mixture to flow through the valves. A sugary of these events is given in Table 2.1.2-3.

In these events, =lectromatic relief valves and direct acting safety valves were actuated, discharged a steam/water mixture and reclosed, indicating that the flow media did not cause a stuck-open valve condition. These events did not lead to any concern over adequate cor e cooling. However, following these events, high water level trips were added to all new BWR's and. retrofitted to most of the BWR's in oper ation.

Valve gualifica ion.

(I) Crosby, Oikkers, Okano and two-stage Target Rock S/RV's are test% for the expect d saturated steam flow conditions. This includes life-cycle testing of 300 ac uations as well as environmental qualifications including seismic, thermal, mechanical and radiation effects.

(2) Three-stage Target Rock S/RV's were subjected to restricted flow steam tests to qualify the set-point and valve opening time delay. Solenoid valves (used during power actuation) are qualified by autoclave test for the LOCA environment.

Satisfactory valve operation has been demonstrated by field service.

(3) Oresser EIectromatic relief valve solenoids were qualified by autoclave test f'r the LOCA environment. Satisfactory valve operation has been denonstrated by field service.

(4) Satisfactory operation of Oresset safety valves has been demonstrate by field service.

Field ~wperience Since 1971 there have be n ""0 events in BWR plant operation wherein S/RV's have stuck open (Table Z.I.Z-I). ln each of these cases the reactor was depressurizM, the stuck valve was repaired or replaced, and the plant was placed back into service.

Although a s uck-open S/RV is of no significant sa ety concern in the BWR, programs are underway to reduce the frequency of such events.

From Table 2.1.2-1 it is seen that the total number of S/RV blowdowns has steadily decreased since the mid-70's. The improvenent in the number of S/RV blowdowns as a factor of number of S/RV's in service has be n even more drama ic.

From Table Z.I.Z-2 it is se n that experience with soring safety valves and Iectroma ic r lief valves has always be n good: the.

have be n only four blowdowns.

F. Sumary (1} BWR S/RV's are routinely t s ed for the only expec.ed mode of opera ion (saturated steam), both by in-place unctional tes:s and by -,",equent usage in mitiga ing plant transients; (Z) i'nore is no des gn-oasis transient or accident which reouires sa-,e-.y, r iie., or dual -,unc-ion S/RV's to pass two-pease or liquid low a- high pressure; (3) '.nadvet-.en passage of iso-phase flow is not likely whe.

hign pressure fe~water and injection sys-~ms are ~ipped by h gh vesse: water level.

2.'l.2 (p. 4)

F. (4) In the three events wherein BWR S/RY's did pass two-phase flow, the valves reclosed; (5) Spring safety valves are almost never required,to open; in the even less likely event that one should stick open, the effect is identical to that of a small steam line break.

There is no concern for adequate core cooling.

(6) Electromatic relief valves and dual-function S/RV "s are frequently called on to operate, and dual-function S/RV's occasionally stick open. The consequences of a stuck-open valve are minimal and reactor shutdown is uncomplicated, as proven by numerous field occurrences. In some BMR's the procedures for responding to a stuck-open relief valve include's the opening of additional relief valves. Improve-ment prograrrs are r~cing the frequency of such events.

BMR Owners'roup Implementation Criteria:

It is concluded that concerns regarding safety/relief valve performance have been addressed and no special performance testing is required provided that the following criteria are met:

(1) A procedure shall exist for responding to a stuck-open relief, safety/relief, or safety valve.

(2) The procedures shall address prevention of inadvertent overfilling of the reactor vessel.

(3) Control grade systems, actuated by reactor vessel high water level, shall be provided to prevent the fe dwater and high pressure injection systems from over illing the vessel (or steam drum, on plants so equipped).

(4) S/RV performance in "Alternate shutdown" mode will be specifically addressed, and a justification of why a tes is not needed will be provided.

TADLE 2.1.2-1 S/RV OLOWDOWNS IN DWR OPERATION 2-STAGE CROSBY-OKANO-TOTAL 3-S1AGE TARGET ROCK TARGET ROCK DIKKERS DLOWDOMNS TOTAL TOTAL DIVIDED STUCK OPEN N OF 5 OF N OF S/RV S/RVs DY TOTAL TOTAI FOLLOWING VALVES IN TOTAL VALVES IN TOTAL VALVES IN BLOW- IN VALVES IN .

YEAR DLOWDOLJNS l)EtSHD SERVICE DLOWDOWNS SERVICE OLOWDOWHS SERVICE DOMNS SERVICE SERVICE 1971 14 14 0.15 1 &72 23 23 0.04 l973 56 0.02 1974 10 108 10 108 0.09 1975 127 127 0.06 1976 149 149 0.07 1977 157 0.06

) 978 157 35 5 203 0.02 1979 to 132 36 52 4 220 O. 02 Sept.

NOTE: The above table does not include Dresser Safety Valves (unpiped Ukscharge) or "Electromatic" relief valves. See Table 2.1.2-2 for information on this equipment.

2.1.2 (p.G)

TABLE 2.1.2-2 SAFEiY AND ELECTROMATIC RELIEF VALVE BLOWOOWNS IN BWR OPERATION A. Safety Valves.

Only one event has ever occured with partially stuck open valves-the Dresden 2 event described in Table 2.1.2-3. The lifting levers which cocked the valves partially open were subsequently removed from safety valves at all plants and there have be n no further .

occurrences. There have only been three occurrences in which

'sa ety valves have ever lifted during operation (see Table 2.1.2-3).

The total number of valves in service is 76(l).

B. Electromatic Relief Valves.

There have been three Occurrences of a stuck open Electromatic relief valve, two of whig) followed a demard. The number of valves in service. is 37.~')

"'Some M's are in the "rocess of replacing safety valves and Eiectrcmatic relief valves w-:, h Target Rock S/RV's.

2.1.2 (p.7)

TARLE 2.1.2-3 EVENTS IN MHICH TMO-PHASE FLOM CR LIQUID PASSED THROUGH BMR SAFETY OR RELIEF VALVES DRESDEN 2 - JUNE 5 1970 During the course of the initial test program on Dresden 2 with the unit operating at 7 5% power, a spurious signal in the reactor pressure control system cccurred. This spurious signaI resulted in simultaneous opening of the control and the turbine bypass valves with resultant turbine trip, reactor scram, and main steamline isolation.

In response to the initial and expected water level drop, the operator switched to manual control of the feedwater system and began filling the reactor vessel at the maximum rate. Mater level misinterpretation led to reactor water overflowing into the main steam lines. A pressure surge resulted in the main steam lines when relief valves were cycled.

This momentarily opened one of the safety valves, resulting in a discharge directly to the containment (unpiped discharge). The fluid impinged upon the lifting levers of two other safety valves causing these safety valves to cock slightly open. The water-steam mix.ure from the two safety valves pressurized the primary containment to an estimated 20 psig and an estimated temperature of approximately 300oF.

At no time during the event was ther e difficulty maintaining adequate water supply to the reactor core, and there was no question of adequate core cooling.

DRESDEN 3 - DECEMBER 8 1971 Unit 3 was operating about 98" power on December 8, 1971, when the plant was shut down due to a reactor low water level scram. The scram resulted from a condensate/condensate booster pump trip and the sub-sequent trip of two reac.or feed pumps on low suction pressure. Follow-ing the scram, the standby feed pump s arted. The vessel was over-filled and the s.earn lines flooded. Due to a pressure sur ge in the main steam lines, a safety valve lifted causing discharge directly to the containment (unpiped discharge) . The containment was pressurized to approximately 20 psig. At no time during the event was there difficulty maintaining adequate water supply to the reac.or core, and there was no ques ion of adequate core cooling.

KRB (G-"RNNY - JANUARY 13. 1977 The unit was opera.ing a 100~ power when a bus on two of its 200 KV lines opened. The plant was scrammed and isolated. Manual feedwa.er,

2.1.2 (p.8) ~

TABLE 2.1.2-3 (cont'd) control was initiated which resulted in flooding of the steam lines.

Safety valves opened and discharged water, steam and two-phase media.

The valves discharged directly to the containment (unpiped discharge).

The safety valves opened and reclosed several times. Because of the unique piping arrangement (which is not present in any US-B4R), r e-action forces of the discharging valves caused or contributed to a pipe rupture in two of the fourteen flanged nozzles by which the valves are connected to a U-shaped header. At no time during the event was there difficulty maintaining adequate water supply to the reactor core, and there was no question of adequate cor e cooling.

iNUREG-0578 Re uirement 2.1.3A; "Direct Indication of Power&perated Relief Valve and Safety Valve Position for PMR's and BMR"s" Provide in the control room either a reliable, direct posi ion indication for. the valves or a reliable flow indication device downstream of the valves.

Discussion:

BMR safety and relief valves are arranged in three ways in the various operating reactors:

1) Valve discharges piped to the containment suppression pool;

2) Valve discharges manifolded and piped to suppression pool;,

3) Discharging directly to the drywell free volume, in pressure operator free volume suppression containments, or to the containment in dry containments.

The configuration of the valve discharge, and the 's ability to diagnose and act on stuck-open valve events, will determine what informa-tion is to be provided in the control room. The environment experienced by he installed instrumentation during a stuck-open valve event will determine the proper qualification requirements.

A. Valve Discharges Individuall Piped to the Suppression Pool.

All dual-function safety/relief valves and most relief valves are configured this way. Given a stuck-open valve, the cont inment pressure will not increase because of the submerged discharge.

There is benefit in direct indication, not only because the operator would be given an early warning of S/RV discharge, but because he can attempt to reseat a stuck-open valve from the control room.

Hos such valves have no external stem, which precludes direct position indica ion.

B. Valve Discharges Mani olded and Piped to the Suoor ssion Pool.

Relief valves in one domestic BMR are configured this way. The system r sponse and operator action considerations are identical to those for valves piped individually to the suppression pool.

A pressure switch in each discharge manifoId will give a positive indica.ion that one of the two ot three valves on each manifold is open or closed . The exis ing temperature sensors in he discharge of each valve will then be su ficient to determine exac ly which valve has ac.uated, so that the operator can attempt to reseat i ..

.2.1.3A (p.2)

C. Valves Oischaroe Oirectl to Containment or Or el 1.

All spring safety valves are configured this way. Because these valves are large (200,000 to 940,000 Ibm/hr capacity per valve) compared to the containment free volume, a stuck-open valve will cause a rapid rise in containment pressure, causing almost imediate scram and ECCS operation in most units and an unambiguous indication of loss of coolant in all. Because the valves discharge steam from the steam drum or main steam lines into the containment, the effect of a stuck-open valve is identical to a small main steam line break. Because the operator has no capability of attempting to re-seat a stuck-open safety valve from the control room, his actions would be identical to those for a main steam line break (that is, whether the "LOCA" is due to a stuck-open valve or due to a. pipe break is of no interest in operator action). Sprina safetv valves almost never open in BHR's, but even if one were to open and remain open, tre-phase flow would not be exoected, as shown in a4 events of stuck-open relief valves of similar capacity in operating BMR's (se Owners 'roup position on NUREG-0578 Requirment 2.1.2).

High reactor water level rips preclude water in the steam lines in most uni w, and operators are sensitive to the undesiraoility of overfilling the reactor vessel or steam drum in all units. Thus there is no need for special pre autions due to the possibility of

~-phase flow in the valves. Even i the valve were to reseat, the opera or's action would be no different than for a small steam line break (maintain 'reactor water level, depressurize the reactor, cool the suppression pool). For all of these reasons, the existing high drywell or containment pressure instrumentation provides all the information the operator can use in analyzing and acting on a stuck-open spring safety valve. Exis ing instrumentation is there-fore a suf iciently "reliable flow indication device" for spring safety valves.

BMR Owners'roup ImoIementation Criteria:

A. Valve Oischaraes Individuallv Piped to the Suppression Pool.

The Owners'roup considers ~retypes of monitoring to be acceptable methods of positive valve indication: pressure switches in the valve discharge lines and acoustic monitors.

A suitable pressure switch sys=em is outlined in the Appendix, in r sponse o an NRC request in the September 24, 1979, Region I meeting, Either type of system will be designed to the following broad requirements:

(1) Ther will be at Ieas one sensing device per discharge line; (2) Sensing devic s may be ei:her inside or outside the drywell; (3) Sensing devices anc ".Der ccmoonen== need not be qua'ied for a ~

OV, (pipe break) envi~ruren-, bu= only for the env;ronment expec:ed during S/RV discnarge :o the suppression oool;

',Z.t.3A (p.3)

()4 All corn p onents will be seismicall ualified (5) The system will be powered by one division of emergency power; (6) Hith sensing devices inside the drywell, non-class-IE electrical penetrations may be used if insuffiaient IE penetrations are available; S. Valve Discharges Manifolded and Piped to the Suppression Pool:

A single pressure switch in each manifold, otherwise conforming to "A" criteria above, H

will be provided.

C. 'Valves Discharge Oirectl to Containment or Dr ell.

No further action is necessary based on the discussion above.

2.1.3A (p.4) ~

APPENDIX to OMNERS GROUP POSITION 2 1 3A USE OF DISCHARGE PIPING PRESSURE SMITCHES FOR S/R VALVE POSITION MONITORING Main stem position is not accessible on the manufacturer 's designs of safety/relief valves in 8MR service. General Electric has evaluated several concepts including magnetic or proximity switches, acoustic devices, temperature, and pressure switches.

The use of pressure switches on the discharge lines has been selected as the most simple, direct and proven technique for monitoring valve position. The Safety/Relief valve discharge is piped to the torus, discharging below the water line. Pressure near the valve discharge can be straight orwardly calculated and tested; it. is in the range of 250 psig when the reactor is at rated pressure. This pressure is sufficiently high that a positive and unambicuous signal is available with ample margin for tolerances in set point calibration. Mhen the valve re-closes, pressure returns to normal in a fraction of a second.

Thus a pressure signal does not have the slow response time which charact rizes temperature .monitoring.

Test data are available confirming the transient and steady-state response of S/RV discharge line pressure. These data were obtained during extensive in-plant measurements ot suppression-pool loading resulting trom safety relief valve actuations. These test data confirm the analytical basis for selection of set points.

Pressure switches are available in industry which are suitable for this service.'imilar devices are used routinely for the protection of plant and equipment. Plant personnel will be familiar with tne calibration, testing, and maintenance of these devices. No development testing is required to orove a satisfactory device, other than qualification tests which would be requirec for any device.

Mith the use of pressure switches, no device is mounted on or near the safety/reIief valve. The technique will work tor all types of piped BMR safety/relief valves in service. It will have no effect on valve pertormance. The pressure switches may be located at some distance from the safety/relief valve where they wi(l not be subjected to severe

.emperature or vibration conditions. where suitable piping penetrations are available it is possible to locate the switches outside the drywell.

The pressure switches will be qualified for a 212oF, 100" humidity environment. Tnis is adequate for the intended service even if .ne pressure swi .ches are inside the drywell because actuation of tne S/R valves, inadver-ent or planned, will not cause hese environmental

2.1.3A (p.S) ccnditions to be exceeded. In the event, of a small pipe break the safety/relief valves in the ADS system would be initiated early in the transient, before degradation of the switches could have occurred. In the event of a large pipe break the safety/relief valves are not required to ooerate. No failure mode has been identified that would result in an erroneous indication that the valve was open.

The signals from pressure switches may be interfaced arith indicating lights, control room annunciators, an event counter, or the process computer. Any one or all of these functions may be implemented, Each safety/relief valve can be monitored independently of the other valves.

NUREG-0578 Re uirement 2.1.3B: "Instrumentation for Detection of Inadequate Core Cooling in PMR's and BMR's "

Perform analyses and impl ment procedures and training for prompt recognition of low reactor coolant level and inadequate core cooling using existing reactor ins.rumentation (flow, temperature, power, etc.)

or short-term modifications of existing instruments, Describe further measures and provide supporting analyses that will yield more direct indication of low reactor coolant level and inadequate core cooling such as reactor vessel water level instrumentation.

Discussion:

Additional hardware to identify inadequate core cooling on BMR's has not been determined to be necessary at this time. Licensees 'rocedures will identify the diverse methods of determining inadequate core cool-ing, using existing ins rumentation. The results of analysis being performed in resoonse to 2.1,9 will be factored into procedures as re-auired, after the analysis is complete.

. Because the BMR operates in all modes with both liquid and steam in the reac or pressure vessel, saturation conditions are always maintained irrespec.ive of system pr essure. This here is no need for a subcooling meter in the BMR.

BMR Owners'roup Implementation Crite. ia:

1) Analyses and operator guidelines for .he detection and mitigation of inadequate core cooling are currently being developed per Require-ment 2.1.9 and questions from the Bulletins and Orders Task Force.

These studies include an evaluation of currently ins alled reactor vessel water level instrumentation, and the possible use of other instrumentation, to detect inadequate core cooling. The need for futher measures, if any, will be addressed after these analyses Implementation of emergency-and operator guidelines are complete.

procedures and retraining will be done on a schedule consistent with those established with the Bulletins and Orders Task Force.

2) A subcooling meter, as required by Enclosure 6 of the NUREG-0578 impleaentation letter of September 13, 1979, will not be provided.

NUREG-0575 Reonimaent 2.1.4: "Containment Isolation Provisions for PMR's and BNR's "

Provide containment isolation on diverse signals in conformance with

'Section 6.2.4 of the Standard Review Plan, review isolation provisions for non-essential systems and revise as necessary, and modify contain-ment isolation designs as necessary to eliminate the potential for in-advertent reopening upon reset of the isolation signal,.

Discussion:

There is diversity in the parameters sensed for the initiation of BWR containment isolation. Following an isolation, deliberate operator action is required to open valves in most cases.

BWR Owners'rou Implementation Criteria:

1) Oiver si.y of parameters sensed for the initiation of containment isolation shall be provided in -accordance with SRP 6,2.4,

2) A review shall be made of all systems penetrating primary contain-ment to identify all essential systems. The basis of such classi-fication shall be documented and supplied to the NRC.

3) All systems not identified as essential will be reviewed. If auto-ma ic isolation is not provided, justifica'tion for not isolating will be presented to the HRC.

4) Licensees will review and modify isolation control systems and administrative controls, as aporopriate, such that no isolation valve will open when the isolation logic is reset. Those plants that have valves that will automatically open when the isola ion logic is reset, will change the isolation logic to prevent the valves from opening when reset. Administrative controls to prevent valves from reopening will be implemented by 1/1/80; logic modifi-cations will be implemented by 1/1/81.

NUREG-0578 Reauir ement 2.1.8b: "Increased Range of Radiati'on Monitor s" Provide high range radiation monitors for noble gases in plant effluent lines and a high-range radiation monitor in the containment, Provide instrumentation =or monitoring e luent release lines capable of measuring and identifying radioiodine and particulate radioactive effluents under accident conditions.

Oiscussion:

The Owners'roup recognizes and concurs with the position as modified in the NRC regional meetings the week of September 24, 1979.

SMR Owners'roup implementation Criteria:

1) The Owners will implement the requirements of position 2.1.8b, items 1, 2, and 3, consistent with coamercial availability of equipment.

2) Procedures will be developed to es imate noble gas and radio-iodine release rates if the existing ef luent instrumentation goes o f scale.

HUREG-0578 Reouirement 2.1.8c: "Improved In-Plant Iodine Instrumentation."

Provide instrumentation for accurately determining in-plant airborne radioiodine concentrations to minimize the need for unnecessary, use of respiratory protection equipment.

Oiscussion:

The Owners'roup recognizes and concurs with the position.

BMR Owners'roup Implementation Criteria: E

1) The Owners will implement, the requirements of position 2.1.8c.

2) Procedures will be developed to accurately determine in-plant iodine concentrations.

NUREG-0578 Requirement 2.1.9: "Analysis of Design and Off-Normal Transients and Accidents"

a. Provide the analysis, emergency procedures, and training to substantially improve operator performance during a small break loss-of-coolant accident.

b. Provide the analysis, emergency procedur es, and training needed to assure that the reactor operator can recognize and respond to conditions of inadequate core cooling.

c. Provide the analysis, emergency procedures, and training to substantially improve operator perfonnance'during transients and accidents, including events that are caused or worsened by inappropriate operator actions.

Discussion:

The speci ic requirements and schedules are being developed in a continu-ing series of meetings between the utility owners'roups and the NRC Bulletins and Orders Task Force.

BMR Owners'roup Implementation Criteria:

The implementa.ion of emergency procedures and retraining will be done on a schedule consistent with those establlished with the Bulletins and Orders Task Force.

NURES-0578 Reouirement 2.2.1.a: "Shiit Supervisor's Responsibi1ities" Review plant administrative and management procedures. Revise as necessary to assure that reactor operations command and control re-sponsibilities and authority are properly defined. Corporate manage-ment shall revise and promptly issue an operations policy directive that emphasizes the duties, responsibilities, and authority and lines of command of the control room operators, the shift technical advisor, and the person responsible for reactor operations command in the contro1 room (i.e., the senior reactor operator).

Discussion:

The Owners'roup agrees with the intent of the staff's position. How-ever, in order to remove any ambiguity from the meaning of the term "accident situation" in item 2.b of the staff's position in Appendix A of NUREG-0578,* the entire sentence will be interpreted as follows: The shift supervisor (or equivalent, such as the supervising control operator in some plants), until properIy relieved, shall r emai.n in the contr'ol room at all times whenever a site or aeneraI emeraenc has been declared to direct the activities of control room operator s.

BWR Owners'roup Implementation Criteria:

The staf,'s position will be implemented as stated and subject to the interpretation o item Z.b as discussed above.

"Z.b rhe shi t supervisor, until prooerly relieved, shall remain in the control room a- all times during accident situations o direc: the ac".ivities of control room operators. Pe. sons author-';zed to relieve .he shift supervisor shall be spe .fied,

HUREG-OS78 Re uirement 2.2.lb: .

Shiftf Technical Te Advisor" t each nuclear power plant a qualified person (the isor with a bachelor's degree or equivalent in a d th pecif c t a' i the plant response to off-normal events an d 'ccident analysisg of sn the plant.

t ertain to the engineering aspects of assuring sa e operations of the plant, inc u ing thee review and evaluation of n ludin operating experience.

Discussion:

ift Technical ope 1

'h Advisor (STA) as proposed by the Task ineer independent and detached from plant f 11 o of ld d tob' 1' h d t li d o to to th controls of the reactor plant. He wou would bee em empowered ow to advise operations but not responsible to operations for his advice.

ctl charged with the responsibility for safe at all times, During th e ear 1 h f d t e s arges ih s respon sibility by coor d'ina in d d' th being governed by their training and nd emergency pro procedures, and during this pnase the entire control roo op "lyo >" po

'h p

n th hift '

h ffi t o " t o of th 1 tbt f 11 sider an indeoendent assessment n conflicts between his and the independent t, d 'd to lt th ors Dialog di g s h a a t o i e spen esolvi g such o i o1 di t t dd 1 th h'ft supervisor and consequently degrade the response o tc the accident.

2.2.lh: "Shift Technical Advisor" (p. 2)

Even though the roles of shift supervisor and STA can be carefully delineated by procedure and training, industrial and military experience indicates that a direct-line organization wherein authority and responsi-bility are interdependent is required to effectively operate in a crisis environment. The proposed STA is empowered to advise operations but not responsible to operations for his advice,, His authority and responsibility are not interdependent. A potential for conflict and confusion exists which cannot be completely eliminated by procedure or training because procedure and training can address only those event sequences which have been postulated in advance. One important lesson learned from the ex-perience at Three Nile Island and at other facilities is that not all event sequences can be postulated in advance. Therefore, an al.ernative which avoids this potential for conflict and confusion but improves the functions intended by the proposed STA is recommended.

Two functions are intended to be improved by the proposed STA: (1) accidest assessment and (2) operating experience assessment, In order to improve -.ne accident assessment function while avoiding the degradation in accident response which accompanies the proposed STA, the course of an accident is considered in three sequential phases: immediate, intermediate, and recovery.

The imediate phase extends from the point at which an abnormal condition affec.ina plant safety can be detected in the. control room until the point at which the shift supervisor has sufficient time to carefully consider an independent assessment and, on the basis of such assessment, decide to alter the procedural actions of the operators. The intermediate phase extends from the end of the immediate ph'ase until the point at which the Technical Support Center (TSC) is manned and ready, The recovery phase extends from the end of the intermediate phase until the point a. which recovery is complete.

'k For the immediat phase, the accident assessment function can be improved only as', by upgraded training to encnance the operators'bilities to recognize, diagnose, and respond to accident conditions. During this phase the operators'ctions are governed by training and emergency procedures and by definition there is insu,ficient time for the careful consideration of an independent assessment which would be required before such an assessment could become the basis for altering the procedural actions of the -operators.

For the intermediate phase, the accident assessment function can be improved by either of two alternative means. An operator can be educated in science and engineering in order that he might provide an assessment which could be considered and acted upon by the shif supervisor. Alternatively, a graduate engineer or equivalent can be trained in plant operations and made available to the shif. supervisor on call in order tha he might provide such an assessment. In either case, the shift supervisor must have sufficient time to carefully consider the assessment and, based on such assessment, decide to al er the procedural actions of the operators.

2.2.lb: "Shift Technical Advisor" (P.3)

For the recovery phase, the accident assessment function can be improved by manning the TSC. The collective engineering resource within the TSC will be able to develop a detailed independent assessment of plant conditions and provide appropriate procedures with which to recover from the accident.

The operating experience assessment function can best fa provided by a team which reviews operating .experience at the plant and at plants of like design.

Varying team membership as appropriate to the operating experience being assessed assures accomplishment of this function by the best qualified individuals.

8WR Owners'roup Implementation Criteria:

The two func.ions intended to be improved by the proposed STA will be improved as follows:

l. Accident Assessment

a. Imediate Phase An'perator or supervisor in the direct operational chain of comand on each shift (norm'ally in charge in the control room) will receive additional specific training in the response and analysis of the plant for transients a~1 accidents, This training wi 11 be coordinated with the schedule for preparation and review of analysis and guidelines under the NRC 8ulletins and Orders Task Force.

All operators and supervisors will receive additional training appropriate to their responsibilities in the response of the plant to transients and accidents. This longer term training and qualification criteria will be provided by the Institute of Nuclear Power Operations.

b. Intermediate Phase (Alternatives}

An operator or supervisor in the direct operational chain of command on each shi>t will receive substan ial additional education in basic engineering and science sufficient to aid him in assessing unusual situa ions not explicitly covered in the current operator training.

-OR-A graduate engineer or equivalent trained in the response and analysis of the plant for transients and accidents and in plant design and layout, including the capabilities of ins rumentation and controls in the control room, will be available to the individual in charge in the control room on call. He may be stationed on or off site as aopropriate to plant location, communication capabilities, operator training and education, extent and detail o emergency proc dures, e-.".

2.2. lh: "Shift Technical Advisor" {p.4)

c. Recovery Phase Individuals knowledgeable of and responsible for engineering and management support of reactor operations in the event of an accident will be available on call to staff the On-Site Technical Support Center.

2. Operating Experience Assessment Where it does not already exist, a team will be. designated by the licensee to assess the operating experience at his plant or plants and at plants of like design. Team membership may vary as appropriate to the operating experience being assessed but will include experience in systems engineering and familiari y with or routine access to persons experienced in the principles of human engineering or human factors,

NUREG-0578 Requirement 2.2.1.c: "Shift and Relief Turnover Procedures" Review and revise plant procedures as nec ssary to assure that a shift turnover checklist is provided .and required to be completed and signed by the on-coming and off-going individuals responsible for con+and of operations in the control room. Supplementary checklists and shift logs should be developed for the entire operations organization, including ins rument technicians, auxiliary operators, and maintenance personnel.

Discussion:

The Owners'roup agrees that knowledge of plant status, especially for those systems requird to mitigate the consequences of an accident, should be transferred in a systenatic manner from one shift to Ne next. The Group is also convinced that to be most effective as a means of .infor-mation transfer in the course of a shift or relief turnover, the infor-mation must be limited to that which can be sumnarized on a single list on a single piece of paper. Furthermore, the information provided by the lis. should be reviewed not only by the shift supervisor and control room operators, bu. by other plan personnel (auxiliary ope. a.ors, te h-nicians, etc.) as appropriate, thus eliminating the need for separate checklisw, as apparently required in the staff's position.

BMR Owners'roup kmolenentat'on Cri eria:

1) A checklist will be devised zo ensure that control room status of sys ems that are r~uired to mitigate the consequences of an accident are monitored on a shift turnover basis. This list will include systan lineups and alarms located in the main control room.

Systems and components in a degraded condition will be iden ified as requir d by plant sta us.

2) The checklist will be kept in the control room at all imes.

3) The checklis . will be reviewed by personnel other than the shif, supervisor and control room ooerators as appropriate.

NUREG-OS78 Requirement 2.2.2.a: "Control Room Access" Review plant emergency procedures, and revise as necessary, to assure

. that access to the control room under normal and accident conditions is limited to ".hose persons necessary to he safe con@and and control of operations.

Discussion:

The Owners'roup agrees that it is necessary to limit access to the control room and to establish a clear line of authority and responsi-bility in the control room in the event of an emergency.

8MR Owners'roup Implementation Criteria:

Procedures will be developed and implemented which will meet the intent of the staff's position.

a lA NUREG-0578 Requirement 2.2.2.b: "Onsite Technical Support Center" A separate technical support center shall be provided for use by plant management, technical, and engineering support personnel, In an emergency, this center shall be used for assessment of plant status and potential offsite impact in support of the control room conmand and control function. The center should also be .used in conjunction with implementation of onsite and offsite emergency plans, including comnuni-cations with an offsite emergency response center. Provide at the offsite technical support center the as-built drawings of general plant arrange-ments and piping, instrumentation, and electrical systems. Photographs of as-built system layouts and locations may be an acceptable method of satisfying some of these needs.

Oiscussion:

The Owners'roup agrees that it is important to have a technical support center (TSC) designated where "individuals who are knowledgeable of and responsible for engineering and management support of reactor operations in the event of an accident" can go to consistent with the intent to limit access to ihe control room, Furthermore, it is agreed that it is appropriate that the emergency plans will designate the role and location of the technical support center . There is, however, one area in particular which needs further discussion.~ g ~

The requirement that the TSC be onsite and in close proximity to the control room is not necessarily the best choice under all circumstances for meeting the intent of the position. The location of the TSC should be dictated by its accessibility to the engineering and management personnel who will occupy it, rather than by its physical proximity to the control room. For example, multi-unit sites which share engineering and management personnel, or so-called outdoor sites which have administrative buildings detached from the plant, may designate locations which may not be judged as in close proximity to the control room, but make sense from a personnel access viewpoint. Furthermore, "close prox'.mity" would only seem to be required as a means of supplementing the transmittal of plant status from the control room to the TSC, and in that sense then becomes inconsistent with the desire to limit access to the control room during emer oencies.

Thus, the requirement for close proximity could be eliminated on the basis that the plant status must be monitored from the TSC.

The Owners'roup also agrees that monitoring equipment may vary from plant to plant, and that there is no single best way in which to monitor plan" s atus in the TSC. There was agreement that TV monitors which could read and transmit information from the control room panels to the TSC would meet the requirement to display and transmit plant status. It was also agreed that the TSC should have two-way coomunications links with the control room, other onsite telephones, the offsite Emergency Opera ions Center, and the NRC. It was further agreed that the existing direct link between the NRC and the control room would be switched over to the TSC upon its activation in accordance with the intent to limit access to the control room. Finally, it was agreed that the staf ing and activation criteria for the TSC would be specified in the emergency plan.

BklR Owners'roup Implementation Criteria:

Phase I b Jan. 1, 1980 :

1) A location will be designated in the emergency plan. This may be a temporary location.

2) Conmnications links will be established with the control room, the on-site Operational Support Center, the off-site Emergency Operations Center, and the NRC. These may be temporary.

3) The staffing and activation criteria will be specified in the emergency plan.

4) The, TSC will have access to the records (system descriptions, arrange-ment drawings, etc,) in accordance with the revised NUREG-0578 position.

Phase II The implementation criteria of Phase II will be issued after further discussions between the Owners'roup and the NRC staff,

NUREG-0578 Implementation Letter Requirements Relative to Containment Level, Pressure and H dro en Monitorin Consistent wi.h satisfying the ~equirments set forth in General Oesign Criterion 13 to provide the capability in the control room to ascertain containment conditions during the course of an accident, the following requirements sha11 be implemented:

1) A continuous indication of containment pressure sha11 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.')

A continuous indication of hydrogen concentration in the contain-ment atmosphere shall be provided in the control room. Measurement capability shall be provided over the range of 0 to 10Ã hydrogen concentration under both posi ive 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 PMRs and cover the range from the bottom to the top of the containment sump. Also for Pl(Rs, a wide range instru-ment shall be provided and cover the range frcm the bottom of the containment to the elevation equivalent to a 500,000 gallon capacity.

For BMRs, a wide range instrument shall be provided and cover the range from the bot om to 5 feet above the normal water level of the suppression pool.

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

Oiscussion:

ine Owners'roup concurs with the ACRS recommendations for additional ins rumenta ion =or the following parameters:

1) Containment water level monitoring 2} Containment pressure monitoring

3) Containment hydrogen monitoring For practical reasons, i . is no desirable to monitor suppression pool water level all the way to -ne sot="m o+ tne suporession pool. This is because an ins rument tap at the v rv bo:-.om could become obstructed by sludge and small debris. The Owners" Grouo believes that water level monitoring down to the elevation of the lowest ECCS pump suc ion is more practical and fully satis.ies the intent of the requirement.

Containment Yonitoring (pQ It is the Owners'roup's current interpretation that the hydrogen monitoring requirement is associated with ECCS performance and core degradation, rather than with containment atmospheric control.

Owners'roup Implementation Criteria:.

1) The Owners'roup intends to implement containment pressure, water level, and hydrogen monitoring which will be designed and installed to meet, Engineered Safety System criteria.

The lowest suppression pool water level monitored will be at or below the elevation of the lowest ECCS pump suction.

NUREG-0578 Implementation Let er Requirement Relative to Remotel Operated High Point Yents.

Each applicant and licensee shall install reactor coolant system and reactor vessel head hiah point, vents remotely operated from the control room. Since these vents form a part of the r eactor coolant pressure boundary, the design of the vents shall conform to the requirements of Appendix A to 10 CFR Part 50 General Design Cr iteria. In particular, these vents shall be safety grade, and shall satisfy the single failure criterion and the requirements of IEEE-279 in order to ensure a low probability of inadvertent actuation.

Each applicant and licensee shall provide the following information concern-ing the design and operation of these high point vents:

I) A description of the construction, location,'ize, and for the vents along with results of analyses of loss-power'upply OT coolant accidents initiated by a break in the vent pipe.

The results of the analyses should be demonstrated to be acceptable in accordance with the acceptance criteria of 10 CFR 50.46.

2} Analyses demonstrating that the direct ventina of noncondensable gases with perhaps high hydrogen concentrations does not result in violation of'ombustible gas concentration limits in con-tainment as described in 10 CFR Part 50.44, Regulatory Guide 1.7 (Rev. I}, and Review Plan Section 6.2.5.

3) Procedural guidelines for the operators'se of the vents.

The information available to the operator for initiating or terminating vent usage shall be discussed.

Discussion:

Domestic Bus are provided with a number of power operated safety grade relief valves which can be manually operated from the control room to vent the reac.or pressure vessel. The point of connection of the ven.

lines from the vessel to tnese valves is such that accumulation oi gases above =ha. point in the vessel will not affect natural accumulation of gases o'. .:~ reactor core.

These power ooerated relief valves satisfy the intent of the NRC position.

Information regarding the desian, qualification, power source, etc., of these valves has been provided to the individual plant- Safety Analyses Reports.

The Owner s'os',.ion is that the reauirement of sinale ailure crit ria for prevention of inadverten: ac-.uation of these valves, and the r equire-ment (stated in the Oc-ooer 11 topical me ting) that oower be renoved

Hich Point Vents (p.2)

Oiscuss on (Cont) during normal operation, are not applicable to 8MRs. These valves serve an important function in mitigating the effects of transients and in many plants provide A&i E code overpressure protection. Therefore, the addition of .a second "block" valve to the vent lines could result in a less safe design and in some cases a violation of the code. Also, in-advertent opening of relief valve in a 8MR is a design basis event and is a controllable transient (this is discussed in our position on HUREG-0578, iten 2.1.2).

In additioh to the power-operated relief valves, operating BMRs 'include various other means of high-point venting. Information on which plants are equioped with which features has been provided in individual plant Safety Analysis Reports, and may be summarized by individual licensees in their NUREG-0578 impienentation letters. Amona these are:

I) Normally closed reactor vessel head vent vai-ves, ooerable from the control room, which discharge to the dryweil; 2} Normally ooen reac.or head vent line, which discharges to a main steam line; 3} Main steam-driven Reac.or Core Isola.ion Cooling (RCIC) Sys.em turbines, operable from the control room, which exhaus to the suporession pool; 4} Main steam-driven Hiah Pressure Coolant, Injection (HPCI) System turbines, ooerable rom the control room, which exhaus: to the suppression pool;

5) Isolation condenser primary side vent valves, operable from tne control room, whicn discharge to containment or a main steam line.

Although .he power-opera ed relief valves fully satisfy. the intenz of the reouirement, these othe. means also provide pro-ac ion aaains he accumu-la -'on of noncondensibles in the reactor pressure vessel.

In the Oc:ober 11, 1979, topical meeting on this subjec , hree procedural questions were raised:

I) Mhere to vent to (suporession pool vs. containment);

2) Mhen to vent;

3) Mhen not to vent.

Under mos . circums-.ances, .here would be no choice as to wner e o vent ;o or wnen to vent, s nc "he relief valves (as oar. of the Automa=ic Oe-pressur "a". on Sys:em), HPCI, and RCIC will func. on automa 'cally in their desianed modes -.o ensure adequate c"re cooiina, and .hese will prov.'de

Hioh Point Vents (p.3)

Oiscussion (con.)

continuous venting to the suopression pool. The current assessment is that i would not be desirable to interfere with emergency core cooling functions in order to orevent venting, but the matter will be studied further.

The result of a break in the safety/relief valve discharge line, or any of the other sys.ems enumerated above, wot<Id be the same as a small steam line break. A comolete steam line break is part of the plants'esign .

basis, and smaIIer-size breaks have been shown to be of lesser sever ity.

A number of reac.or sys~ blowdowns due. to stuck-open relief valves (also equivalent to a small steam line break) have confirm'ed this in practice (see Owners'roup posi ion on Requirement 2.1,2). Thus.no new analyses to show conformance with 10 CFR 50.46 are required.

Hecause the relief valves, HPCI, and RCIC will vent he reactor continuously, and because containment hydrogen calculations in nominal safety analysis calculations assume con inuous venting, no special analyses are required to demons.ra e ".hat the di. ec. ven.ing of noncondensible gases with perhaps high hydrogen concentrations does no. resul in violation of combustible gas concentra ion limits in containment."

BWR Owners'roup Imolenentation C. iteria:

I) The Owners'roup believes that adequate reactor coolant system venting is provided by the existing plant design.

2) Plant procedures will be provided to govern the .operator's use of the relief valves for venting the reactor pressure vessel.

3) No new 10 CFR 50.46 con ormance calulations or containment combus.ible gas conc ntration calculations are required, since systems 'in the plant's original design and covered by the original design bases are used;

4) in response o a request from he October 11, 1979, topical me ting, the use of isolation condenser tube side vents will be consider%;

5) ?n response to a reques from the October ll, 19"9, tooical me ting, the effec of noncondensibles in HPCI/RCIC turbine steam will be addressed.

NUREG-0578 Requirement 2.2.2.c: "Onsite Operational Support Center" Each operating nuclear power plant should establish and maintain a separate onsite operational support center outside the control room, In the event of an emergency, shift support personnel (e.g., auxiliary operators and technicians) other than those required and allowed in t

the control room shall repor to this center for further order s and assignment.

Oiscussion:

The Owners'roup agrees with the position as stated, with the clari-fication that there may be plant unique situations where it may be more appropriate that more than one location be designated in the emeegency plan. As long as these locations are known and the "methods and lines of communication and management" are specified in the emergency plan, the intent of the position will have been met.

8WR Owners'roup Implementation Criteria The staf 's posi tion will be implemented as stated and subject to the clarification on location stated above.

og t