ML20207J445

Forwards Safety Evaluation Approving HGN-112-NP, Generic Hydrogen Control for BWR/6 Mark III Containments, for Ref in Licensee Submittals,For CRGR Review

ML20207J445
Person / Time
Issue date:	09/01/1988
From:	Sniezek J Office of Nuclear Reactor Regulation
To:	Jordan E Committee To Review Generic Requirements, NRC OFFICE FOR ANALYSIS & EVALUATION OF OPERATIONAL DATA (AEOD)
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{{#Wiki_filter:___ p.ess +f Ic, UNITED STATES ? h'UCLE AR REGULATORY COMMISSION . ) us.m.nos o. c. mss ( o. ero 1 1388 f MEMORANDUM FOR: Edward L. Jordan, Chairnan CoLinittee to Review Generic Requirements FROM: James H. Sniezek, Deputy Director Office of Nuclear Reactor Regulation

SUBJECT:

HYDROGEN CONTROL OWNERS GROUP TOPICAL REPORT HGN-112-NP Fy letter dated February 23, 1987, the Hydrogen Control Owners Group (HCOG) transmitted topical report HGN-112-NP, "Generic Hydrogen Control Information for BWR/6 Mark !!! Containments," for staff review and approval. The topical report is e summary of the individual generic submittals that have been sent to the staff by HC06. The tupical report will be referen.:ed by each Mark I!! licensee in their.cubmittal of plant specific analysis t(i demonstrate th effectiveress and reliability of hydrogen ignition systems, as raouired b/ the hydrogen control rule 10 CFR 5^.44(c)(3)(vii)(B). The staff has reviewed the topital report and prepared a safety evaluation report (SEP) enclosed as Attachnent 1. The SER approves the topical report; however, the staff proposes an additional requirement that the hydrogen ignition systems currently installed in Mark III plants be improved by providing an independent power supply to ensure availability of igriters during station blackout accident sequences. Enclosed as Attachreht 2 is the information identified by iten IV.B of the CRGR charter. Larry Shao, Director Division of Engineering and Systems Technology, is the sponsoring Division Director. It is requested that a CRGR review of this proposal be scheduled at the earliest opportunity. hY W ames H.03nieIe,DeputyDirector Of' ice of Nuclear Reactor Regulation

Attachment:

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[p tetQ#'e, UNITED STATES NUCLEAR REGULATORY COMMISSION j ,yr g t W ASHINGTON, D. C. 20666 k.w.... Mr. J. R. Langley F.*oject Manacer, Mark III Containtrent Hydrogen Control Owners Group (HCOG1 c/o Gulf States Utilities kerth Access Poad at Highway 61 St. Francisvil10, 'J 70775

SUBJECT:

ACCEPTANCE FOR REFERENCING OF LICENSING TOPICAL REPORT TITLE 0, "GENERIC HYOROGEN CONTROL INFORMATION FDP BKR-6 MARL 111 CONTAlWENTS", HGN-112-NP We have completed our review of the subject topical report submitted by your letter dated February P3, 1987. We find the report acceptable for referencing in licensee analysis of hydrogen control systems for RWR Mark !!! containment under the limitations delineated in the report and its references and the associated NRC evaluation, which is enclosed. The evaluation defines the basis for acceptance of the report. In addition, the staff finds an independent power supply must be integral part of each licensee's hydrogen igi. iter system. I We do not intend to repeat our review of the matters described in the report and found acceptabic when the report is referenced in licensee requests for approval of final analyses of the hydrogen control system, except to ensure that the material presented is applicable to the specific plant involved. Our acceptance applies only to the matters described in the report and its references. In accordance with procedures established in NUREG-0390, we recuest that FCOG submit to the NRC accepted versions of this report within three months of receipt of this letter. The acu pted versions should incorporate this letter and the enclosed evaluation between the title page and the abstract. The accepted versions should also incorporate as appendices those references used as a basis for the staff's evaluation. The accepted version should include an -A (desigr.a-l ting accepted) following the report identification number. Your submitta', should include an application for withholding the proprietary infomation accompanied by an affidav!t meeting the requirements of 10 CFR 2.790(b). This final report submittal should also include a non-proprietary version of the proprietary reports referenced snd incorporated therein. This final report submittal should also in-i clude a non-proprietary version of the I reprietary reports referenced and incorpo-rated in the approved topical report and intended to be employed as a part of a licensee application. 6

1, Should our criteria or regulations change such that our conclusions as to the i acceptability of the report are invalidated, PCOG and/or the licensees referer.4 cing the topical report will be expected to tovise and resubmit their respective documentation, er submit justification for the continued effective applicability of the topical report without revision of their respective documentatien. Ashok C. Thadani, Assistant Director for Systems t Division of Engineering and Systems Technology R s f r i i t 1 I } ) I I i l [ t I -.._,.__.__--,,__,_-,_.___.___._.m_

4 CONTENTS .P,ajig 1 INTRODUCTION AND 8ACKGROUNO..................................... 1 2 GENERAL DESCRIPTION OF THE HYOROGEN IGNITION SYSTEM............. 3 3 COM8USTION/ IGNITER TESTING...................................... 6 4 3.1 Small-Scale Tests.......................................... 6 1.2 Quarter-Scale Test Facility................................ 7 3.2.1 Scaling Methodology,................................ 10 3.2.2 Quarter-Scale Testing Approach...................... 10 i 3.2.3 Quarter-Sr. ale Test Results.......................... 11 4 CONTAINMENT STRUCTURAL CAPACITY................................. 14 5 DEGRADED CORE EVENTS AND HYDROGEN Gr.NERATION................ E15 4 5.1 Introduction............................................... 15 5.2 Evaluation................................................. 18 1 5.2.1 Acceptable HGE Sequence................. 19 5.2.1.1 The HCOG*s Base-Case Scenario.............. 19 5.2.1.2 Station Blackout and NUREG-1150............ 20 5.2.1.3 TBU the "Acceptable Sequence".............. 20 5.2.1.4 Hydrogen Generation Profiles............... 21

5. 2.1. 5 Non-Mechar.istic Hydrogen Release Profile...

22 5.2.2 BWR Core Heatup Code (8WRCNUC)...................... 25 5.2.2.1 Introduction............................... 25 5.2.2.2 Phenomenological Assumptions............... 26 5.2.2.3 Steam Production........................... 26 5.2.2.4 Hyd rogen Ge ne rati on........................ 28 5.3 S umma ry a nd C o nc l u s i o n s.................................... 29 6 CONTAINMENT RESPONSE - ANALYTICAL M0DELING...................... 30 6.1 Localized Combustion /CLASIX-3.............................. 30 6.2 Containment Pressure and Temperature Calculations.......... 33 6.3 Drywell Analysis........................................... 33 6.4 Existence of Drywell Diffusion Flames...................... 34 Mark III SER iii

l o 1 .g 1 i CONTENTS (Cont'd) Page 7 SURVIVABILITY OF ESSENTIAL EQUIPMENT............................ 38 7.1 Identification of Essential Equipment...................... 38 7.2 Generic Equipment Survivability Analysis (Localized Combustion)................................................ 39 7.3 Diffusion Flame Thermal Environment Methodology............ 41 i 7.4 Spray Availability........................................ 42 7.5 Pressure Effects.................... 43 t

7. 6 Detonations................................................

43 8 CONCLUSION...................................................... 43 l APPENDICES A GENERIC HYDROGEN IGNITION SYSTEM TECHNICAL SPECIFICATIONS i l B MARK III COMBUSTIBLE GAS CONTROL EMERGENCY PROCEDURE CUIDELINE C BIBLIOGRAPHY O ACRONYM LIST i LIST OF FIGURES r 2.1 General Hydrogen Ignitor Assemb1y............................... 4 1 3.1 Elevation Views of the Quarter-Scale Test Facility.............. 8 r 3.2 Facility Configuration Tests S.01-S.11.......................... 9 i 4 4.1 Typical Mark III Containment Configuration...................... 17 I t 5.1 Hydrogen Generation Rate (150 GPM Ref1ood)...................... 23 5.2 Hydrogen Generation Rate (5000 GPM Ref1ood)..................... 24 4 6.1 P e r ry C L A S I X - 3 M0 d e l......,..................................... 35 l 6.2 50RV With No Spray-Wetwell Temperature.......................... 36 l i 6.3 SORY With No Spray-Wetwell Piessure............................. 37 i i i l LIST OF TABLES [ 4.1 Comparison of BWR Mark III Containment Characteristics........., 16 ) 5.1 Hydrogen Release Profiles....................................... 22 l I l l i i I l Mark III SER iv

c. THE GENERIC SAFETY EVALUATION REPORT RELATING TO THE MARK III C0l4TAINMENT HYDROGEN CONTROL i

I f 1 INTRODUCTION AND BACKGROUND Following a loss-of-coolant accident in a light-water reactor (LWR) plant, com-bustible gases, principally hydrogen, may accumulate inside the primary reactor t.ontainment as a result of (1) metal-water reaction involving the fuel element cladding; (2) the radiolytic decomposition of the water in both the reactor core and the containment sump; (3) the corrosion of certain materials within the containment by sprays; and (4) any synergistic chemical, thermal, and radio-lytic effects of post-accident environmental conditions on protective coatings and electric cable insulation. To provide protection against this possibio hydrogen as a result of an accident, Title 10 of the Code of Federal Regulations (10 CFR) Section 50.44, "Standards ODC41,"Containmentatmospherecleanup,ght-water-cooledpowerreactors,"andAppend for combustible gas control system in li that syste:ns be provided to control hydrogen concentrations in the containment atmosphere following a postulated accident to ensure that containment integrity is maintained. Conventional hydrogen control systems (e.g., hydrogen recombiners) historically have been installed to provide the capability to control the rela-tively low rate of hydrogen accumulation (or oxygen accumulation in inerted containments) resulting from radiolytie decomposition of water, corrosion of metals inside containmer.t. and environmental effects on coatings and insulation. However, the net free volume inside containment (or inerting of the containment volume) is used to control the rapid hydrogen production resulting from a metal-water reaction of the fuel cladding. That is, the containment volume is large. I enough so that the hydrogen generated early would not reach the lower limit of 1 flammability (or the inerting would prevent combustible mixt 3res). The rationale for this approach is that the rate of hydrogen release resulting from cladding reaction was assumed to be too rapid (on the order of minutes) following a pos-tulated accident to allow for an active control system. Thus, hydrogen control systems would only be actuated later in the svent to control the slow hydrogen / or oxygen release associated with radiolysis and reaction of materials inside J ] containmort. l To quantify t'ie metal-water source for riesign-basis accidents,10 CFR 50.44, codified in 0:tober 1978, requires that the combustible gas control system be capable of har.dling the hydrogen generated from five times the amount calcula-ted in demonstrating compliance with 10 CFR 50.46 or the amount corresponding to the total reaction of the cladding to a depth of 0.23 mils, whichever amount was greater. Typically, this would translate to a 1 to 5% metal-water reaction of the active clad. However, the accident at Three Mile Island Unit 2 (TM1-2) on March 28, 1979, resulted in a metal-water reaction that involved approximately 45% of the fuel cladding (i.e., about 990 lbs), which resulted in hydrogen generation well in r J excess of the smounts specified in 10 CFR 50.44. The combustion of this hydrogen produced a significant pressure spike inside containment. As a result, it became apparent that additional design measures were needed to handle larger hydrogen releases, particularly for smaller volume containments and those with Mark III SER 1

lower design pressures. The Nuclear Regulatory Commission (NRC) determined that a rulemaking proceeding should be undertaken to define the mann0r and extent to which hydrogen evolution and other effects of a degraded core need *.o be considered in plant design. An advance notice of the rulemaking proceeding on degraded core issues was published in the Federal Reaister on October 2, 1980. In addition, a new unresolved safety issue was instituted (A-48, 6 Hydrogen Con-trol Measures and Effects of Hydrogen Burns on Safety Equipment") to evaluate this new concern. To formalize its requirements for additional hydrogen control measures to deal with degraded core accidents affecting pressurized-water reactors (PWRs) with ice condenser containments and BWRs with Mark III containments, the NRC pub-lished an amendment to the hydrogen rule (10 CFR 50.44) on January 25, 1985 (50 FR 3498). The amended rule required that a hydrogen control system be pro-vided and that the system be capable of accommodating, without loss of contain-ment structural integrity, the amount of hydrogen jenerated from a metal-water reaction of up to 75% of the active fuel cladding. In addition, systems and components necessary to establish and maintain safe shutdown must be capable of performing their function regardless of hydrogen burnir.g. Pursuant to the provisions of the rula, each utilit ment has installed a hydrogen ignition system (HIS)y with a Mark III contain-and submitted a preliminary analysis and a schedule for meetin0 the full requirements of the rule. The affected plants with Mark III containments are Grand Gulf Nuclear Station, River Bend Station, Perry Nuclear Power Plant, and Clinton Power Station. The staff's interim evaluations of tnese initial plant responses are documented in i supplements to the safety evaluation reports for each of these plants (NUREG-0831, NUREG-0989, huREG-0887, and NUREG-0853, respectively). l These responses were aided by the efforts of the Mark III Containment Hydrogen Control Owners Group (HCOG), formed in May 1981 by the utilities with Mark !!! containments to collectively perform testing and analyses to demonstrate the effectiveness and reliability of the hydrogen ignition systems. In addition, each licensee with a Msrk III containment is required to provide l a final analysis (10 CFR 50.44(c)(3)(vii)(B)] to confirm the conclusions of the l preliminary analysis and/or, if necessary, to institute modifications to ensure I compliance with the rule. The scope of this analysis is specified in 10 CFR 50.44(c)(3) (vi)(B). The generic findings from the HCOG's prngram will be } utilized for this final analysis, supplemented by plant-specific design considerations. l The following staff evaluation focuses on the assessment of the completed gen-eric testing and analyses performed by the HCOG in support of the plant unique analysis. The HCOG activities have beer, summarized in a topical report trans-mitted by letter dated February 23, 1987, correspondence identification HGN-D2-NP, "Generic Hydrogen Control Information for BWR-6 Mark III Containments." The topical report is a summary document of all of the individual generic submittals l that have been sent to the staff by the HCOG. It should be noted that HCOG correspondence identification designatnrs with a "P" suffix (HGN-XXX-P) are proprietary to HCO3, Whereas, those without a suffix or with an "NP" suffix are nonproprietary. Mark III SER 2 i

l l l l As part of the review of the HCOG program, the staff obtained technical assist-ance from the Sandia National Laboratory (SNL), the principal contractor for the NRC research program on h.,drogen control and combustion phenomena. SNL provided the NRC with an independent assessment of technical issues contained in selected HCOG submittals pertaining to hydrogen behavior. The staff evaluation of the generic considerations of the hydrogen control system I for the Mark III containment can best be understood if categorized as folicw : general description of the hydrogen ignition system l combustion and igniter testing l containment structural capacity degraded core events and hydrogen generation containment response-analytical modeling survivability of essential equipment l overall conclusions l Therefore, the following discussion will follow this general outline, i 2 GENERAL DESCRIPTION OF T!!E HYDROGEN IGNITION SYSTEM l The regulation, 10 CFR bO.44(c)(3)(iv)(A), states: Each licensee with a boiling light-water nuclear power reactor with a !4 ark III type of containment..., shall provide its nuclear power l reactor with a hydrogen control system justified by a suitable pro-4 gram of experiment and analysis. The hydrogen control system must be capable of handling without loss of conthinment structural integrity an amount of hydrogen equivalent to that generated from a metal-water 4 reactor involving 75% of the fuel cladding surrounding the active fuel region (excluding the cladding surrounding the plenum volume]. 1 The concept employed by the licensees with a Mark III containment, and similarly i i the ice condenser licensees, is to intentionally ignite hydrogen generated l l inside containment. This method precludes buildup of relatively high concen-1 trations of hydrogen during degraded core accident scenarios. 1 To accomplish this early ignition a hydrogen ignition system (HIS) is installed 1 in each of the four plants with Mark III containments. The HIS is a system I which consists of approximately 100 igniter assemblies distributed throughout j i the drywell and containment regions. The main element of the igniter assembly is the Model 7G thermal igniter glow l plug (commonly used in diesel engines) manufactured by the General Motors AC Division. Each Mirk III containment has an identical igniter assembly design. r Each igniter is powered directly from a 120/12-V stepdown transformer and de-signed to provide a minimum surface temperature of 1700'F. The igniter assem-bly (see Figure 2.1) consists of a 1/8-inch-thick stainless steel box that con- [ tains the transformer and all electrical connections and is manufactured by the j Power Systems Division of Morrison Knudsen. Igniter assemblies are Class 1E, seismic Category I, and meet the requirements of the Institute of Electrical and Electronics Engineers (IEEE) Std 323-1974 and NUREG-0588 for environmental qualification. [ Mark III SER 3 i

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f i, The igniter assemblies are divided into two groups; each group being powered from a separate Class 1E division power supply. The intent is to have at least two igniters located in each enclosed volume or area within the containment that could be subject to possible hydrogen pocketing, and each igniter be powered from a separate power division. In open areas within the containment and dryvell regions, igniter assemblies at the same elevation are designed to have alternating power division sources. Igniters are separated by about 30 feet when both engineered safety feature (ESF'. power divisions are operable or by about 60 feet when one power division is inoperable. Igniter placement is designed to be more widely spaced in the large open regions, such as above the refueling floor, and in the lower red ons of the drywell that are subject to flooding. Requiremente of placement as well as other parameters of the system are contained in the technical specifications for the hydrogen ignition system, as proposed by the HCOG, and addressed in Appendix A of this report. Each igniter power division has a corresponding onsite emergency dirsel generator. However, recent risk studies (see Section 5) have indicated that loss of all ac power (i.e., station blackout) is a dominant contributor to core damage events at BWR plants. Therefore, without an independent power sou ru, the HIS would i not be available for the more probable analyzed hydrogen generation events. l Consequently, the staff has concluded that an independent power supply as part l of the HIS design must be considered. Further, the staff concludes that a non class IE power supply with suitable electrical isolation design features, and capable of energizing one division of igniters, is appropriate and acceptable for meeting the staff requirements for an independent power supply. The HIS is designed for manual actuation from the main control room. Actuation by the operator is required by plant emergency procedures when the reactor pres-sure vessel (RPV) water level reaches the top of active fuel (TAF). The proposed combustible gas control emergency procedures for plants with Mark III contain-ments are further discussed in Appendix B. By letter c Aed March 5, 1986 (HGN-073), the HCOG provided the following justi-fication to support manual actuation. Actuation is linked to indication of the RPV water level, which is a key safety parameter and is closely monitored by the operators. Also, HIS actuation requires only the positioning of two hand-switches. Furthermore, operators should not hesitate to energize the system during accident s.anarios in which the hydrogen threat is uncertain or marginal because there would be no adverse effect on th9 plant as a result of unnecessary igniter actuation. Time available to actuate the HIS is the other significant parameter. B sed on the hydrogen events considered,'he HCOG estimated this time to be approximately no less than 25 minutes that is, after the water level reachesTAFtothelowerhydrogenflammabilitylImitreachedinthewetwell volume. The HCOG also noted that hydrogen would migrate to the upper portions of the containment before the wetwell reaches hydrogen combustion conditions. This effect was seen in the quarter-scale tests. Therefore, the time intervai is expected to be somewhat greater than 25 minutes. E.ecause (1) manual actuation is a simple task, (2) the operator has sufficient time to perform the task, (3) and there are no negative effects if the system is inadvertently or unnecessarily actuated, the scaff finds manual operator actuation acceptable. HIS Design Assesseert Tne staff finds the hydrogen igniter system currently installed in the plants with a Mark III containment to be acceptable if modified by the provision for Mark III SER 5

i an additional indeperdent power source. As a minimum, one of the two igniter divisions should be powered from this indeperient power source. This assessment applies generically to the plants with a Mark III containment (Grand Gulf, Clinton, River Bend, and Perry). The staff's conclusion is based on the requirements of 10 CFR 50.44 and the results of recent probabilistic risk assessments that indicate station blackout 1 (SBO) scenarios are expected to influence the estimates of core damage frequency (thus events with hydrogen generation) for boiling light-water reactor (BWR-6) plants with a Mark III containment (see Section 5). Since under 580 conditions, the currently installed igniters would not function, an independent power supply is necessary to ensure reliable operation of the igniter system. 3 COM8USTION/ IGNITER TESTING Numerous research programs have been conducted since 1980 to better understand hydrogen combustion behavior and the performance of ignition devices. Because i these programs were varied in scope, Sandia National Laboratcry (SNL) summari:ed the findings of reevnt hydrogen combustion test orograms in NUREG/CR-5079. This rport also provides additional background information and insights related to hydrogen behavior. The specific test programs considered necessary by HCOG to support the unique plant characteristics of a Mark !!! containment are discussed below. f 3.1 Small-Scale Tests Small-scale hydrogen combustion tests were performed at Whiteshell caboratories and documented by the HCOG in a letter dated June 7, 1984 (HGN 017 NP). The j program was intended to investigate ignition and combustion behavior of mixtures j predominantly composed of hydrogen and steam, i.e., with limited available oxygen. i This condition may exist for a postulated drywell break event in which air is j initially swept from the drywell and then later reintroduced into the steam-j hydrogen environment. These tests confirmed that such hydroger-sir-steam nix-tures can be successfully ignited as long as the oxygen concentration exceeds j i approximately 5-6 volume percent, A 1/20th-scale Mark III hydrogen combustion program was conducted by Acurex Corporation and documented by the HCOG in a letter dated February 9, 1984 I (HGN-014-NP). The objective of this program was to provide a visual record of hydrogen combustion behavior in a 360-degree model of a Mark III l containment. Modellingincludedthesuppressionpoolandmajorblockagesin the annular region between the drywell and outer containment walls. Hydrogen l was admitted through simulated quenchers and/or vents into the suppression pool l And ignited by prototypical ignition sources. t The most important result obtained from the 1/20-scale test was the confirmation j of continuou:; hydrogen burning in the form of steady diffusion flames above the r suppression pool. The significance of this mode of hydrogen burning is the observed severe thermal loads that occur near the diffusion flames and could i threaten the integrity of the containment and equipment. Diffusion flames were observed when hydrogen flow rates of 0.4 lb/sec (full-scale equivalent) or I i i i Mark III SER 6 . -., ~ , _. -., _ ~.,., -,. - - _ - - -.. _ _ -. - -.. - - -, _ --,n

1 greater were used. Combustion was initiated oy the igniters and rapidly prop-i agated to the pool surface and formed steady diffusion flames that were an-i chored at the surface of the pool and located above the submerged spargers that l 1 released the hydrogen. Hydrogen burning was observed to intensify as the hydro-gen injection flow rate was increased, as evidenced by taller flames and higher i i temperatures. ( ) As part of the 1/20-scale program to determine the sensitivity of scaling, a 1/5-scale single-sparger mockup was constructed. A significant result of these tests was that approximately one-half the flame height of what would have been predicted based on reruits of 1/20-scale tests was observed. On the basis of these tests, it became necessary for the HCOG to pursue a larger-scale test i program to obtain thermal environmental data more representative of a Mark !!! } l containment. Subsequently, the HCOG undertook an extensive program to better i define the conditions that could exist during a degraded core accident. Amajor [ element of this offort was the quarter-scale Mark III containment combustion j test program. l 3.2 Quarter-Scale Test Facility P l The quarter-scale test progrsm became the major element of the HC0G's hydrogen .wsearch program. The primary objective of this program was the irvestigation a and characterization of the environment that could result from diffusive burning on the suppression pool in a Ma d III containment. Ultimately, the information gathered from the quarter-scale test facility (QSTF) would be used in determin-i ing the survivability of select equipment. Test facility description and the combustion test results may be found in the HCOG's letters HGN-098-P, July 18, 1986; HGN 115-NP, February 10, 1987; and HGN-121-P, July 22, 1987. r The test facility is a quarter-linear-scale model of a Mark III containment, de-signed and constructed by Factery Mutual Research Corporation (FMRC), and located l in West Gloucester, Rhode Island. The test enclosure is designed to operate at i pressures up to 40 psig and consists of an outside tank, 31.5 feet in diameter. l 49.4 feet high, containing a smaller tank, about 21 feet in diameter by 23 feet l high. The space between the two tanks is the test volume; which contains floors i and other large blockages simulating the obstructions that exist in the actual containments. Because of the unique features of the four plants studied, modular j construction of the annular floors is usod to modify the vessel interior when l needed. At the bottom of the two tanks, the suppression pool is simulated, Several views of the facility are showt. in Figures 3.1 and 3.2. i I j Facility design features include: containment sprays simulated loss-of-coolant-accident (LOCA) vents (top row only, numbering 48) simulated spargers (uniforely spaced every 15 degrees azimuthally and t totalling 24) unit coolers (for the River Bend configuration) i l l The facility is heavily instrumented to measure gar and surface temperatures, i gas velocities, gas concentrations, heat fluxes, pressure, and five video i cameras are used for a visual record. l l Mark III SER 7

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3.2.1 Scaling Methodology The theoretical basis for mooeling hydrogen flames in the test facilit.v is based on froude scaling. The modeling assumes fully developed, buoyancy dominated, turbulent flows are achieved to preserve the equivalent value for the Froude number in the model and in the full-scale plant. The technique of Froude scaling is supported by numerous experimental demonstrations in the field of fire research. Using this type of modelling full scale was scaled to quarter scale, a 4-to-1 linear scaling resulting in: 32-to-1 reduction in mass and volume flow rates 64-to-1 reduction in total hydrogen released 2-to-1 reduction in the time scale 2-to-1 reduction in gas velocities 1-to-1 relationship for gas temperatures and gas concentrations Flame heights and global flow patterns also were determined by Froude scaling. Generally, froude scaling was used to reasonably and practically desion the QSTF (e.g., spray flow and droplet sizes, heat sink thermal charactet.stics, blockages). However, the following discrepancies were noted: (1) The quarter-scale tests revealed that the insulation used in the facility l became wet and its thermal properties departed from dry insulation. (2), The QSTF had only 30% of the mass as prrscribed by Froude scaling. (3) The scaling method did not rigorously simulate convective and radiative heat losses to structural heat sinks. To assess the impact of these discrepancies, the HCOG provided a comprehensive analysis as documented by HCOG letter HGN-085, dated May 5, 1986. The HCOG determined that compensating effects existed in the treatment of heat sinks. Thus, the data obtained from the QSTF does provide a reasonably accurat. description of the full-scale thermal environment when extrapolated by Froude scaling. To assist tae staff in the review of this complex aatter, SNL studied the subject analysis and submitted various comments. On October 7, 1987, a meeting between the HCOG, SNL, and the staf f took place to resolve the SNL's comments. Subse-quently HCOG documented its responses in a letter (HGN-128) dated November 6, 1987. On the basis of the additional information, SNL concluded and the staf f concurs that the application of quarter-scale experimental data directly to full-scale equipment survivability can be done conservatively in spite of the above discrepancies. SNL's assessment is documented in correspondence dated December 23, 1987. 3.2.2 Quarter-Scale Testing Approach Tests were performed in the QSTF for the four different plants with a Mark III containment; i.e., the QSTF was customized to reasonably represent the plant-specific characteristics of each Mark III configuration. During the tests, I Mark !!! SER 10

r A hydrogen was released through spargers used to simulate the automatic depres-surization system (ADS) and a stuck-open relief valve (50RV) or through the simulated LOCA vents. Two hydrogen release proffles were used in the facility, a low-reflood case (150 gpm) and a high reflood cese t(5000 gpm). A discussion of the development of these profiles is contained in section 5. i However, before the plant unique or production tests were conducted, a series of scoping tests were performed to assess data repeatability and the significance of various parameters. Results from these tests formed the basis for developing 3 the final test matrix that were usad in the production test program. Also, in i 1 the early development of postulated degraded core events, spray availability i was uncertain, therefore tests were performed with and without sprays activated. ( In the production tests, each plant had its own specific array of tests, focusing l on the 50RV locations, the combination of ADS spargers and LOCA vent releases, and the offeet of sprays / coolers. The data obtained from these production tests formed a basis for determining the full-scale thermal environment and became a central element of each licensee's final analysis. This information was used as input to analytical evaluations of equipment thereal response for assessing sur-vivability of critical equipment. Further discussions on the use of this data 1 are contained in Section 7. 1 3.2.3 Quarter-Scale Test Results l The scoping test and partial prcduction test results are summarized and presented i in the HCOG's correspondence (HGN-098-P, and HGN-121-P). These results demon-strated th6t the distributed glow plug igniter system can provide an effective 4 means for limiting accumulation of hydrogen in plants with Mark III containments. ( Hydrogen concentrations throughout the facility were maintained near or below 5 l volume percent (dry basis) for all tests and steam concentrations were deter- { l mined to be about 10-15 volume percent for selected tests. Although low hydro-J gen concentrations were maintained, different types of combustion behavior were 1 observed during the tests, depending on the synergistic conditions. The various t observed combustion modes are described below. J I Diffusion Flames j i When hydrogen was released into selected spargers, hydrogen combustion woula initiate as a mild deflagration or lightoff (pressure rise about 1 psi) in the wetwell region between the hydraulic control unit (HCU) floor and the suppres-t sion pool surface and would persist in the form of standing di),usion flames j anchored to the pool surface, This was the dominant mode of combustion and l l occurred for bulk oxygen concentrations of 8 volume percent (dry) and hydrogen l injection rates greater than 0.15 lb/sec. It should be noted that the hydrogen flow rates are full-scale equivalent values (i.e., a 32:1 increase). In this regime of steady flames, combustion was essentially complete. For an injection j rate of 1 lb/sec, a flame height of about 8 feet (full scale) was riached. l t As the hydrogen injection rate was decreased to about 0.15 lb/sec, combustion i l became less complete and the flames less stable. As the rate was further de-creased, diffusion flames on the pool surface could not be maintained. This point is known as the flame extinguishment limit. Moreover, it was observed i d that this limit was strongly influenced by background gas concentrations. l i ? l i { Mark III SER 11

To illustrate the various reistionships, the following was extracted from the QSTF scoping test report: (1) The flame extinguishment limit ranges from ~ 0.07 to - 0.15 lb/ see for ambient hydrogen concentrations,below ~ 4.1 volume per-cent dry (high oxygen conditions). (2) The flame extinguishment limit decreases with increasing /see at ahy'Irogen concentration to a minimum between ~ 0.025 and - 0.03 lb hydrogen concentration of - 4.5 volume percent (high oxygen conditions.) (3) For comparable ambient hydrogen concentrations, the flame extin-guishment limit is slightly higher at low oxygen conditions. Another effect that accompanied hydrogen burning was the form ' ion of bulk air currents. Horizontal air flow was created above the pool surface allowing diffusion burning to continue by providing a source of oxygen. Another pattern of circulation was the creation of chimneys, which provide for flow to and from the region of burning and exchange flow with the upper containment, that is, hot (upward flow) and cold (downward flow) chimneys. Localized Combustion Below the flame extinguishment lim't, flames on the pool were not observed. The prevalent burning mode at very low hydrogen release rates has been termed localized combustion. This phenomenon is characterized as weak flames or volume burning through a marginally combustible hydrogen / air / steam mixture. This type of combustion was detected enly in regions at or above the HCU floor and concen-trated mostly in chimney areas. T.iis was evident by temperature measurements; localized combustion was not observed by video recordings. Localized combus-tion appeared to be relatively benign (i.e., less than 250'F at instrumented locations). Burning was more widespread and somewhat more intense at low oxygen conditions and was accompanied by slightly higher backg sund hydrogen concentrations (i.e., near 5*1 The QSTF was oriented to invevicate tha burning phenomena in the area immedi-ately above the suppression por. As a Jesult, the instrumentation layout above the HCU floor was not sufficif ' to provh'e a detailed mapping of the conditions in that region. Consequently, a rigorous nvestigation of localized combustion was not possible; however, the instrumentati o that was present, along with HCOG's analytical effort (see Section 6), provie d a reasonable characterization of the phenomena. Localized combustion is discussd further in Section 6 as it relates to the analytical m6thods used by the HCOG. Secondary Burning During the quarter-scale testing, an additional combustion phenomenon was ob-served late in one of the tests. When the bulk oxygen concentration dropped below 8 volume percent (dry), flames extinguished on the surface of the pool but formed at the HCU floor elevation. This type of burning has been termed secon-dary burning. Mark III SER 12

During a June 1986 meeting with the staff, HCOG revealed the presence of secondary burning in one of the Perry production tests. This phenomenon was not observed in previous production tests or in the scoping test phase. Until this particu-lar test, only in a scoping test did the containment oxygen concentration drop below 8%. Oxygen concentrations were generally maintained above 8 percent due to a unique need assa bted with the video coverage. Each of the five video cameras used in the QSTF requ' red a continuous air purge for the camera lenses to prevent a condensation on % e lens. This resulted in a continuous inflow of oxygen in the facility, thus pcecluding the atmospheric oxygen concentration to fall below 8%. However, the ca..: era air purges were not run continuously in the subject test; subsequently, late in this test the oxygen concentration fell below 8%. Additional information is provided by HCOG submittal HGN-106-P dated September 29, 1986, and also discussed in detail in the quarter-scale combustion test report. To present its overall assessment of the significance of secondary burning, HCOG began by addressing the limitations of the QSTF. The QSTF has various physical and practical limitations associated with the investigation of secondary burning. The instrum.rr tation in the facility was geared to define the thermal environment prod u o by diffusion flames anchored to the surface of the suppres-sion pool, which a the dominant combustion mode. There fore, more instrumenta-tion would be neeced to investigate burning above the HCU floor. 04nce all plants with Mark 'II containments have different containment volumes, simulat of the expected exygen depletion profile for each plant wwld be difficult. Therefore, HCOG avaluated the need to further consider the re undary burning phenomenon. TN following identifies the various factors considered and their relation i.ip to the Q ur plants with Mark III containments: (1) Secondary burning is expected to occur over a narrow range of oxygen concentrations, approximately from 6 to 8%. Based on the hydrogen generated by a 75% metal-wate r: etion, a Mark III corttainment would experience this oxygen concentration ir,Mrval late in the transient or not at all. Assuming the drywell air is not added to the containment inven-tory, a metal-water reaction of 55 to 67% wou M be reached before the oxygen concentration is expected to fall below ?%. This range applies to three of the four plants. Because of tre larger containment volume-to-power ratio, Clinton is not expected to fall below 10% oxygen; thus, secondary burning is not anticipated. When the drywell air inventory is included in the containment region, a w tal-water reaction of 67% would be reached for Perry before the oxygen comentration is expected to fall below 8%; River Bend and Grand Gulf c old havi already consumed the equivalent hydrogen required by the rule (i.e., M of the fuel cladding surrounding the active fuel region). (2) Considerable uncertainty is inherent in predicting the long-term hydrogen profile, especially in the latter phase of the profile (refer to Section 5). For example, an alternate accident sequence such as a drywell break sequence, different hydronen release rates, the use of the drywell mixing system, or not even reaching a 75% metal-water-reaction value, could reduce or possibly eliminate secondary burning. Mark !!! SER 13

b { i (3) Also, not all conditions expected to exist in an actual plant existed in [ the test when secondary burning was observed. For example, sprays were not i activated and the burning on the HCU floor was in a sector where the hydrogen release was most concentrated. This sector was in the 45-degree chimney in which the 50RV was located and the steam tunnel structure would reduce the upward cross-sectional flow area. Therefore, it is expected that these factors contributed to the locally high concentration of hydrogen that is J required for secondary burning. It should also be noted that the overall shape of the flames occupied a relatively small area, forming a flame zone rear the corner of the steam tunnel and drywell wall. On the basis of these differences, the following significant mitigating factors can be inferred to reduce the consequence of secondary burning: i (a) Increased turbulence inside containment through spray operation or j unit cooling could potentially delay or preclude secondary burning. l This was evident to some degree in one of the scoping tests during which conditions were similar to those during the Perry test whre i secondary burning was present. This scoping test had sprays func- [ tioning and the oxygen concentration fell to approximately 7.8%. Secondary burning did not occur. Also, sprays / unit coolers would provide cooling to mitigate the consequences of secondary burning if it were to occur. (b) Secondary burning appears to be extremely localized. It occurred in 1 the region above the location where three adjacent safety relief l valves (SRVs) spargers released hydrogen. Further, secondary burning l l occupied only a small zone. Because of equipment redundancy and separation, secondary burning is expected to affect only one train of l equipment. i On the basis of its findings, the HCOG determined further txperimental investi-gation of secondary burning was not necessary, 1 1 9 The staff's review of the evidence indicated that secondary burning is not ex- [ 4 ] pected to present a significant additional threat and, if this combustion mode l were to occur, it is expected that the thermal zone of influence would be lim- { ited. Therefore, the staff agrees that further study of se:ondary burning is I However, since the redundancy of equipment (i.e., spatial separa-unwarranted. tion of equipment performing the same function) is the most important element. the staff will request the Perry, River Bend, and Grand Gulf licensees (exclud-ing Clinton) to confirm that sufficient separation (i.e., at least a 90' azi- [ ( muthal displacement) exists between the redundant equipment expected to be af-i fected by secondary burning. [ I 4 CONTAINMENT STRUCTURAL CAPACITY I j The burning of hydrogen inside containment has the potential to induce pressure i excursions in excess of the containment /drywell design values. To determine ( the pressure capability of the containment structures, required by 10 CFR 50.44 (c)(3)(iv)(B), each licensee provided its plant-specific analysis for staff review. The details of the staff's evaluations regarding the containment and j drywell ultimate capacities are documented in each of the plant's respective SER supplements. Rather than repeating these evaluations, a brief description i of the Mark III containment will be provided. [ Mark III SER 14 [ i

In the Mark III contain.sent design, the containment completely surrounds the drywell. At the bottom of the containment, a 360-degree annular suppression 1 1 pool is located between the containment wall and drywell wall. Below the pool surface, horizontal vents are constructed in the drywell wall. The principal difference between the four plants is in the characteristics of the containment shell, as illustrated in Table 4.1. For Grand Gulf and Clinton, the primary containment is a steel-lined, reinforced concrete structure consisting of a vertical cylinder ano a hemispnerical dome top. For River Bend and Perry, the primary containment is free-standing steel vessel consisting of a vertical cylinder and a torus-sphsrical dome surrounded by a concrete shield building. The internal containment design pressure of 15 psig is the same for each plant, j The ultimate pressure capacity was determined to be about three times design (i.e., approximately 50-60 psig) for each plant. Since the drywell structure j is designed to greater pressure values than the contairment vessel, the drywell i ultimate capacities also are greater and are not limiting in the forward or reverse direction. The containment pressure capacity, taking into consideration limiting containment penetrations, is used as the limiting parameter when evaluating the consequences of hydrogen deflagrations inside containment. Figure 4.1 is an illustration of a Mark III containment configuration, i l 5 DEGRADED CORE EVENTS AND HYDROGEN GENERATION i j 5.1 Introduction To determine the consequences of hydrogen burning, the hydrogen generation i release must be addressed to establish a representative hydrogen generation event (HGE) and define representative hydrogen release profiles a The regulation, 10 CFR 50.44(c)(3)(vi)(B), specifically requires that the fol-lowing be considered in the analv.is: (1) large amounts of hydrogen generated after the start of an accident (hydrogen resulting from the metal-water reaction of up to and including 75% of the fuel cladding surrounding the active fuel region, excluding the cladding i surrounding the plenum volume); i l (2) the period of recovery from the degraded condition; l (3) accident scenarios that are accepted by the NRC staff and that are accom-J panied by sufficient supporting justification to show that they describe the behavior of the reactor system during and following an accident result-ing in a degraded core. The HCOG analyzed two degraded cort accident sequences (HCOG transmittais HGN-003, -006, -018-P, -031 -052, -055, -072, -104-P, -112-NP, -129-P and -132). The base-case scenario begins with a loss of offsite power, followed by rea: tor scram, isolation of both the containment and MSIVs, and power conversion system unavailability. One diesel generator fails to start and the relief valves cycle on high reactor pressure as a result of MSIV isolation. Relief valve cycling results in one stuck-open relief valve (50RV). The second scenario models a small break in the drywell by using the same total hydrogen and steam release histories as the previous case but the predicted hydrogen and steam release is mechanistically split between the drywell and the containment. Mark III SER 15

t Table 4.1 Comparison of BWR Mark III Containment Characteristics i i e Characteristic Grand Gulf Perry River Bend Clinton Rated thermal output, MWt 3,833 3,579 2.994 2,894 Number of fuel bundles 800 748 624 624 L i Orywell structure: Design pressure, psig 30 30 25 30 l External design pressure, 21 21 20 17 [ psid e Air volume, ft3 270,000 277,685 235,196 246,500 suppression pool volume (includes vents), ft3 1.3E4 1.12E4 1.3E4 1.1E4 l Suppression pool surface area, ft2 553 482 522 455 Holdup volume, ft3 50,000 40,564 20,353 33,804 i Holdup surface area, ft2 3,145 2,617 2,564 2,490 Containment vessel: Design pressure, psig 15 15 15 15 U]timatepressurecapacity, [ psig 56 50 53 33 External design pressure, psid 3 0.8

0. 6 3

l Total air volume, ft3 1.4E6 A.141E6 1.192EG 1.551E6 i Air volume below hydraulic control unit floor, ft3 J'1,644 181,626 153,792 173,000 i Suppression pool volume, t ft3 1.74E5 1.06ES 1.2855 1.35E5 Suppression pool surface area, ft3 6,667 5,900 6.40H 'i,175 r i Upper pool makeup vclume, l ft3 35,380 32,P30 0 14,655 i Containment spray flow rate (1 train), gpm 5,650 5,250 0 3,800 Number of loss-of-coolant-i j accident vents 135 120 129 102 l l i i i f i l l t 6 l Mark III SER 16 i I

v, m / N1 SHitLD 9p SUILDIN G i n. . pCONTAtNMENT t DRYWELL HLAD 7 ,,,,,.UPPE R POOL p .r n J [, REACTOs d/SRVOtSCHARGE w y. g, q v ipREACTOR F SHIELD WALL r. 4 [,', l; ,,ARYWELL [ . / a, ,j ,i e (( .j ,,,, -WIIR WALL t.. l ( ,7 ,; p' j/ l.f l F p ! p,;

1. ..pHOR20N*AL

• e

'...... s.l vgNTs .T' ; ' '.*,j , ,*.,i*,,' " su m 'Jp SUPPRES$t0N lu $- '. g. l ~ poot l N m ,..........,r, ,..m, i .,....e .,....., g..,..,..., ;, ;, ;. '*..., *..... r.' ' ? r,' e - .. e. e. ;. ...,;*.......e..,......... '.,..., o t.,j.* ..c ,1 1 i l Figure 4.1 - Typical Mark III Containment Configuration Mark III SER 17 L

The transients resulting in an 50RV were selected (1) to ensure a rapid loss of inventory and (2) to account for and create a limiting local thermal containment environment for analysis and testing. Small-break loss-of-coolant accidents (SBLOCAs) were selected as an alternate sequence to address the potential and consequences for hydrogen combustion in the drywell. Otherwise the SBLOCA sequence is identical to the 50RV sequence. For the base-case scenario, all ac powered reactor makeup systems are assumed to initially fail. According te emergency procedures, the operator will depres-surize the reactor when water level decreases to the top of the active fuel or when conditions requiring steam cooling are ret. Following vessel depressuriza-tion, low pressure system injection is assumed to fail. The scenario continues with the core becoming uncovered and core heatup beginning at about 35 minutes into the transient. Limited hydrogen is produced during core heatup. At about 65 minutes into the event, the core is reflooded before it becomes nonrecover-able (exceeding a 50% zirconium (Zr] melt fraction). During reflooding of the core a significant amount of hydrogen is generated. This hydrogen is transported to the suppression pool through the safety relief valve spargers and into con-tainment where it is ignited and burned. The selection of the 50RV sequence was based on the reactor safety study methodol-ogy applications program (RSSMAP) study. In 1986, the staff questioned the absence of the station blackout (5B0) sequence (letter dated February 21,1986). HCOG held the view that SB0 is not a likely HGE contributor based on its relatively low core melt frequency (HGN-055). This conclusion is based on the results of the RSSMAP study (NUREG/CR-1659), which assumed Grand Gulf to be representative of the four plants with Mark III containments. But the results of the GESSAR-II probabilistic risk assessment (PRA) (NUREG-0979) suggests SB0 to be a dominant contributor to the probability for core damage. The PRA results were reinforced by the staff findings report ) in an NRC report (NUREG-1150). In view of these studies, the HCOG revised its submittal to account for $80. These revised results are contained in two reports transmitted by letters dated January 8 and September 9, 1987. The staff's review will focus on those revised results but will also draw on information from previous submittals. Additionally, the review effort focused on the hydrogen (roduction profiles that were derived using the BWR core heatup code (BWRCHUC) (described in Science Application Inc. and International Technical Services (ITS) reports to the staff; HGN-020, -031, -032, -034, -089, -096, and -132; and HCOG/NRC meeting August 28, 1984). The objective of this review was to ascertain the capabilities and the acceptability of the BWRCHUC for use in generating the hydrogen generation pro-files. Particular BWRCHUC concerns were (1) the Zircaloy oxidation model, (2) the transient simulation capabilities, (3) the ability to predict the maximum expected hydrogen production rate, and (4) the ability to predict the total amount of hydrogen produced in each transient. 5.2 Evaluation The evaluation was divided into two parts: (1) the establishment of an accept-able HGE scenario and (2) the acceptability of the BWRCHUC to estimate hydrogen production histories. Mark III SER 18 t

I 5.2.1 Acceptable HGE Sequence The analysis required by 50.44 must be based upon an accident sequence which is "acceptable to the staff" and is at the same time limitod to "recoverable" events. The rule, however, does not "acceptat.lity" or "recoverability." provide criteria for the determination of The staff position with regard to recoverability is that there should be a reasonable expectation that the original core geometry is generally maintained. However, a quantitative definition of a degraded core hazard state that is recoverrble is not required. The purpose here is.,ot to associate core recoverability with detailed phenomena of cladding or fuel melting and reloca-tion, but rather to provide a reasonable cut-off as far as the deterministic calculation of hydrogen production is concerned. The total amount of hydrogen production which must be considtred is specified in the rule itself. It is in this limited sense that the term "recoverable" is used in this evaluation. HCOG proposed a definition of recoverability in terms of the fraction of 4 1 Zircaloy cladding which has reached or xceeded the Zircaloy melting tempera-ture of 2170 degrees K. The staff acce ted a 50% Zircaloy clad melt fraction 4 1 as the cut-off point for "recoverabilit " based on HCOG's report that j analyses indicate that at this point si nificant fuel melting is in progress. Itisthestaff'sjudgementthatthemantenanceoftheoriginalcoregeometry after damage to this extent is unlikely. Therefore, for the purposes of hytrogen rule considerations and hydrogen generation rate estimates, the 50% Zircaloy melt fraction criterion is acceptable. 1 With regard to the "acceptability" of sequences, the staff considered two cri-1 teria: (1) the likelihood of a given sequence and (2) the contribution to risk from a given sequence. Based upon NUREG-1150, the staff concluded that (1) the most likely HGEs would occur with the reactor vessel depressurized, 4 j (2) the potential for greater consequences is associated with HGEs at high pressure, and (3) the risk from all HGEs is estimated to be extremely low. I In assessing which sequences should be considered by HCOG, the staff also con-sidered the uncertainties associated with low-and high pressure events. For low pressure events the requirements of the rule force conditions which are physically unrealistic (e.g. that the core be recoverable yet 75% of the Zircaloy is oxidized). This results in sequences which are som4what artificial 4 and therefore considerably uncertain. For high pressure events these uncer-l tainties are further complicated by a further lack of experimental data. .1 The staff therefore judged that because (1) the overall risk from HGEs is j believed to be low, (2) from a risk perspective the reduced likelihood of a high pressure HGE is likely to offset the potentially higher consequences of such an event, and (3) the additional uncertainties associated with high-i pressure event progression renders the usefulness of what would be a consider-able effort very questionable, it is sufficient to consider only low pressure sequences. l 5.2.1.1 The HCOG's Base-Case Scenario i j The oase case scenario proposed by HCOG results from a transient caused by less of offsite power, subsequent reactor scram, MSIV and containment isolation, and 4 Mark III SER 19 i I

one 50RV. All ac powered reactor makeup systems are assumed to fail initially. However, the reactor core isolation cooling (RCIC) system which is de powered and/or the fire truck diesel supply are available at Grand Gulf. Emergency operating procedures require depressurization when the water level reaches the top of the active fuel region and some low pressure injection system is avail-able. It is assumed that following depressurization, the low pressure systems fail to inject. The core becomes uncovered and core temperature begins to rise at about 35 minutes into the transient. As the core temperature continues to rise some hydrogen is produced. At about 65 minutes into the transient, the core is assumed to be reflooded at a high flow rate. During the reflooding of the core, large amounts of hydrogen are produced and transported to the con-tainment through the safety relief valves. At this point in time, the core has reached the recoverability criterion (i.e., the Zircaloy melt fraction is at about 50%). ,, variation to the 50RV sequence is the %LOCA scenario resulting from a hypo-thetical drywell break. The drywell break is essentially the same as the 50RV sequence except that the hydrogen is discharged into the drywell as well as through the safety relief valves (SRVs). The staff considered this conservative sequence in o* der to evaluate the effect of hydro 1en burning in the drywell where essential control equipment cabling is found. 5.2.1.2 Station Blackout and NUREG-1150 As stated earlier, the res'lts of the GESSArt-II PRA (NUREG-0979) suggest that $B0 is a major contributor to the probability for core damage. These results were reinforced by Grand Gulf fincings documented in NUREG-1150. Subsequently, the HCOG submitted information to account for SB0 to the staff by letters dated January 8 and September 9, 1987. The results of analyses of Grand Gulf documented in NUREG-1150 indicate that the most probable HGEs result from SBO. The most likely of these sequences (designated as TBU feQuences) consists of loss of offsite power followed by the failure of onsite r. powe* in divisions 1 and 2, the failure o( high pressure core spray (!E and reac'.or core isolation cooling (RCIC), and depressuriza-tion of the reacJor vessel. TBU represents more than 90% of all HGE sequences and more than 93% of all low pressure HGE sequences. The development of the loss-of-offsite power (depressurized vessel) sequence begins by boiling off the entire reactor vessel coolant inventory. With the core dry but at pressure, the operator depressurizes the reactor to increase the length of time available to support core recovery before the initiation of core damage. Following vessel depressurization the core begins to heatup causing oxidation of incore Zircaloy and core damage. Before core damage progresses to a point where a nonrecover-able core geometry could develop, a reactor vessel reflood system is assumed to be recovered. This reflood system then covers the fuel region with water termi-nating the event with a degraded, but recoverable, core geometry. 5.2.1.3 TBU the "Acceptable Sequence" The HCOG had considered the applicability of the various significant sequences identified in the draft version of NUREG-1150 to the HCOG program. The scenarios were divided into three categories; the short-term (about I hr) damage states TBU, TBUX, TCUX, the intermediate (4-6 hrs), and the long-term (8-10 hrs) se-quences TB, TBul, and TQUX (HGN-123). Differences, however became apparent Mark III SER 20

i i when the results of the revised NUREG were reviewed. The revised version of NUREG-1150 estimates TPU to be the dominant HGE sequence, which accounts for i 93% of core damage frequency. The phenomenology of the TBU sequence is i similar to that of the HC0G base case with regard to the 50RV. However, the HC0G experimental testing and analyses, which encompasses the TBU sequence, 1 assumed the igniters were continuously powered, including during the por' ion of the transient when at power was not available. In addition, the rule requires that the containment structural integrity and a safe shutdo.n ce established and maintained. The ability to satisfy these requirements depend on both the total amount and the rate of hydrogen production. To estimate the maximue hydrogen production rate and the total amount of hydro-gen produced, the rate of water supply in the recovtry phase of the HGE is critical. For purposes of the hydrogen control rule, the TBU sequence as described in NUREG-1150 (which encompasses the 50RV as described by the HCOG) is an acceptable sequence leading up to core recovery. In summary, the TBU is acceptable for the time sequence of events and for the hydrogen production rate and total amount. (In probabilirtic risk assessment notation, the terms TB, TBU, TBUX, TBul, TCUX and TQUX denote the following: TB - Station Blackout. TBU - Loss of offsite power (LOSP) with failure of all high pressure functions. The SRVs are opera-tional and the vessel is depressurized. TBUX - LOSP with loss of all AC divisions and failure to depressurize. TBul - LOSP with failure of AC divisions I and 2 and of the high pressure core spray (HPCS). The reactor core isolation cooling (RCIC) operates for 6-8 hours before failing due to high pressure in the tubine exhaust. TCUX - ATWS with LOSP loss of AC and HPCS and RCIC fail-ures. TQUX - Failure of all ECCS functions except power.) 5.2.1.4 Hydrogen Generation Profiles Recovery of cooling water flow is effectively bounded between 150 gpn. from a single control rod drive cooling nump to 5000 gpm from the emergency core cooling system (ECCS) low pressure high-flow-rate core recovery system. The hydrogen generation profiles fnr these extremes are qualitatively and quantitatively different. The probability of a high-flow-rate recovery is expected to be higher than that of a low-flow-rate system, because there are more high-flow systems (or combinations of systems) to inject water into a depressurized vessel; hence, it is reasonable to assume that the operator will attempt more often to recover one of the high-flow-rate systema. A high-flow reflood rate is associated with a high, narrow spike of hydrogen release, while the low-flow reflood rate will yield lower hydrogen production rates but for longer times (see Figures 5.1 and 5.2)(HGN-132). These profiles have been estimated by the HCOG using the BWRCHUC code, which is discussed in Section 5.2.2. The total mechanistic estimated amount of hydrogen released in the low-rate reflood case is higher than that released in the high-rate reflood case. The hydrogen peak release of the high-of the high-reflood case is about 35 seconds wide at half maximum, while for the low-reflood case significant hydrogen release lasts about 8.5 minutes. Table 5.1 shows a summary of the main features of both cases. Mark III SER 21

I. i Table 5.1 Hydrogen Release Profilcs Length of Total Peak Width at Reflood Transient Hydrogen Rate Half Max Rate (gpm) (min.) (lbs) (1bs/sec) (sec) 150 80.0 903.4 0.95 510 5,000 25.8 604.8 8.00 3 ', t 5.2.1.5 Non-Mechanistic Hydrogen Release Profile The hydrogen rule requires consideration of metal-water reaction (WR) for 75% of the Zircaloy cladding surrounding the active fuel region. However t5e esti-i mated amount of metal-to-water reaction in either reflood rate scenario is far less than the required 75%. For Grand Gulf, the active core region cladding is 79,100 lbs. For the oxidation to proceed as: Zr + 2H 0+Zr02 + 2Hz, the amounts of Zr that correspond to the hydrogen released in Figu:res 5.1 and 5.2 are 20,450 lbs and 13 700 lbs, which represent about 26.0% WR and 17.0% WR re-i spectively." (ThIs WR incorporates channel box and stainless steel oxidation.) c A mechanism was needed to increase the release profiles to 75% WR of the active core region cladding, as required by the rule. The 75% WR of the Zr in Grand 4 Gulf is 59,300 lbs, which when oxidized will create about 2,600 lbs of h dro en. It must be pointed out that mechanistic models that account for 75% WR f c ad-ding oxidation result in a severely damaged core exceeding the recoverability criterion. There are many possible scenarios that can be hypothesized to yield 75% WR cladding oxidation; however, no attempt is made to estimate the phenom-ena associated with such an oxidation level because it would require an unreasonable recovery criterion. As discussed previously, after core quenching in the low-rate reflood case, the calculated maximum amount of metal-water ruction is limited to about 26L To meet the rulo requirement of 75% WR, the HCOG submitted a nonsechanistic model L l used to predict hydroge, production based on an energy balance in a severely l damaged core. It assumed that such a core has energy losses at least adequate to remove decay energy in the core, the energy produced by continued oxidation r of Zircaloy, and excess stored energy in the core. It also assumed that terai-nation of oxidation at 75% WR takes place by quenching of the core and removal i i of all excess energy (HGN-034). Considering the above, the oxidation rate will support a constant hyd ogen release of about 0.10 lbs/sec. The staff finds that this release rate is acceptable for hydrogen release to 75% WR, as required by the rule. Therefore, for the scenarios shown in Figures 5.1 and 5.2 the "tails" correspond to 1700 lbs and 2000 lbs of hydrogen, i.e., an extensioi) of about 17,000 seconds (4.7 hours) and 20,000 seconds (5.6 hours), respectively. l L The staff concludes that (1) mechanistic models can not predict the required 75% WR of cladding oxidation in the active fuel region without core damage "Zircaloy is assumea to consist of 1001,Zr. The actual composition of Zircaloy-2 in weight percent includes, Sn: 1.2-1.7, Fe: 0.02-0.07, and Ni: 0.05-0.15 t i Mark III SER 22

5 ttff.I.I.A%f Ill*.IOf tY lt - TJNSI Gl%1 Ill i I 00819 e, C ~ M = M-7- 2 G-z 5 -- OP k 4-to es] O 3-b O O at 2-O I-O~ v '- a i i i - T-s - i 2 2.4 2M 32 3E 4 4.! 1m1F. ( If106ISANOS OF 50 CON 05 ) l figure 5.1 Hydrogen generation rate (5000 ope reflood) 1 i

z T l g i J J 1 i Lv 4 w I s d ..) r i H } ( i N I Ci ,. / ? C F, C. 's 2, l 2*i C :! r -sl - X 5. 2 HI c! ._:==- i .s g>s K 2 ~ W 'lI 'f.,s I e Z<l N L i) E T s W ;=,. I NV I O. ' l P . 4 \\ f '/ f ~ Z5i \\. WsI 'N E i - :r i

s.,N

t. <R g,

e = V wi N \\ W g.~ \\ S \\ C l rs N l i e i ,N 4 i 4 i r; r-q T, O N M C + = c c c s a e d 8 i i ( m/w411 11YW NOl1YWIN'30 N3DOWQ.U1 Mark III SER M 29 1

I beyond the recoverability criterion and (2) the use of a non-mechanistic release model based on heat Lalance is reasonable and acceptable. This leads to an oxi-dation rate producing 0.10 lbs of hydrogen per second, requiring an extensicn of i about 4.7 and 5.6 hours for the scenarios of Figures 5.1 and 5.2, respectively. 5.2.2 BWR Core Heatup Code (BWRCHUC) 5.2.2.1 Introduction f The BWRCHUC has been used by the HCOG to calculate hydrogen rate release profiles for the hydrogen generation sequences described previously. The areas the staff l cinsidered in the review of the BWRCHUC is discussed below. i i TM BWRCHUC was not validated or benchmarked to global core experimental data, rather it relies on collective engineering judgment and understanding of the i phelorena taking place in a core disruptive accident. The lack of benchmarking or validation is due to the absence of suitable experimental data. This lack of benchmarking prevents the results of the code from being used directly without [ appropriate consideration of selected input parameters. The results of the BWRCHU' should be seen as an engineering estimate of the anticipated phenomena. Accordingly, the code review was aicec' at the reasonableness of the modeling, the physical significance of the assumptions, and possible conservatisms in the estimate. Reasonableness was assessed in terms of models and hy)otheses that have been advanced by other researchert. in this field and any otier evidence f that could be gleaned from whatever limited and partial experimental informa-tion was available. For code modeling, the TBU sequence for an HGE was consto-ered equivalent to the 50RV sequence (paragraph 5.2.1.4) with respect to the depressurization and core uncovery time,is the simplest and most straight-thus similar as far as hydrogen l generation is concerned. This sequence forward, thus having the highest probability of being modeled correctly, The BWRCHUC is a well-written computer code in that (1) it f'aithfully represtats the BWR geometric core design and (2) the models included in the code are ade-quate to cover the specific HGEs selected for analysis by the HCOG and repre-sented by the TBU sequence. Modular architecture has been used extensively, i where each module (subroutine) in the code treats a different phenomenon or as-pect of the problem. The code is built by connecting the various modules with executive routines. The numerical solution technique applied in the BVRCHUC is apparently as good as any employed in severe accioent codes. Numerical stability, j as reported by HCOG, is evidenced by the graphs of code output and the fact that reflooding calculations can be run, d The BWR core geometry is very complex. Some subtleties of the the potential to affect the prediction of hydrogen generation. geometry have Therefore, it j is appropriate that a best-estimate code contain a representation of the gecae-try that is as complete as is reasonably achievable. This has been done in the BWRCHUC. Considerable attentica has been drawn to the fact that the BWRCHUC allows for a different two phase water level to be predicted in each fuel assem-bly represinted. A separate level for the core bypass level varies according to the bundle power since the water in an assembly is assumed to be saturated at the system pressure. Water levels may also vary because the void fraction of i i Mark III SER 25 i ,,-.n,

the water in an Ilsembly is a function of assembly power. The byp ss level cal-culation further assumes that water in the bypass is subcooled and thus corres-ponds to the collapsed water level in the core. There is a hydraulic connec-tion between the assemblies and the bypass so that the water level in the bypass is reduced as the core water inventory is boiled away by the decay heat generated within the assemblies. This representation closely corresponds to a partially covered BWR/6 core at low pressure before any structures in the core reach tem-peratures sign #ficantly greater than saturation. 5.2.2.2 Phenomenological Assumptions A model for channel blockage was included in the code, but has not been employed in the calculations since experimental results did not support total flow blochage. The blockage model assumed that the fuel rod cladding melts while i the channel box remains intact. Molten cladding is then assumed to slump and refreeze within the channel forming a complete blockage, which prevents steam l from reaching the Zircaloy surfaces within the assembly. In addition, steam I generation below the blockage pressurizes that portion of the assembly forcing the two phase level in that assembly below the core plate. Since no steam enters the channel, all oxidation would stop. Experimental results from the PBF tests (HCOG presentation to NRC January 14, 1985) indicated that a reduction in the flow area as a result of Zircaloy slumping did occur, but that complete blockage did not form. Without the channel olockage model hydrogen production is maximized all other conditions being the same. The lack of clad motion or channel blockage is a very conservative assumption with regard to hydrogen production. It is assumed that the control ods will remain intact since it is consistent with the recovery criterion. Un@r certa',n conditions experimental evidence (R.O. Gaunt)suggeststhatBWRcontrolrodbladesr.ouldmeltearlyinthecore heatup phase of a transient. This would lead to the possibility of local loss of control; thus, when the core is reflooded, local criticality could result in intense heat production and core damage beyond the limits of recoverability. Therefore, control rod melt would be beyond the scope of this program. 5.2.2.3 Steam Production The modeling of steam generation within the reactor pressure vessel (RPV) can have a significant impact on the quantity of hydrogen generated. While some aspects of steam generation are accurately modeled in the BWRCHUC, other sources of steam are not nodeled at all. The steam generation modeling generally is incomplete; howaver, for the most likely HGE considered, the steam sources not represented do not significantly impact production of hydrogen. Within the BWRCHUC, the fol'.owing five sot.ces of steam generation are modeled: deposition of the decay power from that portion of the fuel assembly below the two phase level into the saturated water within an assembly heat transfer (by nucleate boiling) from portions of fuel rods, channels, control blades, and the core shroud that are at temperatures greater than saturation when they are covered by the two phase level Mark III SER 26

t i i radiative heat transfer from portions of control blades that have tempera-l tures higner than saturation to surrounding channel walls when the two-phase i 'evel within the channel is at or above the portion (at elevated tempera-tures) of the control blade lashi ; " rater in the downcoser and lower plenum as a result of reduc-l tw in tie RPV pressure (Pressure-time history is provided by user input.) 3 t i evaporatira of core spray droplets entering the top of a fuel assembly i during re/looding of the core Steam generation resulting from flashing of the water inventory within the fuel assemblies and in the bypass region is not modeled. If system pressure would decrease, flashing would occur. However, the selected HGE sequence does not 4 i involve changes in pressure vessel pressure after hydrogen generation has begun. l 1 It is assumed that the RPV pressure is constant for at least 10 minutes, which j i is the time required to remove the bulk of the heat in the lower plenum struc-l tures. Therefore, the lack of a flashing model is not a factor. t Downward relocation of molten Zircaloy can have a large effect on steam genera-tion. If the two phase level is above the core support plate, molten Zircaloy can run into water. Quenching or relocating Zircaloy in water would enhance steam and hydrogen generation. This phenomenon is not modeled in the BWRCHUC. However, there is no water above the core support plate when Zircaloy melting i occurs. Modeling of the melt relocation into the water would not increase the quantity of hydrogen produced compared to that which will be produced in the i core reflood because of the more favorable surface-to-volume ratio. l l l j An oxidation cutoff temperature is used in the BWRCHUC as a surrogate for the effect of cladding and channel box relocation and subsequent quenching thereby i removing the Zircaloy frcm the oxidizing environment (R.O. Gaunt and HC0G pre-4 sentation to NRC January 14,1985)- The HCOG estimated Zircaloy oxidation vs. Zircaloy temperature and concluded that 2400WK is a conservative representation l to account for this effect (HGN-034, item 4). Based on the evaluation performed l by ITS, the staff has accepted the 2400'K as the irreversible oxidation cut-off f temperature (letter to HCOG June'4, 1985). i ] In the reflood stage, querching of Zircaloy that is at temperatures higher than i the saturation temperature is nonsechanistically estimated. This can lead to i overprediction of the steam generation rate during the reflood phase. For nodes 1 that are more than 100VK above saturation, quenching is assumed to take place f 4 { in a single time step thus accelerating the heat transfer process and steam t 1 production, j Steam flow in the bypass region is underpredicted. However, the effect of this J underprediction of the b ass steam flow rate on the overall prediction of r hydrogen release is smal. Overall steam generation rates in an overh:sted i I

r. ore could be underpredicted for transients in which the two-phase level is 1

above the core support plate. Inthestaff'sjudgment,theextentofthis l i underprediction is small compared with the uncertainties associated with l predictions of this nature, j f 1 f i Mark III SER 27 I l l

In summary, steam generation before reflood is reasonably well predicted provided the RPV pressure has been constant for approximately 10 minutes. In the sequence considered, the RPV is depressurized and stean and hydrogen production take place under conditions of constant pressure. 5.2.2.4 Hydrogen Generation As with the modeling of steam generation, the approach to modeling hydrogen generation is reasonable considering the difficulty of representing the phenom-ena to modelling techniques. The lack of models for a few relevant phenomena combined with some of the assumptions made for phenomena that are modeled, leads to some uncertainty with regard to the predictions of the hydrogen generation rate during the dominant HGE. This uncertainty is expected to be negligible (i.e., possess compensating effects) in the present context. tiowever, consider-ing the conservative assumption of no clad motion, we concluded that the overall hydrogen generation estimate is conservative. The considerations / phenomena that are related to hydrogen generation and are not modeled or are undt aedicted are listed below. Oxidation below the location at which melting occurs is not modeled. Because of the underprediction of steam in the bypats channel, oxidation of stainless steel and the outside of the channel is probably underpredicted. Ballooning of the cladding and localized failure resulting in simultaneous ' interior and exterior oxidation is not modeled, thus limited hydrogen underprediction may result. Film boiling in a quenching mode is not modeled. This leads to higher rate of hydrogen production for shorter time periods. It is not clear that an overall underprediction will result In the reflooding stage, vaporization of droplets that enter the top of fuel assemblies by radiant heat transfer does not remove heat from fuel rods. This results in a ccaservative hydrogen production if the maxrsum temperature is below the cut-off and possibly not conservative if it is above the cut-off. It is not clear if the overall effect is nonconservative. Reaction rates of Zircaloy and stainless steel with steam are calculated using the Arrhenius relationship. The reaction rate constants used in these i4 pres-sions were derived by others from experimental results. This modeling o' reac-tion rates and the associated heat generation is appropriate and consists:.t with what is used in other severe accident modeling codes. A hydrogen blanketing fac-tor is included in the formulation of the Arrhenius reaction rate expression. Hydrogen blanketing refers to the possible limitation of the oxidation rate from the diffusion rate of steam through the hydrogen emitted from the oxidizing sur-face. While the process represented by the hydrogen blanketing factor is real, a reduction of the oxidation rate is almost certainly not realized under the conditions expected during core damage in BWRs. Diffusion of steam through the oxide layer is the rate-limiting process. Theref ort:, the hydrogen blanketing effect was not considered in the HCOG calculations, which represents a slight conservatism. Mark III SER 28 i

Because the oxidation rate varies exponentially with temperature, the represen-tation of intact Zircaloy nodes reaching temperatures significantly higher than the melting temperature leads to higher oxidation than would be predicted if melting were explicitly treated. Therefore, this is a conservative assump-tion. However, because the oxide layer is generally thick at these timss, the actual quantity of additional oxidation is considered to be small. One could view this enhanced oxidation as a nonsechanistic approach to representing the initial enhancement in oxidation that probably accompanies slumping molten Zircaloy. Heating of the cladding reduces the tensile strength and increases ductility. Simultaneous heating of the fuel and gases within the cladding leads to pres-t surization of the rod from within. Ballooning of the cladding and I m lized failure may occur before melting. Failure of the cladding would allow the in-terior surface to be exposed to steam. It is therefore entirely possible that both the interior and exterior surfaces of the cladding will undergo oxidation. Since this possibility is not modeled in the BWRCHUC, hydrogen generation rates and total hydrogen generation could be underpredicted. However, in the staff's judgment, the conservatism in the assumption that there is no clad slumping will adequately compensate for this potential underprediction. Overall, it is the staff's judgment that the modeling of the hydrogen genera-tion rate in BWRCHUC is reasonable and the total and peak hydrogen production estimates are expected to be conservative. 5.3 Summary and Conclusions There was a twofold objective in this portion of the evaluation corresponding to two requirements of 10 CFR 50.44: (1) "Use accident scenarios tiat are accepted by the NRC staff." Paragrapn (c)(3)(vi)(B)(3). (2) "Provida an evaluation of the consequences of large amounts of hydrogen generated after the start of an accident...up to and including 75% of the fuel cladding surrounding the active fuel region...." Paragraph (c)(3)(vi)(B)(1). The first requirement corresponds to the dominant accident sequence that leads to an HGE. The information for such a sequence was derived from HCOG submit-tals and conforms to the revised (final) version of NUREG-1150. The TBU st-quence was found to represent 93% of all HGE sequences and consists of lost of offsite power followed by failure of onsite ac power in divisinns 1 and 2 and failure of the HPCS and RCIC. The TBU sequence was found to be similar to the 50RV, which was initially proposed by HCOG. Thus, for hydrogen ger.eration purposes the TBU sequence satisfies the requirements of 10 CFR 50.44. The second requirement is limited to the acceptability of the BWRCHUC to estimate hydrogen generation profiles. The essential characteristics of such profiles are the peak ran, its duration, and the total amount of hydrogen produced. Mark !!! SER 29

t The staff r1 viewed the BWRCHbC code on the basis of thest requirements and information submitted by the HCOG. The staff finds the BWRCHUC cede acceptable for use in calculating hydrogen production profiles. Therefore, the staff finds that the profiles estimated by itCOG using the BWRCHUC are acceptable for use in demonstrating compliance with 10 CFR 50.44. 6 CONTAINMENT RESPONSE - ANALYTICAL MODELING In view of the quarter-scale test program, the emphasis on analytical methods for predicting containment response to hydrogen burning has significantly di-minished. This conclusion is based on the broad range of hydrogen release rates in which diffusive combustion is expected to occur. The staff believes the evaluation of the survivability of essential equipment will be based on the QSTF data. Therefore, there is limited value in pursuing such analytical meth-ods as the CLASIX-3 code; thus, the following evaluation addresses HCOG's ef-fort to resolve the CLASIX-3 code analysis generically. As such, this effort is only relevant at low hydrogen flow rates that are near the flame extinguish-ment limit. As documented by various staff evaluations performed before the completion of the quarter-scale test program, the CLASIX code has been the principal analyti-cal tool in predicting the containment response as a consequence of burning hydrcgen for plants with an ice condenser or Mark III containment. The CLASIX code or the CLASIX-3 code (which is the latest modified version that includes Mark III containment features) deals with deflagration (discrete-type) hydrogen burning. The code is a multivolume containment code that is used to calculate the containment pressure and temperature response in separate compartments. Moreover, the code has the capability to model characteristics that are unique to Mark !!! containments while tracking the distribution of the atmospheric constituents (i.e., oxygen, nitrogen, hydrogen, steam). The staff's desire to demonstrate verificttion/<alidation of the CLASIX code has been a continuing effort. CLASIX results have compared well with results of other NRC-accepted analytical codes and hydrogen burning experiments. Fur-thermore, the HCOG has performed additional code validation by comparing the more recent Nevada Test Site large-scale hydrogen experiments to CLASIX-3 code predictions. This is doc;mented in HCOG's letter (HGN 113) dated January 8, 1987. With regerd to hydrogen burning, the focus on code validation has been on pressure predictions because temperature comparisons are more difficult to predict due to their time and spatially dependent fluctuations. As discussed earlier, the major element of the HCOG's program is the quarter-scale test program. The data obtained from tests were used to perform equip-ment survivability analysis (see Section 7). These tests revealed that diffusion flames on the suppression pool surface can exist at a hydrogen injec-tion rate as low as 0.02 lb/see under certain background conditions. As such, i it is expected for a significant portion of postulated degraded core hydrogen profiles that diffusion flames will be the dominant combustion mode. Since CLASIX-3 does not model diffusion flames, these results have a significant bearing on the extent to which the CLASIX-3 code can be relied upon to predict i containrent temperature environments, which further emphasizes the importance of the test program. Mark III SER 30

t 6.1 Localized Combustion /CLASIX-3 As noted in Section 3.1, testing performed in the QSTF revealed that combustion which occurred below the flame extinguishment limit was not global deflagration-type combustion; but "localized combustion." Localized combustion is character-ized as weak fmes or weak volume btuning through a marginally combustible hydrogen-air t,eam mixture. By letters dated June 10, 1986 (HGN-092-P), and December IE, 1987 (HGN-111-P), the HCOG provided various analyses to demonstrate that the CLASIX-3 model will bound the combustion occurring below the diffusion flame threshold by modeling a combustion mechanism that produces a more severe global thermal environment than has been measured locally in the OSTF for local-ized combustion. The staff requested Sandia to review this approach. In its HGN-092-P submit-tal, the HCOG cotpared CLASIX-3 predictions for a quarter-scale model to exper-imental results of the corresponding test. The CLASIX-3 predictions of the wttwell volume showed that the temperature profile exceeded the volume-wei!Ated average of experimental data. On the basis of this analysis, the HCOG conclud-ed that CLASIX-3 yields conservative predictions of thermal environments inside containment for very low itydrogen flow rates. The staff qt.estioned the appli-cability of using eiperimental data pert,aining to a local rhanomena to demon-strate the capability of a lumped volume code. SNL shared the staff's concerns and recommended that the local combustion phenomenon observed in the QSTF warranted further evaluation. In its HGN-111-D submittal, the HCOG provided a comprehensive assessment of localized coTbustion seen in several quarter-scale tests, in these tests, com-bustion activity, as evident by thermocouple responses, is widespread during periods of low hydrogen flow. Test data do not indicate that concentrated flame energy deposition occurs at fixed locations. Energy deposition appears to be rapid and diffuse and is dominated by convective mixing, combustion-induced turbulence, olume influence, and background gas flows. Typically, peak temperatures recorded during localized combustion are relatively low and persist for short durations. The temperature responses are cyclic and return to relatively low background levels. The HCOG analyzed five quarter-scale tests conducted during the scoping test phase of the program in an effort to better understand localized combustion. At the low hydrogen flow rates, these tests demonstrated certain repeatable trends and the thermocouple activity observed recurrent and generally predict-able. Some of the findings resulting from the evaluation of localized combus-tion are briefly described below. (1) in tasts without sprays, combustion was generally widespread.

Whereas, when sprays vere activated, combustion appeared to be suppressed in open chimneys (i.e., annular quadrants) as a result of cooling effects and shifts in global flow patterns.

Also, enhanced mixing resulting from sprays induced slightly higher temperatures in some areas, but not appre-ciably higher than those recorded when sprays were off. (2) Comparing the scoping test results, it appeared that the locatirn of the 50RVs did not have as significant an effect as other parameters, such as variation in hydrogen flow rates. Mark III SER 31

l (3) Prcbably the most important finding pertained to combustion activity in f the vicinity of the hydrogen igniters. The closest thermocouple located to a nearby igniter was about 15 inches laterally or about 6 inches later-ally and 15 inches above the igniter. Data indicated that temperatures close to igniters were generally no more severe than recordings several toopenflowregIons,ncomparingtheeffectsofblockagesaboveigniters j feet away. Also whe a significant increase in temperature was not ob-served. Combustion energy dispersion was prevalent. To further support its findings of turbulent mixing induced by combustion, the HCOG included a discussion of a test in which pool flames were observed. A thermocouple was placed about I foot directly above the pool surface over an active sparger. Readings indicated that at low hydrogen flows the flames at this location appeared to be intermittent and unstable. The temperature re-sponse did not exceed 4250F as a result of these unsteady pool flames. The HCOG contends that, because of the efficient mixing, one should expect local hydrogen concentrations elsewhere in the facility to be less than at the sup-pression pool surface. Moreover, this fact coupled with temperature readings (discussed above) and the absence of visual indications regarding flame forma-tions above the HCU floor, is not strongly supportive of a hypothesis that sus-tained high-temperature localized combustion zones will be established at very low hydrogen flow rates. In addition, HCOG indicates that the temperatures generated from pool burning at low hydrogen flow rates (i.e., about 0.15 lb/sec) from resultant hot plumes represent a more severe thermal environment than localized combustion. As part of this assessment, HCOG provided additional information with regard to the role of the CLASIX-3 code in its analyses and the conservatisms used for containment modeling. While global or large volume deflagration, as modeled by CLASIX-3, did not occur in the QSTF, the HCOG contends that the CLASIX-3 model-ling would conservatively bound the observed localized combustion environment. To assess the severity of the environment from an equipment survivability per-spective, the HCOG compared the thermal loads created by the ecst severe local-ized combustion reasurements at the QSTF to the corresponding CLASIX-3 temperature profile. The results of this comparison show the CLASIX-3 profile generates a significantly more severe environment than that produced by localized combustion. The staff requested that SNL review this issue along with the consideration of scaling aspects. SNL determined that the HCOG adequately addressed the likely locations for localized combustion and identified reasonable bounds for the most threatening thermal environment for equipment located near regions of lo-calized combustion or in the resultant hot plumes. Moreover, the thermal local comparison in combination with the HCOG's discussion of localized combustion provide adequate justification that the CLASIX 3 thermal load would be more severe than that experienced in the QSTF for low hydrogen injection rates. In conjunction with discussions contained in the QSTF test report (HGN-121 P), SNL asserts that there is reasonable assuran:e that the thermal response at full scale will be no more threatening than that experienced in the QSTF. The staff has also evaluated this issue and concurs with SNL's assessment. Based on the modeling methodology used in t"e referenced subcittals (e.g., low hydrogen flow rates and the focus on the wetwell profile), the staff finds that the CLASIX-3 predictions would be acceptable in determining the containment environmental conditions as a consequence of localized hydrogen burning. Accordingly, these profiles could be used to evaluate the survivability of equipment. Mark III SER 32

1 i I 6.2 Containment Pressure and Tergerature Calculations i Letters HGN-092-P and HGN-109-P documented the HCOG's calculations of the con-f tainment pressure and temperature response based on postulated degraded core scenarios that are discussed in Section 5 using the CLASIX-3 code. To deter-i mine the adequacy of the hydrogen ignition system (HIS), the HCOG considered i i two types of accidents in its generic analysis: a stuck-open relief valve 1 (50RV) transient and a small break loss-of-coolant accident (SBLOCA) in the l ]' drywell. Thecomponentofthehyorogenreleasehistorythatisofinterestin j this analysis is referred to as the tail" portion and represents a nonmechanistically defined constant hydrogen production rate. As discussed c above, the CLASIX-3 results bound the thermal environment that may be produced for low hydrogen release rates that are below the diffusion flame extinguish-ment limit. I HCOG provided a generic sensitivity study using the Perry Nuclear Power Plant I q containment characteristics for the CLASIX 3 model. In this sensitivity study, different parameters were varied to assess the effects on the calculated re- ) suits. The staff focused on the most important parameter considered, which was [ l the assumed availability of the contair aent sprays. HCOG had chosen to use the l CLASIX-3 code predictions without sprays (i.e., for the 50RV case) in its ge-9 j neric survivability study (discussed in Section 7). For the equipment surviv-1 ability analysis to be generic, it became necessary to consider the no-spray t case because fan coolers rather than sprays are part of the River Bend con-4 t j tainment design. 1 i For the 50RV case, all mass and energy releases were directed into the suppres- [ 4 j sion pool. The CLASIX-3 model used in the generic analysis simulated four com-j partments of the Perry containment: the drywell volume, the wetwell volume (bounded by the HCU florst and the surface of the suppression pool), the inter-i mediate volume (bounded by the HCU floir and the refueling floor), and the con-i l tainment volume (above the refueling floor). Figure 6.1 presents a schematic i representation of the model. Ignition of hydrogen combustion was assumed to f { occur at a 6% hydrogen concentration with 65% combustion completeness. The CLASIX-3 50RV base-case model produce a transient in which the hydrogen was 1 ignited in a series of burns in the wetwell volume. Figures 6.2 and 6.3 show l J the computed wetwell temperature and pressure profiles. The early portien of j the transient resulted in the highest wetwell temperature. This is symptomatic j of the hydrogen spiked release in the early phase of the release profile. Dif-t fusion flames would be prevalent in this interval and would be beyond the range of use for the CLASIX-3 methodology. For the major portion of the temperature profile, the wetwell burns produce a peak wetwell temperature of above 800'F. r i j At t5e end of the hydrogen release period, the calculated hydrogen concentration [ ] in the containment volume did not reach the ignition criterion of 6%. In the t 1 CLASIX-3 calculation, tt.e HCOG assumed a containment burn to occur at this lower j concentration which resulted in the most severe pressure excursion, to approxi-mately 23 psig. l I ] 6.3 Oryvell Analysis I I For the base-case analysis of a small pipe break in the drywell (DWB) the CLASIX-3 f containment model was similar to the 50RV case except the hydrogen / steam source t l' t Mark III SER 33 ( o

terms are directed to both the drywell volume and the suppression pool. The Da? scenaric was chosen because of the pntential and consequences for hydrogen combustion in the drywell. Of the cases studied, only the 2-inch DVB case had conditions where a hydrogen burn was predicted to occur. Ignition in the dry-well was limited by lack of oxygen (i.e., below 5%) because air is forced from the dry. ell by vessel blowdown. The only burn predicted by CLASIX-3 for the 2-inch DWB case resulted in a peak drywell temperature of about 1050'F and a peak drywell pressure of about 13 psig. For the events cent edered, where high steam flows are directed into the drywell along with the diversion of most of the hydrogen to the suppression pool, the hydrogen threat to the drywell appears to be relatively small. As indicated in Section 7. HCOG performed thermal re-sponse analysis of selected drywell equipment. The results demonstrated that the equip.aent would survive the drywell burn. 6.4 oxistence of Drywell Diffusion Flames In the DWB case, air would be reintroduced in the drywell through vacuum breaker actuation or operation of the drywell mixing system. The drywell environment is predicted to be a hydrogen-rich / oxygen-lean mixture. When oxygen is re-introduced in the presence of an ignition source a diffusion flame may result in the vicinity of the oxygen source. ThispossIblecombustionphenomenonis referred to as an inverted diffusion flame. This is a concern sicce the poten-tial to establish a continuous inverted diffusion flame at the oxygen source may result in locally severe thermal loadc. By letters dated June 25, 1986 (HGN-091), and June 10, 1987 (HGN-119) HCOG eval-uated the potential impact of inverted diffusion flames in plants with a Mark III containment. In the HGN-091 submittal, the HCOG discussed the criteria for establishing the existence of inverted diffusion flames. The HCOG indicated that flames will not occur in the drywell when conditions are outside the flam-mability curve. In the HGN-119 submittal, the HCOG further discusses the low l likelihood of achieving the necessary combustible conditions in the drywell l based on the CLASIX-3 predictions. SNL reviewed the initial submittal and determined that the HCOG did not provide sufficient justification to preclude drywell burning. Specifically, SNL com-mented that the flammability limit merely establishes the limits that will allow flame propagation; burns that do not propagate into the mixture are not precluded by being outside the flammability limits. Furthermore, it was not obvious that the burning mixture should be expected to follow the path predicted by the HCOG. Generally, there is a lack of experimental data to support the HCOG's position. However, recent risk studies do not support the DWB case as a dominant core-melt / degraded-core event for plants with a Mark III containment; therefore, fur-ther phenomenological investigation may not be warmnted. Drywell break events are further discussed in Section 5. In addition, tne expected redundancy (i.e., spatial separation of equipment performing the same function) of the critical equipment should compensate for possible locally severe thermal loads. The staff be'ieves there is a reasonable level of assurance that the consequences of a drywell creak event would not pose a significant threat to containment integrity and would not preclude safe shutdown of the plant. However, the staff will reque:t each licensee of a plant with a Mark III containment to confirm Mark III SER 34

PERRY CL ASIX-3 MODEL wursvuvurn-C ONTAINMENT ( v 0L. 41 e-n. I l I 6 i l smaa, jCapa,citag e' I t I p i i tatvVu estastas g N CRYACLL IN T E R W C0lLT r l s m l suass Ltamacy g y ni,,3 3 (v0L.1) l cots l = g h h i l seaar uppta poet staaeravtaj coup l l i 8 l l e 4 i i g -s witwrLL f;;;;;;.. cr. r;, C 5'OPi>R ES$ ION d .J se - m. -y-m cyoL,a P00L CHiWhtY .z .. m 1.. '^2 l e eg o. in octa e.a t c tion s l r ages in ont ein t e rs ee I'I A' "I A N O ~susausussu Figure 6 1 Perry CLAS!" Model Source: HM, 192-P Mark III SER

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r n, 2 ~ _g } g .h _o -x-f- ~ c sR k8 - :: r A ~ Eu e I E $Y. ~ 2g nN Eb -c 93 M__. ~ J t=D C C i i i i i i i i i i i i i e e h c. (f 6 N O n N 4 4 o o o o o o o o o (s pw o4 60w a) (s) awninaans: Mark III SER 88 34

n. -R t i 3 p i w L e 1 i I t It: IE tt i ~ Eh ua e t 86 Ch ~* SS ( 7e t w i o i i i i i i i ? 8 R '2 D t t t I (ess) swnssww I ? Mark I!! SER M 37 j i

the location of critical equipment with respect to potential oxygen sources through the drywell vacuum breakers and drywell mixing system to support the above conclusion for each plant. 7 SURVIVABILITY OF ESSENTIAL EQUIPMENT As part of the analysis, 10 CFR 50.44(c)(3)(vi)(B)(5)(ii) states: Systens and components necessary to ests511sh and maintain safe sh'Jt-down and to maintain containment integrity will be capable of per h rm-ing their functions during and af ter exposure to the environmental conditions created by the burning of hydrogen, including the effect of local detonations, unless such detonations can be shown unlikely to occur. Accordingly, each licensee with a Mark III containment is required to demonstrate that the essential equipment located inside the containment will survive the hydrogen burn environment. To support this objective, the HCOG conducted two programs to define the environment that would result from hydrogen cembustion. As discussed earlier in this evalaation, the quarter-scale test data will be used to define the environment that sculd be produced by diffusive combustion on the suppression pool surface. In addition, the CLASIX-3 code analysis will be used to define a bounding environment for localized combustion below the diffusion flaw extinguishment limit. 7.1 Identification of Essential Equipment The equipment that has to survive hydrogen burning was selected on the basis of function during and after a postulated degraded core accident. Generally, all the equipment located in the containtrent that was considered to be in one of the five categories listed below was considered to be essential for the safe shutdown of the plant. (1) systems and components that mitigate the consequences of the accident (2) systems and components needed for maintaining the integrity of the containment boundary (3) systems and components needed for maintaining the core in a safe condition (4) systems and components needed for monitoring the course of the accident and providing guidance to the operator for initiating action in accordance with emergency procedure guidelines (5) components whose failure could preclude the ability of the above systems to fulfi)) their intended function Using these criteria, the HCOG identified the equipment that would be needed to be evaluated for survivability. In its letter (HGN-084) dated May 16, 1986, the HCO3 transmitted to the staff the list identifying the following system /coeponents: Mark !!! SER 38

l l (1) containment penetrations: air icek, hatch seals, electrical penetrations, l vent valves, and vacuum breakers l (2) drywell components: air locks, hatch seals, and post-accident vacuum l breakers (3) hydrogen igniter system (4) combustible gas control system: hydrogen recombiners, drywell mixing system, and post-accident atmosphere sampling valves (5) containment cooling: spra/ isolationvalus,LPCIinjectionvalves,and unit coolers (6) autaatic depressurization system (7) containment and reactor monitoring: containment and drywell temperature instruments reactor pressure vessel wide range pressure instruments reactor i,ressure vessel wide range and fuel-zone level instruments (8) assostated instruments, controls, cables, interlocks, terminal and junctionblocks. The staff finds that HCOG's generic equipment survivability list contains the equipment essential for safe plant operation under postulated degraded core accident conditions. As part of the final an lysis, each licensee with a Mark 111 containeent should provide plant-specific information corresponding to the generic list in conjunction with unique de,ign features that are relevant to l the selection Criteria. 7.2 Generic Equipment Survivability Analysis (Localized Combustion) As discussed in Section 6, pressure and temperature predictions were obtained by using the CLASIX-3 code. This calculational methodology was used to provide the containment environment or boundary conditioris necessary to perform equip-ment response.nalyses for hydrogen release rates below the diffusion flame extinguishment limit where burning is limited to localized combustion. The HCOG believes that equipment survivability can be established generically. The sup-norting analyses was presented in its letter dated August 7,1987 (HGN-118 P). It was stated that a generic approach is sufficient because of the conservative nature of the combustion phenomena modeled by the CLASIX-3 code and the boundary conditions used in the generic equipeent survivability analysis. The HCOG identified a number of conservatisms in its generic analysis; the staff has listed some of the more important itees below. (1) The constant hydrogen release r.te of 0.1 lb/sec, which is the nonsechan-15 tic "tail" portion of the re'sase profile, is unlikely to occur after core recovery, Alsc, on the basis of QSTF tests, diffusion flames on the surface of ths pool may u st as low as 0.02 lb/see indicating localized Mark III SER 39 L

t l combustion would not occur. It is expected that the presence of diffusion flames would probably be the dominant combustion mode, possibly in combi-nation with localized combustion phenomena when the hydrogen flow rate is helow the flame extinguishment limit. The significance of these two dif-ferent combustion modes is the spatial shifting of thermal loads; as such, a single piece of equipment would not continually be exposed to hydrogen l burning resulting in a lower temperature profile. i (2) The CLASIX-3 wetwell temper 6ture profile was used as the boundary condition for the equipment response analysis although the most sensitive equipment if located outside of the wetwell volume. The wetwell has the severest environnent of the three containment volumet. The staff finds that based on limitations of the CLASIX 3 methodology used in the generic analysis, there is no choice but to use the wetwell volume. However, the staff does recognize the selected profile is limiting. (3) In the selected CLAS!X 3 case, there are no active containment cooling mech-anisms (i.e., the lack of availability of sprays or unit coolers). Because of the type of event considered, a recoverable degraded core, the HCOG emptCts that sometire durinq these relatively long transient events, spray / unit coolers would become available. A set of equipment common to each plant with a Mark !!! containment was compiled from the list of generic equipment. Subsequently, the most thermally sensitive equipment, such as cables pressure transmitter, hydrogen igniter assembly, and ADSsolenoidvalve,wereIncludedinthegenericsurvivabilityanalysis. Based on the results of the generic equ,pment survivability analysis, the drywell break equipment response analysis shov ed f avorable results; whereas, in the 50RV case, the thermal analysis response for the pressure transmitter indicated a 27'F ex-ceedance above its qualificatian *emperature. The significance of this result is assessed below. The equipe.ent response analysis for the 50RV case used the wetwell CLASIX *, tem-perature profiles, presented in Section 6, with some modifications. These mod-ified profiles exclude the few initial burns in which diffusion flames would exist and the last induced global burn. As a result, the modified wetwell pro-file contains about 90 serial hydrogen burns. The calculated critical component of the pressure transmitters exceeded its qualification after the seventy-first hydrogen burn. However, the HCOG indicated that the pressure transmitter is expected to survive the hydrogen event because of various conservatisms la the analysis. The staff acknowledges conservatises, as discussed earlier, are contained in these analyses which could compensate for the temperature exceedance over the qualification of the pressure transmitter. Nonetheless, the staff requested the HCOG to provide additional data on the qualification of the pressure transmitter. By letter dated April 5, 1988 (HGN 131-P), the HCOG indicated that during quali-fication testing the transmitter had operated without failure at surface temper-atures approaching 380'F for several minutes (as compared to the qualification of 320'F). As part of the HCOG's response, an equipment response analysis of the pressure transmitter was re-evaluated assuming containment sprays to be available. This response analysis indicated that the equipment surface tempera-ture was about 70'F 1ess than qualification temperature of 320'F. These results Mark III SER 40

demonstrated the impact of sprays to cool the Containment environment, thus maintaining the function of essential equipment. River Bend Station is the only plant without containment sprays, but unit coolers are eart of its design. While specific analyses hava not been performed to support quantification of the cooling effect provided by unit coolers versus sprays, the HCOG concludes that a reduction in background temperature would be adequate to reduce the thermal 1 cads on the pressure transeitter. In summary, HCOG contends that further analysis is unwarranted because, with the potenti!1 for active containment cooling and the conservatisms inherent in the analyses, the pressure transmitter will function as designed during recoserable degraded core events that progress to 75% retal-water reaction. With regard to these analyses at low hydrogen flowrates, the staff agrees with HCOG's position that further effort in t.Nis area is not warranted. Moreover, the staff finds that the determination of equipttent survivability based on the data obtainud from the QSTF for diffusion flames is more appropriate than an assesseent based on localized cembustion coaditions. 7.3 Dif fusion Flame Thermal Envircnment Methodology In itt letter dated July 30 1956 tobeusedbyeachmemberIIcensee(HGN-103),theHCOGoutlinedthemethodology to determine the full scale plant-specific containment ther1al environments from the QSTF data. Ths full-scale environmen-tal conditions would be used as boundary conditions in the HEATING-6 computer code to analyze the response of containment equipment during postulated diffu-sive combustion events. As a result of these analyses, the survivability of essential puipmeat would be determined. From the produttien test *eries conducted for each Mark III containment, the test that produces the most limiting environment at the corresponding (to full scale) equipment location is used. Thermal profiles are constructed by spatial mapping of the test facility data. Specific plant profiles are developed from average temperatures for time intervals of maximum hydrogen flow and low con-sta % hydrogen flo. from the production tests. This allows determinatien o' the plure locations and the effects of blockages and spargers. Full-scale velocities are ccmputed from the quarter-scale measured velocities using Froude scaling; test temperatures are used d;rectly (scaling is 1:1). The convective heat transfer and radiative heat fluzes are computed using the scaled velocities and terperatures. Since this approach establishes an environmental pap, the heat transfer roces that should be considered are dependent on the location of the affected equipment. To validate and assess the heat transfer methodology, a complex (three diaiensional geometry) calorimeter asseebly was used in several quarter-scale tests to subject the calorireter to different locations and different thermal environments. A HEATING 6 model of the complex calorimeter was constructed and the calculated response was compared to the measured response to validate the methodology. This ef fort is presented in the HCOG's letter (HGN-1054) dated August 29, 1986. SAL assessed the submittals and determined that most of the computed results were conservative from the standpoint of the equipment survivability. Therefore, the correlations anc results presented are reasonable. However, SNL recomended Mark Ill SER 41

l that when *,he generic methodology is used for plant-specific equipment evaluations, a revie should be ccaducted to assure conservative specificatiun of the boundary l conditions. In sumary, the staf f finds that the heat transfer methodology dealing with dif fusive combustion as presented in W N-103, provides an acceptable foundation to perform plant specific equipment response analyses. Accordingly, esch l I licenste with a Mark !!! containment intends to use this methodology as part of its final analysis, r; quired by the hydrogen rule. The staff agrees with SNL's recome.*datien, that approp'iate detail of input data should be provided by l each licpnsee to ensure its analysis is conducted in a consen ative l manner. l

7. 4 $ pray Availability l

In the preliminary evaluations of hydrogen igniter systems (e.g., see Grand l Gulf SSER N. 3, NUREG-0931, July 1982) the staff allowed credit for operation l of containment sprays in the analyses of the consequences of hydrogen combus-l tion curing degraded core accidents. The validity of the assumption of contain-ment spray operability was premised un several considerations. First, in the preliminary evaluations of igniter systems the staff and HCOG focused on the 50RV transient and drywell pipe break accident sequences. These accident sequences do not necessarily imply loss of the containment spray function of the RHR pumps, RHR purps may be operable but the LPCI injectior /ath may be interrupted or sost. Further, at the time of the preliminary evaluations the overall tone of the B d emergency procedure guidelines (EPG) was to focus on containment integrity rather than adequacy of core cooling at an earlier point in a degraded core accident sequence. Since the preliminary evaluations were conducted additional infon:.ation has been developed which raises questions regarding the validity of assumptions concerning availability of the RHr. putps in the containment spray mode. In contrast to the earlier focus on the 50RV transient and drywell pipe break recent risk analysis indicates that $B0 is a significant cont-ibutor to hydrogen generation events. For the 5B0 ebviously the loss of reactor makeup is tied to the loss of pumps, including RH't p'erps, in either the LPCI or containment spray code. Thus for the 5B0 sequence the RHR spray function cannot be reason-ably assumed to be available until ac po.er is restored. Fina'1w, the earlier emphasis in the EPG's on containrent integrity vs core coolit. or containment spray operattun has been reversed. In Rev. 4 to ths CVR EPG's (March 1987) the sequence of steps has been modified, use of RHR pumps in the containment spray mode, irrespective of adequate core cooling, is directed as the last step, (nw following venting) to control pressure. For the above reasons the staff concludes the B' alt Mark M I owners should eveluate the containnent and essential equipment response to hydrogec. centration events assuming containment sprays are unavailable, consistent with SBG assumptions and the EPGs. Spray operability can be etodelled but should be treated in the context of establishing sargins for a variety of possible plant conditions. Similarly, assu ptions regarding availability of containaent coolers should be consistent with the basic premise of the SB0 accident sequence. Mark !!! SER 42 i

O 1 7.5 Pressure Effects In HGN-ll8-P, the HC00 indicated equipment located inside containment is quali-fied to a pressure loading of at least 30 psig cpplied externally. The CLASIX-3 predictions produced the most severe pressure rise of about 23 psig in the Mark !!! containment. The staff concludes that pressure is not a concern pending confirmation by each licensee of the 30 psig capablii.y. When the hy % gen ig-nition system is functioning, various contair. ment subvolumes will be randomly affected by hydrogen burning, however, a lurge pressure spike is not expected to occur. 7.6 Detonations The HCOG believes that a ('etonation is not a credible phenom 'i the Mark !!! contalment because (1) no rich hydrogen concentrations..i 'usulate inside containment since the dis P ibuted igniters will initit it, tion as the mixture reaches the lower flamability liait and effectiv, y will occur and (2) there are no reginns of the containment with sufficient M oretrical con-finement to allow for the flame acceleration necessary to yield e transition to detonation. The staff agrees with the HCOG position. As conf rmed by the quarter-secle test results, the atmospheric conditions inside the test facility was well mir.ed and burning at low hydrogen concentrations was prevalent. Thus, the potential for localized accumulation of significant concentrations of hydrogen is concluded to be unlikely. 8 CONCLUSION On the basis of the above evaluation, the staff finds the HCOG topical report, "Generic Hydrogen Control Information for BWR-6 Mark !!! Containments," (HGN-112-NP) dated February 23, 1997, provides an acceptable' basis for techni-cal resolution of the Mark !!! containeent 6egraded core hydrogen issue. Each licensee should provide a plant-specific final analysis, as required by 10 CFR 50.44(c)(3)(vii)(61, which will address the eleiaents specified in 10 CFR 50.44(c)(3)(vi)(B). The HCOG tupical report, or portions thereof, say be referenced where appropriate, taking into consideration staff requirement,s as stated in this report. The plant-specific analysis should provide information needed to demonstrate the acceptability of the hydrogen ignition system (H b) for the respective Mark !!! containment, A critical element of the staf f's assessn(nt for determining the adequacy of the HI5, is the need to enhance / diversify the power source to the system, by providing an independent power supply, as a minimum, to one if the two igniter divis!cns. As indi:ated by recent risk studies, the station-blackout sequence is a dainant consributor to the probability of core damage and resulting gener-ation of hydrogen. As such, the HIS is not functional during these events with-out an independent po.er supply. Therefore, an independent power supply sust be an integral part of the HIS. The staff ree.oenendation is applied to the four affected plants with Mark I!! containments. Mark 111 SER 43

Contingent on the licensees incorporation of the recommendations contained in this report, the staff finds that there is reasonable assurance that the HIS installed in the plants with Mark III containments will act to control the burning of hydrogen so that there is adequate protection against containment failure. In summary, the staff concludes that the following key elements should be ad-dressed in each licensee's plant-specific final analysis to resolve the degraded core hydrogen control issue: (1) hydrogen ignition system design, including the consideration of an inde-pendent power source (2) confirmation of applicability to the generic effort (3) quarter-scale plant specific production testing results (4) primary containment structural survivability quarter-scale testing pressure capacity analyses for drywell and containment, for example, confirm previous plant-specific analyses (ST survivability cf esse.itial equipment identify plant-specific essential equipment define thermal environment from quarter-scale testing perform equipment response analysis confirm that redundancy exists for that equipment affected by second-ary burning and drywell inverted diffusion flames confirm pressure capaoility of equipment (6) licei,see's position regarding the proposed HCOG emergency procedures for combustible gas control l (7) overall conclusions relating to conformance of the hydrogen rule Mark III SER 44 a

APPENDIX A GENERIC HYOROGEN IGNITION SYSTEM TECHNICAL SPECIFICATIONS Generally, technical specifications (TS) of a particular system consist of two distinct sections: Surveillance Requirements to ensure system operability and Limiting Condition for Operation (LCO) to define the allowable operability range in conjunction with various plant actions when needed. Each of the four plants with Mark Ill containments have similar TS for the hydrogen ignition system (HIS). The following discussion on this subject is focused on the proposed generic HIS TS and its deviations from the current TS. Currently, TS on igniter systems in plants with Mark III containmants prescribe two types of surveillance practice. At 184-day intervals, all the igniter assemblies are energized and current / voltage measurements are performed and compared with similar measurements taken previously. If more than three ighiter assemblies on either subsystem are determined to be inoperable, there is an increase of the surveillance frequency to a 92-day interval. A second part of this first surveillance requirement is the verification that inoperable igniters are not adjacent to each other, if more than one igniter on each subsystem ic determined to be inoperable. This requirement is based on the staff's view regarding potential hydrogen pocketing in enciosed areas. The second type of surveillance is conducted at 18-month intervals to verify a surface temperature of at least 1700*F for each accessible igniter and verify by measurement sufficient current / voltage to develop 1700'F surface temperature for those igniter assemblies in inaccessible areas. Accordingly, the bases section of the TS indicates that inaccessible areas are defined as areas that have high-radiation levels during the entire refueling outage; such enclosures include the heat exchanger, filter demineralizer, and the pump room for the reactor water cleanup (RWCU) system. The current LCO allows no more thar. 10% of the igniter assemblies inoperable per subsystem. And if one subsystem is inoperable, the action statement re-quires restorat'on to operable status, or be in the required operationti condition, within 30 days (similar to the hydrogen recombiner TS). By le+ter dated April 16, 1986 (HGN-070), the HCOG propJsed to revise selected portions of the existing plant specific TS as outlined above. Principally, thera are two significant proposed changes: (1) an increase of the allowable inoperable igniters per subsystem to about 40%, as compared to the currant value of 10%, and (2) removal of the surveillance requirement in determining the location of the inoperable igniters af ter the requisite nurber of failed igniters have been attained. Also, as discussed above, the current action statement reqLires an allowable period of 30 days to restore the igniter sub-system to operable status. HCOG proposed to change this interval to 60 days because these events in which the HIS is required to be operable are less probable than design-basis accidents. The staff finds the proposed inoperable period increase is not based on sound engineering jucament since it relies Mast n a SER 1 Appendix A

on being beyond the DBA but does not provide a rationale for 60 days. Thus the 30-day interval is appropriate and should be maintained. In its letter of April 16, 1986, the HCOG provided a justification for the other two significant proposed changes. Essentially, the HCOG cited the con-clusions observed regarding the QSTF testing (see Section 3.1) of a particular scoping test in which about 40% of an igniter subsystem was inoperable in con-junction with the other subsystem not functioning. The staff has concluded relative to the hydrogen aspects of the TS justifica-tions that the HCOG had not provided sufficient justification to relax the TS to such a degree. The staff made its determination because of the inherent uncertainties such as extrapolation of the quarter-scale results to full scale, various injection rates, different safety relief valves actuating, and differ-ent combinations as to where the 40% of the inoperable igniters could be located. Therefore, the allowable value for inoperable igniters should be as low as practical; a 10% value appears to be a reasona' ole limit. The second proposed change is to remove the surveillance that ensures that inoperable igniters are not' adjacent. Principally, this surveillance ensures at least one operable igniter in each enclosed area and coverage of the azimuthal positioned igniters in the open regions. Essentially, the HIS TS are intended to prevent beildup of hydrogen in subvolumes of the Mark III contain-ment, and thereby prelude the occurrence of large volume burns. 'ne following considerations are highlighted as part of the HCOG's justification i for proposing to femove the TS provision to determine that inoperable igniters are not adjacent: The HCOG evaluated the potential flow paths that could transport hydrogen in or near enclosed regions of the containment and determined that no potential hydrogen source exists. It is expected that igniters in open areas will function to preclude local hydrogen pocketing. Observations of the quarter-scale tests indicated that the released hydrogen will tend to mix with the surrounding atmosphere and thus reduce the potential of locally high nydrogen concentrations. The likelihood is low for inoperable igniters being located in such a fashion as to create a large containment subvolume that would be without igniter coverage. Igniters would tend to fail in a random manner. Currently, whenever at least one igniter is inoperable in each sub-system, containment entry is normally required to find the location of the failed igniter. This wuM d subject plant personnel to various occupational safety hazards such as radiation exposures and the risks associated with the construction of scaffolding. i On the basis of there considerations provided by HCOG, the staff has determined that there is reasonable assurance that the proposed TS without the adjacent igniter provision would.1ot have an adverse effect on the effectivtness of the igniter system. l Mark III SER 2 Appendix A

The staff finds the generic HIS TS as documented in the HCOG letter dated April 16, 1986, to be acceptable contingent on the following changes: the 40% silue of allowable inoperable igniters should be 10% in the appropriate locations of the text and the 60-day interval to restere a subsystem in the action state-ment should be 30 days. Each Mark III owner that intends to adopt the generic HIS technical specification must confirm that the HCOG assumptions used in the development of the TS are valid for their plant-specific configuration. i Mark Ill SER 3 Appendix A

APPENDIX B MARX III COMBUSTIBLE GAS CONTROL EMERGENCY PRC EDURE GUICit.INE As part of the generic program, the HCOG has developed Cossustibio Gas Control Emergency Procedure Guideline (EPG) for plants with Mark III contain ants. The latest version of the guidelines with supporting apptodices verr. sent to the NRC by letter (HGN-122-P) dated July 8,1988. This procedum in-ludes operator action for the hydrogen igniter system as well as other r:ombustible sus control systems designed in the Mark III containment, such as hydrogen recombiners and the drywell mixing system. In addition, the proposed procedure provides guid-ance for spray actuation and containment venting. This effort is to supplement the overall BWR Owner Group's EPG program. Figure B.1 highlights the operator actions in dealing with hydrogen in an emer-gency situation. These actions for controlling hydrogen depend on a determina-tion of hydrogen concentration in the containment and drywell as indicated by hydrogen monitors and/or analyzers that obtain gas samples from the containment and drywell. The significant trigger limit used in the EPG is when the drywell or containment hydrogen level reaches a concentration at which a global deflagra-tion could threaten containment or drywell integrity from overpressurization, referred to as the hydrogen deflagration overpressure limit (HDOL). At this limit or when the centainment hydrogen concentration cannot be determined to be below the HDOL and it cannot be determined that the igniters have been con-tinuously operating, the HIS should not be used. The containment HDOL is a i curve of hydrogen concentration versus containment pressure, whereas the dry-well HOOL is a single value representing a peak hydrogen concentration. The containment HDOL is more limiting than the drywell HDOL. The hydrogen ignition system, the hydrogen recombiners and the drywell mixing system are the key hydrogen mitigating systems. As indicated 'i.. Figure B.1, these systems are activated at appropriate trigger points to deal with a pro-gressing hydrogen build-up. With the addition of an independent power source to the HIS, it is anticipated that for most severe accident / degraded core situations the resulting large amounts of hydrogen can be accommodated. As part of the subject letter, HCOG had addressed staff comments which were discussed in a October 22, 1986 HCOG/NRC meeting. In this latest version of the Mark III Combustible Gas Control EPGs (Revision 3), HCOG has addressed staff concern; or provided sufficient justification for their position as discussed below. As one of the initial steps in the EPGs, the operator is instructed to vent the containment and drywell if the hydrogen concentration reaches the minimum detectable concentra 'on (0.5%) in either region, provided the site radioac-tivity release rett expected to remain below the site release rate limiting t condition for operation (LCO). It should be noted that this step is similar to the BWR EPGs for Mark I and Mark It combustible gas control. The staff Mark III SER 1 Appendix B

previously commented that venting may not be necessary solely upon hydrogen concentration above the minimun detectable level and below flannability levels; the use of reconbiners is valuable and should be utilized where appropriatc. In response, since dissolved hydrogen is present in the reactor coolant system during normal operation and the EPGs are based on a symptomatic approach, it is the intent of this step to remedy a hydrogen problem during normal operation, and within the constraints of technical specification limits. HCOG believes there is sufficient guidance to preclude this action from being implemented during a genuine emergency situation. Also, HCOG had committed to modify the generic Mark III procedure at a later date, if necessary, to be consistent with the BWROG's approved combustible pas control procedure. The staff finds that the subject procedure and the HCOG approach to be acceptable. As one of the last steps to control hydrngen accumulation during a progressively worsening situation, containment venting is directed. Venting the containment in spite of the offsite radioactivity release rate would only be considered to restore and maintain the containment hydrogen concentration below excessive linits. Containment failure ray follow if a large deflagration were to occur. Venting the containnent may be the only mechanism which remains to prevent an unecntrolled and unpredictable breach of the containment. The controlled re-lease of radioactivity to the environment is preferable to containment failure ( wherety, adequate core cooling eight also be lost and radioactivity released I with no control. This concept of venting is similar to the emergency procedures for pressure centrol. Regarding the second issue, HCOG provided additional information responding to NRC connent dealing with the limited use of the drywell mixing systems. The staff views containment venting as a last resort to deal with extraordinary conditions. The use of the drywell hydrogen mixing system may delay contain-ment venting by diluting the containment volume (at a higher concentration of hydrogen) with the drywell volume (at a lower concentration of hydrogen). HCOG cited various factors to demonstrate the drywell mixing system is not beneficial for hydrogen control inside the containment volume, which includes: dilution effects are marginal, since the containment is significantly larger than the drywell; the mixing system would re-initiate a LOCA signal and potentially interfere with event recovery; and implementing a modified procedure may induce conflicting direction. In addition, the design intent of the mixing systen is to deal with hydrogen in the drywell. The staff believes some of the HCOG concerns are valid. In addition HCOG had modified its procedures to assure that the HIS would remain operational above the HDOL if it can be determined that the igniters have been continuously operating. The addition of an independent power supply to the HIS would further enhance the reliability of the system. Consequently, the combined effect would reduce tne potential for containment venting to control hydrogen inside contain-ment. Therefore, the staff agrees

• tth HCOG that the inclusion of the drywell mixing system would not provide significant benefits (in delaying venting) as compared to its disadvantages.

Overall, the staff finds the proposed (Revision 3) Mark Ill Combustible Gas Control EPGs are based on sound technical judgment, and are acceptable. Accordingly, each Mark !!! licensee should address it s combustible gas control energency procedure in the plant specific final analysD. Mark !!! SER 2 Appendix B 6

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• +

3 t APPENDIX C BIBLIOGRAPHY Gaunt, R. O. et al., "The DF-4 BWR Control Blade / Channel Box Fue's Damage Experiment," Sandia National Laboratories, to be published. Hydrogen Control Owners Group (HCOG), HGN-003, letter from J. D. Richardson (HCOG) to H. R. Denton (NRC), "Report on Hydrogen Control Accident Scenarios, Hydrogen Generation Rates and Equipment Requirements," April 8, 1982. --, HGN-006, letter from J. D. Richardson (HCOG) to H. R. Denton (NRC), "Report on Hydrogen Control Accident Scenarios, Hydrogen Generation Rates and Equipment Requirements," Rev. 1, September 9, 1982. --, HGN-009-P, letter from J. D. Richardson (HCOG) to H. Denton (NRC), "CLASIX-3 Report " March 18, 1983. --, 011-NP, letter from J. D. Richardson (HCOG) to R. W. Houston (NRC), "Re-sponses to NRC Requests for Additional Information," May 11, 1983. --, 012-NP, letter from S. H. Hobbs (HCOG) to R. Bernero (NRC), "1/4 Scale Hydrogen Test Program," August 12, 1983. --, HGN-014-NP, letter from S. H. Hobbs (HCOG) to H. Denton (NRC). "Final 1/20th Scale Test Report," February 9, 1984. --, HGN-017-NP, letter from S. H. Hobbs (HCOG) to H. Denton (NRC), "Mark III Hydrogen Control Owners Group Final Whiteshell Ignition Test Report," June 7, 1984. --, HGN-020, letter from S. H. Hobbs (HCOG) to H. R. Denton (NRC), "Transmittal of BWR Core Heatup Code Hanual," Oeptember 5, 1984. --, HGN-027-NP, letter from S. H. Hobbs (HCOG) to R. Bernero (NRC), "1/4 Scale Test Facility 3D-Complex Calorimeter," February 13, 1985. --, HGN-031, letter from S. H. Hobbs (HCOG) to R. Bernero (NRC), "Hydrogen Release Histories and Test Matrix for 1/4 Scale Test Program," March 13, 1985. --, HGN-032, letter from S. H. Hobbs (HCOG) to R. Bernero (NRC), "Submittal of Information on BWR Core Heatup Code," April 16, 1985._ --, HGN-034, letter from 5. H. Hobbs (HCOG) to R. Bernero (NRC), "Model for Hydrogen Production Equivalent to 75% MWR," May 17, 1985. --, HGN-051, letter from S. H. Hobbs (HCOG) to R. Bernero (HRC), "Availability of Contais. erit Spray system," July 26, 1985. 1 Appendix C

1, --, HGN-052, letter from S. H. Hobbs (HCOG) to R. Bernero (NRC), "Hydrogen Release Time Histories," August 1, 1985. --, HGN-055, letter from 5. H. Hobbs (HCOG) to R. Bernero (NRC), "Evaluation of SB0 and ATWS Contributions to Hydrogen Generation Events," September 27, 1985. --, HGN-070, letter from J. R. Langley (HCOG) to R. Bernero (NRC), "Mark III Hydrogen Ignition System Technical Specifications," April 16, 1986. --, HGN-072, letter from S. H. Hobbs (HCOG) to R. Bernero (NRC), "Event Sce-narios Considered for Evaluation of Drywell Response to Degraded Core Accidents," March 5, l'.86. --, HGN-073, letter from J. R. Langley (HCOG) to R. Bernero (NRC), "Justifica-tion for Manual Actuation of Mark !!I Hydrogen Ignition Systems," March 5, 1986. --, HGN-084, letter from J. R. Langley (HCOG) to R. Bernero (NRC), "Generic Equipment Survivability List," May 16, 1986. --, HGN 085, letter from J. R. Langley (HCOG) to R. Bernero (NRC), "Final Re-port Assessing Adequacy of Heat Sink Modeling in the 1/4 Scale Test Facility," May 5, 1986. --, HGN-089, letter from J. R. Langley (HCOG) to R. Bernero (NRC), "BWR Core Heatup Code Responses," June 9, 1986. --, HGN-091, letter from J. R. Langley (HCOG) to R. Bernero (NRC), "Criteria for Existence of Inverted Diffusion Flames in the Drywell," June 25, 1986. --, HGN-092-P, letter from J. R. Langley (HCOG) to R. Bernero (NRC), "Report of CLASIX-3 Generic Analyses and Validation of CLASIX-3 Against 1/4 Scale Test Facility Data," June 10, 1986. --, HGN-096-P, letter from J. R. Langley (HCOG) to R. Bernero (NRC), "BWR Core Heatup Code Report," July 30, 1986. --, HGN-098-P, letter from J. R. Langley (HCOG) to R. Bernero (NRC), "Scoping Test Report," July 18, 1986. --, HGN-099-P, letter from J. R. Langley (HCOG) to R. Bernero (NRC), "Transmit-tal of Handouts from June 19, 1986 HC0G-NRC Meeting," July 11, 1986. --, HGN-100 letter from J. R. Langley (HCOG) to R. Bernero (NRC), "Nevada Test Site Data Evaluation," July 31, 1986. --, HGN-101, letter from J. R. Langley (HCOG) to H. Denton (NRC), "River Bend Staion Unit Coolers," July 30, 1986. --, HGN-103, letter from J. R. Langley (HCOG) to R. Bernero (NRC), "Dif fusive Combustion Thermal Environment Methodology Definition Report," July 30, 1986. 2 Appendix C

I --, HGN-104-P, letter from J. R. Langley (HCOG) to R. Bernero (NRC), "Evalua-tion of Emergency Procedure Guidelines Operator Actions Against HCOG Assumptions for Analysis of a Hydrogen Generation Event," August 18, 1986. --, HGN-105-P, letter from J. R. Langley (HCOG) to R. Bernero (NRC),"Diffusive Combustion Heat Transfer Methodology Validation for Equipment Survivability in Hark III Containments," August 29, 1986. --, HGN-106-P, letter from J. R. Langle (HCOG) to R. Bernero (NRC), "Supple-mental Information on Secondary Burning,y' September 29, 1986. --, HGi4-109-P, letter f rom J. R. Langley (HCOG) to R. Bernero (NRC), "CLASIX-3 Generic Sensitivity Analyses," December 9,1986. --, HGN-110-P, letter from J. R. Langley (HCOG) to R. Bernero (NRC), "Co.nbust-ible Gas Control Emergency Procedure Guideline and Supporting Appendices," December 1, 1986. --, HGN-311-P, letter from J. R. Langley (HCOG) to NRC, "CLASIX-3 Summary Re-port," December 15, 1987. --, HGN-112-NP, letter from J. R. Langley (HCOG) to R. Bernero (NRC), "Generic Hydrogen Control Information for BWR-6 Mark III Containments," February 23, 1987. --, HGN-113, letter from J. R. Langley (HCOG) to R. Bernero (NRC), "Comparison of CLASIX-3 Predictions to Nevada Test Site Data," January 8,1987. --, HGN-114, letter from J. R. Langley (HCOG) to R. Bernero (NRC), "Response to NRC Concerns Regarding Potential' Impact of SB0 Events on Operation and Per-formance of the Hydrogen Ignition System," January 8, 1987. --, HGN-115-NP, letter from J. R. Langley (HCOG) to R. Bernero (NRC), "1/4 Scale Test Facility Final Design Report,' February 10, 1987. --, HGN-118-P, letter from J. R. Langley (HCOG) to NRC, "Generic Equipment Survivability Analysis," August 7, 1987. --, HGN-119, letter from J. R. Langley (HCOG) to NRC, "Final Inverted Diffusion Flame Report," Juns 10, 1988. --, HGN-121-P, letter from Langley (HCOG) to NRC, "Report of Hydrogen Combustion Experiments in a 1/4 Scale Model of a Mark III Nuclear Reactor Containment," July 22, 1987. --, HGN-122-P, letter from J. R. Langley (HCOG) to USNRC, "Revision 3 to Mark III Cwnbustible Gas Control Emergency Procedure Guideline," July 8,1988. --, HGN-123, letter from J. R. Langley (HCOG) to USNRC, "Response to NRC Ques-tions on Station Blackout and ATWS Sequences," September 9, 1987. --, HGN-128, letter from J. R. Langley (HCOG) to NRC, "Responses to NRC/SHL Comments on Heat Loss Report," November 6, 1987. --, HGN-129-P, letter, J. R. Langley (HCOG) to NRC, "Revision 4 EPGs vs HCOG Scenarios." April 8,1988. 3 Appendix C

E s --, HGN-131-P, letter, J. R. Langley (HCOG) tc NRC, "Supplemental Discussion of Pressure Transmitter Survivability at Low Hydrogen Release Rates," April 5, 1988. --, HGN-132, letter, J. R. Langley (HCOG) to NRC, "Final HCOG Hydrogen Release Histories," April 4, 1988. --, HCOG/NRC meeting presentation, "BWR Core Heatup Code Results," August 28, 1984. --, HCOG/NRC meeting presentation, G. R. Thomas (HCOG), "Review of Basis for Zircaloy Oxidation Cutoff in the BWR Core Heatup Code," January 14, 1985. International Technical Services (ITS), ITS/ LWR /BNL 85-1, "Validity of the Use of a Temperature Cutoff for Zircaloy 0xidation," by H. Komoriya and P. Abramson, September 1985. --, letter from H. Komoriya (ITS) to L. Lois (NRC), "Review of 0xidation Model-ing in BWR Core Heatup Code," October 30, 1987. Institute of Electrical and Electronics Engineers IEEE Std 323-1974, "IEEE Standard for Qualifying Class IE Equipment for Nuclear Power Ganerating Stations." Mississippi Power and Light Cumpany, letter from L. F. Dale (Miniasippi Power and Light Company) to H. Denton (NRC), "H2 Igniter Environmental Qualifications Test Results," February 14, 1983. Sandia National Laboratory, letters from S. E. Dingman to A. Notafrancesco (NRC), June 26, August 10, September 3, September 4, and December 23 (two letters), 1987. Science Application Inc., SAIC/87/3114, "Hydrogen Generating Events for Boiling Water Reactors with Mark III Containments," by Atefi et al., April 15, 1988, i U.S. Nuclear Regulatory Commission, Title 10, Code of Federal Reaulations, 10 CFR 50.44, "Hydrogen Control Requirements." --, letter from R. Bernero (NRC) to S. H. Hobbs (HCOG) dated June 4, 1985. --, letter from R. W. Houston (NRC) to J. R. Langley (HCOG) February 21, 1986. --, NUREG-0011 "Safety Evaluation Report Related to the Operation of Sequoyah ) Nuclear Plant, Units 1 and 2," Supplement 6, December 1982. --, NUREG-0588, "Interim Staf f Position on Erivironmental Qualification of Safety-Related Electrical Equipment," Rev.1. July 1981. --, NUREG-0831, "Safety Evaluation Report Related to the Opsiration of the Grand Gulf Nuclear Station, Units 1 and 2," Supplement 3. July 1982, and Supplement 5, August 1984. --, NUREG-0853, "Safety Evaluation Report Related to the Operation of Clinton Power Station, Unit No.1," Supplement 6, July 1986. 4 Appendix C

1 \\ --, NUREG-0887, "istety Evaluation Report Related to the Operation of Perry Nuclear Power Plant, Units 1 and 2," Supplement 6, April 1985. --, NUREG-0979, "Safety Evaluation Report Related to the Final Design Approval of the GESSAR II BWR/6 Nuclear Island Design," Supplement No. 2, November 1984. --, NUREG-0989, "Safety Evaluation Report Related to the Operation of River Bend Station," Supplement 4, September 1985. --, NUREG-1150, "Reactor Risk Referente Document," to be published. --, NUREG/CR-1659, Vol 4 of 4, "Reactor Safety Study Methodology Applications Program (RSSMAP)," Grand Gulf Power Plant Unit 1, November 1981. --, NUREG/CR-4866, "An Assessment of Hydrogen Generation for the P8F Severe Fuel Damage Scoping and 1-1 Tests," A. W. Cronenberg et al., EG&G, April 1987. --, NUREG/CR-5079, "Experimental Results Pertaining to the Performance of Ther-mal Igniters," Sandia National Laboratory, to be published. Vinjamuri, K., et al., "Severe Fuel Damage Test 1-4 Data Report " EG&G, Septem-ber 1987. i i I 5 Appendix C

I APPENDIX D ACRONYM LIST \\ ADS automatic depressurization system 8WR boiling-water reactor B'.IRCHUC boiling-water reactor core heatup code DWB small pipe break in the drywell EPG emergency procedure guideline ESF engineered safety feature FHRC Factory Mutual Research Corporation HCOG Hydrogen Control Owners Group (Hark III Containment) HCU hydraulic control unit HDOL hydrogen deflagration overpressure limit l HGE hydrogen generation events HIS hydrogen ignition system HPCS high pressure core spray IEEE Institute of Electrical and Electronics Engineers l LCO limiting condition of operation LOCA loss-of-coolant accident LWR light-water reactor 1 MWR metal-water reaction NRC Nuclear Regulatory Commission PWR pressurized-water reactor QSTF quarter-scale test facility RCIC reactor core isolation cooling RPV reactor pressure vessel RSSMAP reactor safety study methodology applications program RWCU reactor water cleanup SAIC Science Applications Inc. (report designation) SBLOCA small-break loss-of-coolant accident $80 station blackout SER safety evaluation report SNL Sandia National Laboratory SORV stuck-open relief valve SRV safety relie. valve Mark III SER 1 Appendix D +

t TAF top of active fuel 10 CFR ' Title 10 of the Code of Federal Regulations T5 technical specifications Zr Zirconium i Mark III SER 2 Appendix 0 L

i ATTACHMENT 2 RESP 0t:SE TO REQUIREl<EllTS FOR COMTENT OF PACKAGE SUBMITTED FOR CRGR REVIEP (i) The proposed generic requirement or staff position as it is proposed to be sent out to licensees. Staff position is: To require ar independent power source to support the hydrogen igniter system currently installed in Park III plants and to accept topical report HGN-117-NP dated February 23, 1987 as a basis for each Mark III plant's final analysis. (ii) Draft staff papers or other underlying staff documents supporting the requirerents or staff positions. (1) 10 CFR 50.44(c)(3)(iv), (v), (vi), (vii); (2) SER on HGN-112-l'P, dated February 23, 1987, "Generic Pydrogen Contrn1 Inforration for BWR/6 Mark III Contain-ments;" (3) Draft f;UREG-1100; (4) GESSAR SER, NUREG-0979 Supplement 2, Noverher,1984. (iii) Each proposed requirement or staff position shall centain the sponsoring effice's position as to whether the proposal would in-crease requirements or staff positions, implement existing require-rents or staff positions, or would relax or reduce existing require-I ments on staff positions. l The staff position would inplement an existing regulation, 10 CFR 50.44 (c)(3)(iv). Hydregen ignition systems were installed to comply with this regulation. In the preliminary evaluations of igniter systers in Park 111 plants the staff cencluded that electric thermal igniters powered from the main emergency diesel generators were adequate and that the igniters need not function during a station blackout accident. As a result of ongoing research and study of severe accidents, however, the staff propuses to revise the requirements by requiring an independent power supply for the igniters in addition to the existing power supply from the emergency die wl generators. The staff's proposed requirement represents a change in our position regarding implementation of existing regulations as a direct result of new and relevant information. The staff's position is based primarily on the following considerations: (1) the results of recent PRA's (e.g., GESSAR NUREG-1150) indicate that Station Blackout (SBO) scenarios are expected to dominate the estimates of core denage frequency, and thus degraded core accidents, for BWR-6 (ftark-!!!) plants and (2) it is the Commission's intent to require means for hydrogen control for t u rest likely degraded core accidents. l l l

1 I. \\ 2 Under SB0 cerditions the currently installed igniters would not function because they are powered by the main emergency diesel generators. Therefore, in view of the above considerations an independent power supply (IPS) is necessary to assure reliable operation of the igniter system under those conditions most likely to lead to a hydrogen generation event (HGE). (iv) The proposed mettad of irplenentation with the concurrence (and any connents) of OELD on the method proposed. Inplementation of the staff requirements will be carried out as part of the plant specific final evaluations of Mark 111 hydrogen igniter systems as provided for in 10 CFR 50.44. OELD has reviewed the.CRGR transmittal package and the enclosed HCOG SER and has no leg 31 objections, f (v) Regulatory analysis generally conforming to the directives and guidance of NUREG/BR-0058 and NUREG/CR-3568. A formal regulatory analysis of the staff's recoseendation to improve Mark !!! igniter systens by providing an independent power supply has not been perforred. It is our view that this position is a logical consequence of implerenting the requirements of 10 CFR 50.44 given the results of available probabilistic risk assessments for applicable designs (Grand Gulf,GESSAR). Following the TMI-? accident, the NRC recuired that l' ark-III and the ice condenser containments be equipped with systems to control hydrogen generated from recoverable degraded core accidents. Several licensing requirements were imposed for dealing with hydrogen control during postulated degraded-core accidents. These were considered as interim reasures pending completion of the longer tegn hydrogen control studies. The interim requirements related to ice condenser and BWR Mark-I!! plants, for which a construction permit was issued before March 28, 1979, were first published as a proposed rule on December 23, 1981. A final rule (10CFR50.44)wasissuedonJanuary 25, 1985. The final rule requires that ice condenser and Mark-III plants be provided with a hydrogen control systcm justified by a suitable program of experiment and analysis. The systen must be capable of (a) establishing and maintaining safe shutdown conditions (b) maintaining containment integrity, and (c) of handling an arount of hydrogen equivalent to that generated from a metal-water reaction involving 75% of the fuel cladding in the active fuel region. The rule also reauires that a licensee submit an analysis which provides an evaluation of the consequences of large amounts of hydrogen generated af ter the start of an accident and include consideration of hydrogen control measures as appropriate. These analyses are to use accident scenarios acceptable to the staff. In addition, in the statement of considerations published with the rule and in response to public comments, it was' emphasized that while measures to prevent the generation of large amunts of hydrogen are necessary and desirable, the Connission believes that It is also necessary, deptnding upon containment design, to provide measures to mitigate the effects of large amounts of hydrogen.

t 3-t The staff interprets the text of the hydrogen rule and especially the state-rent of considerations, to require a hydrogen control system for the most likely hydrogen generation events (HGEs). Thus, the importance of cost / benefit considerations is minimized for hydrogen control system features t which are essential for reliably mitigating the dominant events. Cost / benefit considerations are important for feat res which go beyond the basic requirement. The expression. use acc. dent scenarios acceptable to the staff, is interpreted to mean that the staff shall employ scenarios which are acceptable in their representation of the likely HGEs and their hydrogen generation profiles to assure safe disposal of the hydrogen. The staff does not interpret this language to imply that all scenarios may be excluded based upon probabilistic arguments and that no hydrogen control i 7 j system be prcvided for these plants. 1 1 Actinst this baclground tie staff determind which scenarios should be i adcressec for hyc* ogen control by reviewing the results of draf t NUREG-1150 as well as other M PRAs. These studies clearly indicated that the tcrinantcoredamalesecuence(ancthereforeF0Es)fortheplantsstudied (Grand Gulf, GESSAR) is station blackout. Thus it was concluded that an independent power supply should be provided for the igniter system in order to assure reliable operation during these events most likely to lead to an HOE. As part of our review regarding implementation of the degraded core I acciderot provisions of the hydrogen rule, the staff considered several options other than the near term imposition of the requirement for an i inde, ender.+. pe er supply. One was to defer the decision on a requirement i for an independent power supply until after implementation of the SB0 rule and the Severe Accident Polic (i.e., completion and evaluation of Individual Plant Examinations (IPE ). The staff rejected this approach l l since it introduced an unnecessary lengthy delay in implementation and i because SB0 will most likely remain a significant contributor to hydrogen I j generation events even after the 580 rule is fully implemented and IPE's are completed. A second approach to this issue that was considered was i to not require an independent power supply but retain the original AC l that the accidents ir question are of very low probability (10'$ grounds This option is viable on the j power igniters already installed. ) and that [ i the additional cost of modifying the system is not warranted. The staff l rejected this option simply because of its undue emphasis and reliance on absolute probability estirates whereas a comparative analysis of + 1 accidents leads the staff to conclude that SB0 is significant and should be addressed. I (vi) Identification of the category of reactor plar,ts to which the generic requirerents or staff position is to apply. f { The staff position is applicable to all Mark !!! plants (i.e., Grand riulf, Clinton, River Bend and Perry). i l l 4 J +

I. -4 It should be noted that the staff recommendation for Mark-Ill D'Ps is different from that which was reached for the Sequoyah and McGuire power stations (Ice Condenser Containment) at the time of issuance of the Hydrogen Rule. In the statement of considerations accompanying the rule, the staff accepted (for Sequoyah and McGuire) AC-powered igniters without recuiring a backup power supply. This decision was I i based on the conclusion that $30 was not a dominant sequence for l these plants and therefore an independent power supply was not essential. Cost / benefit analyses were therefore considered for the estinated to be about 6X10"ethat time the core melt prcbability was alternate power supply. At

• /ry with the station blackout component j

repretenting only about 5%. The incremental rish reduction associated ( with provisions of the igniter system backup power supply did not warrent the additional cost. l Also, as reported in the revised version of MUREG-1150, the absolute i i value of the probability for a SB0 initiated HGE in Sequoyah (ice condenser plant) is higher than the corresponding value for Grand i Culf (a Mark-111 plant). The decision to require an independent power supply for Mark 111 plarts, however, was based on SB0 being the domi-nant sequence for these plants. This is in accordance with the staff's l interpretation of the Commission's intent for the hydrogen rule. The revised NUREG-1150 results estimate a low contribution from SB0 for l Sequoyah but, nevertheless, higher than the previous estimate. The l staff will consider these new results for ice condenser plants separately, I and pursue any further actions in accordance with the Concission's backfit policy. (vii) for ead such category of reactor plants, an evaluation which demon-strates how the action should be prioritized and scheduled in light cf other ongoing regulatory activities. The evaluation shall document for consideration information available concerning any of the following factors as may be appropriate ard any other information relevant and material to the proposed action: (a) Statement of the specific objectives that the proposed action is designed to achieve; The objective is to advise the Hydrogen Control Owners Group of the acceptability of the topical report and staff's position that an independent power supply n st be an integral part of the hydrogen ignition system. (b) General description of the activity that would be required by the licensee or applicant in order to complete action; Each Mark 111 Ifeensee must submit a final analysis as required by 10CFR50.44(3)(c)(vii)O1. The HCOG topical report provides the generic experinental anu enalytical basis for each plant specific analysis. Accordingly, as part of the final analysis, the licensee should include a description of an independent power supply as part of the hydrogen ignition system design.

I. i . l (c) Pctential change in the risk to the public from the accidental offsite release of radioactive material; 6 Implementation of the staff position would result in a small reduction in the risk to the public on a best estimate basis, using NUREG-1150 results for Grand Gulf. The change would significantly improve however, containment performance by substantially reducing the conditional containment failure probability associated with S80 f induced core damage accidents. (d) Potential impact on radiological exposure of facility employees and other onsite workers. The potential impact on radiological exposure of facility workers are judged to be minimal. (t) Installation and continuing costs associated with the action, including the cost of facility downtime or the cost of construction l

delay, t

l Provision of an independent power supply for hydrogen igniters has t been estimated, by industry, to cost roughly $500,000 - $1,000,000 i per plant. Of this total cost roughly one-third represents hardware and installation costs with the remainder composed of engineering services. This estimate reflects the ccsts associated with providing a non-class IE power systen (e.g 10-15 kw generator) capable of energt:ine one division of igniters. The staff concludes that such a non-class IE system, with suitable electrical isolation design features, would be acceptable for meeting the requirement for an independent power supply. Installation of an independent power 7 supply is not expected to influence facility downtime and could be deferred to the next planned outage of sufficient duration. 1 l Alternatively, licensees may opt to resolve the issue of independent i power for igniters in conjunction with their actions to meet the i requirements of the Station Blackout rule. The staff has previously 1 noted that the preferred approach to meeting the requirements of the i Station Blackout rule is to provide an alternate AC power source. I l Therefore, a licensee ray satisfy the requirem49t for independent power for igniters by utilizing an alternate AC wwer source, if properly sized, which also meets the requirements of the Station i Blackout rule. { (f) The potential sefety impact of changes in plant or operational com-f plexity, including the relationship to proposed and existing regula-tory requirements and staff positions; [ i Based on the staff position, plant safety is not expected to be i adversely irpacted by this action. i f i 1 I )

I r (g) The estinated resource burden on the NRC associated with the propcsed ar. tion and the availability of such resources; Approval of the HCOG topical report should reduce the resources reovired of the staff to review final plant specific analysis by eliminating the need to review the methodology on each application. Approval of the generic topical report will restrict the final plant evaluations to plant specific issues. Review of licensee actions to meet the additional proposed requirement, provision of an independent power supply, should require only minimal additional staff resources that are within our current capability. This judgement refTects consideration of the fact that this review affects only four plants and that the re.'iew of the independent power source would focus on the design features for electrical isolation. On balance, the overall burou en staff resources created by this action, i.e., review of the tepical report, including implementation of the additional requirement, should be minimal. (h) The potential impact of differences in facility type, design or age on the relevancy and practicality of the proposed action; While the staff position is applicable to Mark !!! plants, this may be expanded to ice condenser plants as described above in part(vi). (1) Whether the proposed action is interim or final, and if interim, l the justification for imposing the proposed action an interim basis. This is the final staff position. ( (viii) For each evaluation conducted pursuant to 10 CFR 50.109, the proposing f office director's determination, together with the rationale for the detereination based on the considerations of paragraphs (1) through (vii)above,that (a) there is a substantial increase in the overall protection of public health and safety or the comon defense and security to be derived from the proposal; and (b) the direct and indirect costs of implementation, for the facilities affected, are justified in view of this increased protection. Not applicable ( [

...?. . (ix) For each evaluation conducted for proposed relaxations or decreases in current requirements or staff positions, the proposing office director's deterr:ination, together with the ratier. ale for the determination based on the considerations of paragraphs (1) through (vii) above, that ^ (a) the public health and safety and the common defense and security would be adequately protected if the proposed reduction in reovirements or position were implemented, i and (b) the cost savings attributed to the action would be substantial enough to justify taking the action. The SER provides the rationale to approve the HCOG's topical report r which is used to f acilitate the implementation of existing requirenents [10CFR50.44(c)(3)(iv)(A)). If the staff position is implemented, the public health and safety and the comon defense and security would be adequately protected. Furthermore, the topical report acceptance will be cost effective to NRC resources. l . g. [ f r i t i l f f l i ( I i -}}