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Forwards Response to NRC 791025 Request Re Design Adequacy of B&W NSSS Utilizing once-through Steam Generators. Necessary Mods Do Not Require Const Halt
	ML19210E292
Person / Time
Site:	Midland
Issue date:	11/30/1979
From:	Howell S; CONSUMERS ENERGY CO. (FORMERLY CONSUMERS POWER CO.)
To:	Harold Denton; Office of Nuclear Reactor Regulation
References
	HOWE-306-79, NUDOCS 7912040286
	Download: ML19210E292 (141)
	v • d • e

{{#Wiki_filter:. Stephen H. Howell Sensor Vice President General Offices: 1945 West Parnali Road, Jackson, Michigan 49201 e (517) 788-0453 November 30, 1979 Howe-306-79 US Nuclear Regulatory Co= mission Attn: Mr Harold R Denton Office of Naclear Reactor Regulation Washington, DC 20555 MIDLAND PROJECT DOCKET No 50-329, 50-330 RESPONSE TO 10CFR50 54 REQUEST ON DESIGN ADEQUACY OF B&W SYSTEMS FILE: 0485.19 SERIAL: 7999 Enclosed are ten (10) copies of Consumers Power Company's response to your 10CFR50.54(f) request dated October 25, 1979 regarding the Design Adequacy of Babcock & Wilcox Nuclear Steam Supply Systems Utilizing Once Through Steam Generators for Midland Unit 1 and 2. The attached response consists of Appendix A through F which correspond to your questions a through f. Appendixes A and B represent the B&W analysis input on overcooling events. Due to time constraints and our desire to meet your schedule, Consumers Power Company has not completed a detailed technical review of this caterial. Certain obvious modifications to cover the specific design details of the Midland Plant have been made. If our review uncoverc additional changes, we will notiff your staff and provide a revised report. Consumers Power Company has studied the concern of sensitivity of the reactor coolant temperature and volume to perturbations in the-secondarf system and has concluded that there are steps that can and vill be taken to reduce these secondar/ perturbations and to address the concern 'for sensitivity. The discussion of plant changes is presented in Appendix F. It should be noted that these modificaticns do not involve major changes to large pieces of equip-ment such as vessels, heat exchangers or pumps. Considering the magnitude of changes and for the reasons presented in Appendixes C and D, Consumers Power Ccmpany believes that installation of the-affected systems can and should continue and that necessary modifications can.be accommodated during continued construction. Hence, we believe there is no benefit in halting all or parts of construction of the Midland Plant Unit 1 and 2. 147) 2431b 7912040 4

2 Consumers Power Company Dated: November 30, 1979 3 M hC Stephen 4 }owell, Senior Vice President Sworn and subscribed to before me on this 30th day of November 1979 YW. Y Y M--Y Notary Publiep Jackson County, Michigan My commission expires September 21, 1982 1471 244

RESPONSE TO 10 CFR 50.54(f) APPENDIXES A AND B Quest io ns a. Identify the most severe overcooling events (considering both anticipated transients and accidents) which could occur at your facility. These should be the events which cause the greatest inventory shrinkage. Under the guidelines that no operator action occurs before 10 minutes and only safe ty systems can be used to mitigate the event, each licensee should show that the core remains adequately cooled. b. Identify whether action of the ECCS or RPS (or operator action) is necessary to protect the core following the most severe overcooling transient identified. If these systems are required, you should show that its design criterion for the number of actuation cycles is adequate, considering arrival rates for excessive cooling transients.

Response

I. INTRODUCTION AND CONCLUSIONS A.

Background

On October 25, 1979, the NRC issued a letter to utilities holding construction permits for B&W NSSSs. The utilities were requested to assess overcooling events on their plants, accounting for balance-of-plant features. B. Scope This report responds to the specific NRC requests identified above. More than one transient type is analyzed to address different frequency of occurrence classifications and to ensure that the most severe cases are indeed included in the evaluation. A qualitative assessment of possible nonmitigative operator actions in the 0 to 10-minute time f rame is also provided. This assessment provides indication of what operator action is anticipated durin3 the initial phases of an overcooling transient. The analyses identify the frequency of the RPS, ES F AS, and operator action for mitigation of the transient. A summary of the results is given in Section II. Section III provides the details of the initial conditions, computer codes, and basic assumptions used in the analysis. The transient response data are given 1471 245 A&B-1 11/79

RESPONSE TO 10 CFR 50.54(f) APPENDIXES A AND B in Section IV. Section V demonstrates the adequacy of the design criteria for each system. C. Conclusions Based on the analyses performed in this report, the following conclusions can be drawn. 1. The overcooling accident (main steam line break) and the overcooling transient (main feedwater overfill) analyzed herein retain adequate core cooling even when analyzed with no operator action before 10 minutes and with only safety systems used to mitigate the event. 2. RPS and ECCS actuation are required to mitigate the most severe overcooling transients.

However, operating data imply that the arrival rate of transients requiring RPS or ECCS actuation is within the design basis.

It should be noted that this report could not-exhaustively determine the most severe overcooling transient in the allotted time; the reasons for selecting main feedwater overfill are discussed in Section IV.A.l. D. Applicability of Results The results presented in this report are applicable specifically to this NSS with the parameters tabulated in Section III. Specific attention has been paid to the balance-of-plant equipment in the mitigative functions performed. II.

SUMMARY

This section provides a detailed summary including identification of the safety concern and basis for selection of the transients to resolve the concern and principal results of the analysis. By reviewing this section, which is supported by the details given in Sections III, IV, and V, a concise overview can be obtained of the completed resolution of this concern. Section II. A addrescas the selection of anticipated transient and accident conditions causing greatest core shrinkage, and Section II.B discusses the phenomenon of void formation under inventory shrinkage conditions. Section II.C summarizes the analyses. Section II.D summarizes Section V, demonstrating 1471 246 A&B-2 11/79

RESPONSE TO 10 CFR 50.54(f) APPENDIXES A AND B that the design criteria for the number of actuation cycles of the RPS and ESFAS are adequate. A. Limiting Overcooling Event Confirmation Maximum RCS coolant inventory shrinkage esults from a decrease in the pressure and temperature of the coolant at a maximum rate, without a compensating coolant makeup addition. The double-ended steam line break (SLB) provides maximum cooldown rates and is analyzed in Section IV.B as the limiting accident. Several sensitivities and differing conditions were analyzed to provide greater insight into the steam void formation and collapse which would occur and its subsequent effect on core cooling. These additional studies were performed on the SLB because this accident was expected to result in RCS voiding. However, it will be shown that the limiting moderate-frequency event analyzed does not produce voiding as a result of RCS coolant inventory shrinkage. In selecting the limiting anticipated transient, SAR and operating plant overcooling events were reviewed. The most severe moderate-frequency event in the SAR is the steam pressure regulator malfunction. Review of plant transient data ( see Sec tion IV. A.1) has shown that overfeed by main feedwater af ter reactor trip has prod uced the most severe overcooling transients. Therefore, based on arrival rates for operating plants and the coolaown rate associated with this transient, main feedwater overfeed following a reactor trip / turbine trip is considered the limiting anticipated transient and is analyzed in Section IV.A. B. Shrinkage Effects Shrinkage of the RCS coolant liquid volume occurs as temperature decreases during an overcooling event. The pressurizer volume of 1,500 cubic feet contains 800 cubic feet of saturated water during normal opera t io n. This liquid volume flows out of the pressurizer into the system as the system inventory volume decreases. If the RCS coolant inventory volume decrease is greater than 800 cubic feet and continues to decrease, the pressuricer steam space can be transferred into the RCS. This type of steam voiding is limited by the inventory volume dif ference between hot, full power, and the final cressure/ temperature achieved during the transient. Itc effect is further mitigated by actuation of the emergency core cooling system (ECCS). 1471 247 A& B-3 11/79

RESPONSE TO 10 CFR 50.54( f) APPENDIXES A AND B The other mechanism which produces steam voids in the RCS is flashing of RCS water. As the pressure rapidi-j decreases in the RCS, the liquid in the hotter portions of the system can become saturated by the hot metal in this area, flashing additional water to steam. This process, in a non-LOCA situation, is self-regulating. As the steam separates, or additional flashing occurs, the pressure decrease in the system lessens as the overcooling continues. The steam void formation is then reduced and the steam void will tend to collapse as a subcooled state is again established. Examination of the SLB analysis indicates that a small amount of steam formation occurs in the upper hot leg region prior to the pressurizer emptying, occurring almost exclusively on the side with the affected steam generator. If the affected steam generator is on the loop with the pressurizer, emptying the pressurizer contributes to the steam void formation. If the af fected steam generator is on the opposite loop f rom the pressurizer, emptying the pressurizer has little effect on the steam voids on that side and they are quickly quenched. Therefore, the limiting accident, in terms of void vclume formation, occurs for the SLB in the same loop that has the pressurizer. C. Adequacy of Core Cooling In this section, the results presented in Section IV are summarized and analyzed for determination of adequate core cooling. The anticipated transient analyzed is the overfeed of the steam generators by main feedwater ( Section IV. A). This overcooling transient, with no mitigative operator action for 10 minutes, resulted in the pressurizer emptying briefly. However, HPI actuation is sufficient to prevent any steam voiding in the RCS. The design basis steamline break accident (Section IV.B) produces steam voiding in he upper hot leg regions of t the RCS. Severr.1 sensitivity studies were performed to assess impact on steam void formation and subsequent core cooling flow. The sensitivity studies incl ud ed the following: 1. Varying the time of loss-of-offsite power (LOOP) from time of trip to time of ESPAS 2. With and without core decay heat 1471 248 A&B-4 11/79

RESPONSE TO 10 CFR 50.54(f) APPENDIXES A AND B 3. Single-failure assumptions of stuck-open relief valve on unaffected steam generator sr loss of one HPI pump 4. Moving the break from the steam generator with the pressurizer in its loop to the side without the pressurizer In all analyzed cases, core flow continued. The core region remained subcooled thro ug hout the transient for all cases analyzed. The remainder of the SLB cases presented presented in Section IV.B all satisfy this criterion. Mitigative operator action was not assumed in the analysis in the first 10 minutes. From a review of potential operator actions during this time, it is concluded that only two actions are of major importance. Operator control of the steam generator level would have reduced the extent of RCS inventory shrinkage for both MFW overfeed and SLB transients. A nonmitigative operator action would result from the premature cutoff of the HPI flow. Adequate indications are available to the operator during steam voiding situations that would exist during the SLB accident analyzed to ensure the continuation of HPI flow. Pressurizer level and subcooled margin both indicate the necessity of HPI. Ad equa te core cooling would necessitate that HPI be available at some point during overcooling transients. D. Adequacy of Core Protective Measures Section V provides the details of the design basis for operating transient cycles. Operating plant data have shown the 40 cycles of actuation of HPI to be a sufficient design basis to cover automatic initiation arrival ra tes for this system. The analysis presented in Section IV confirms that the most severe overcooling events require ECCS actuation. The operating plant data show that ESFAS automatic actuations occur less than once per year; therefore, 40 cycles per lifetime is an adequate design for transients not expected to occur greater than 40 times in the life of the plant. III. ANALYTICAL TECHNIQUES A. Computer Codes The B&W-certified computer code TRAP 2 (Reference 1) has been used in the analyses presented in the following sections. Computer Code 2 is a nodal type, digital simulation (similar to CRAFT, Reference 2), and is capable of handling rapid overcooling transients that A& B-5 11/79 1471 249

RESPONSE TO 10 CFR 50. 54 ( f) APPENDIXES A AND B may result in two-phase fluid conditions in the reactor coolant system. The noding flowpath networks used in the TRAP 2 analysis of the plant are given in Figures A&B-1 and A&B-2. A description of each node and the improtant flowpaths are given in Tables A&B-1 and A&B-2. The more detailed nod ing shown in Figure A& B-1 (description in Table A&B-1) is referred to as maxi-TRAP. The less detailed model in Figure A&B-2 (description in Table A&B-2) is referred to as mini-RAP. The more detailed maxi-TRAP model is used during the initial phase of the transient while the primary and secondary variables are rapidly changing. In the interest of computer calculational timesaving, the mini-TRAP model is used in the long-term solutien where system variables are more slowly varying and the additional noding is not required. B. Transient Selec tion The types of overcooling events considered include those which consititute the initiating event, those which result from single failures following any initiating event, and those which are made more severe from single failures following the initiating overcooling event. The specific systems whose malfunction or failure are considered either as initiating events or sir.gle failures which enhance overcooling are: 1. Feedwater heater failure which causes a decrease in feedwater temperature 2. Feedwater flow control malfunction which causes an increase in feedwater flow 3. Steam pressure regulator malfunction which causes increased steam flow 4. Inadvertent opening or stuck-open steam relief valve which causes increased steam flow and/or depressurization of a steam generator 5. Steam system piping failure which causes excessive steam flow and depressurization of a steam generator The 3AR anal.yses are referred to in order to narrow the most severe type of overccoling events for consideration. Specifically, these includ e : 1471 250 A&B-6 11/79

RESPONSE TO 10 CFR 50.54(f) APPENDIXES A AND B 1. Events which constitute an initiating event - Items 1 through 4 above are moderate frequency, and steam regulator malfunction is the most limiting according to the SAP analyses. Item 5 is a design basis event for which the double-ended rupture (DER) MSLB is limiting. 2. Events which result from single failure following any initiating event - This infrequent occurence is a combination of a moderate frequency event plus one of Items 1 through 4 occurring as a single failure. The event chosen to be analyzed in this category is an immediate reactor trip on turbine trip signal (decrease the heat source) combined with a feedwater flow control malfunction that allows continued main feedwater flow (increase the heat sink). 3. Events which are more severe from single failures following the initiating overcooling event - The limiting design basis overcooling transient is a double-ended SLB. The single failure chosen to maximize continued long-term coolir:g is a stuck-open relief valve on the unaffected steam generator. The limiting or potentially limiting overcooling cases to be analyzed as discussed above are summarized in Table A&B-3. C. Basic Assumptions Key input parameters used in the plant analysis are given in Table A&B-4. These values represent as-built information, realistic se tpoints, actuation times, flowrates, and valve closures. Other system parameters not listed are those applicable to the plant design. The assumption of a stuck rod was removed from the shutdown rod worth, resulting in a more realistic, conservative direction for the overcooling type events concerned with maximum RCS coolant shrinkage. Single failures of active components assumed in the analysis are given in Table A&B-3. Some parameterization of the single-f ailure assumption is done for the limiting overcooling case. Because only safety grade equipment is assumed to function, the single failures of mitigative equipment are limited. Table A&B-5 lists the equipment assumed to function for each transient analyzed. 1471 251 A&B-7 11/79

RESPONSE TO 10 CFR 50.54(f) APPENDIXES A AND B No mitigative operator action is assumed for 10 minutes in the analysis. IV. RESULTS OF CORE COOLING STUDIES A. Anticipated Transients 1. Scope of Evaluation The anticipated transients analyzed in the S ARs were reviewed for cooldown rates and consequences in order to select the most limiting case for shrinkage. Operating plant data were also reviewed. For this review, the transient with the highest frequency of occurrence and the potential for greatest overcooling was due to malfunctions resulting in overfeed of the steam generators by main feedwater. Operating plant data show that overcooling of the RCS has occurred from primarily two types of events: failure of a relief valve to reseat at the proper pressure, which limits the overcooling to the saturation temperature uf the pressure at which the valve does reseat; and overfeed of the steam generators following a reactor trip, which has caused the greatest primary cooldown observed. Steam pressure regulator malfunctions that allow increased steam flow would represent overcooling by depressurizing the secondary system. Its effect is very similar to a small SLB analysis. The arrival rate for this transient has been zero at operating B&W plants. Therefore, in the limited time f rame for the preparation of this report, the Mai overfeed transient is presented. The MRi overfeed represents the maximum cooling that can be achieved by feeding the OTSGs. 2. Main Feedwater Overfeed Analysis The initiating event is a turbine trip with simultaneous reactor trip and a control failure such that main feedwater continues to feed both steam generators at full capacity. The sequence of events for this transient is given in Table A&B-6. The analysis was performed using the models and assumptions given in Section III. comparison of the maxi-TRAP and mini-TRAP system parameters is shown in Figures A&B-3 to A&B-5 for the first 2 miuntes of the transient. Based on the relatively good agreement of these results, the A& B-8 47j }g} 11/79

RESPONSE TO 10 CFR 50.54(f) APPENDIXES A AND B mini-TRAP run was extended to 10 minutes. No credit for ICS and operator actions was assumed. For this analysis, it was assumed that only safety grade equipment functioned. Because the ESFAS signal on low RC pressure does not directly actuate AFW, the steam generators must boil down to the low level actuation setpoint to initiate flow. AB1 actuation would also occur when the main feed pumps are tripped due to actuation of a main steam line isolation signal (MSLIS) upon ESFAS actuation. However, AFW injection would not occur until the OTSG level setpoint was reached, which would be after the 10-minute time period encompassed by this analysis. Therefore, actuation of AR1 at an earlier time would not increase the severity of the overcooling transient. Figures A&B-6 through A&B-13 present system parameters. For this transient, the pressurizer empties briefly at about 3 minutes.

However, during the 30- to 50-second duration before HPI starts to increase RCS inventory and refill the pressurizer, no steam void formation occurred in the RCS.

The cooldown rate (i.e., RCS coolant inventory shrinkage) was not large enough to overcome the subcooled state of the RCS coolant inventory or the HPI flowrate. From the system response observed, two probable operator actions during the course of the transient are suggested. First, operator action would be needed to terminate the OTSG overfill by main feedwater early in the transient, which would stop the overcooling of the RCS. Also, because sufficient subcooled margin exists throughout most of the transient, the operator would regulate HPI flow to maintain pressurizer inventory.

However, this particular action is not required for the first 10 minutes of the transient.

3. Conclusions The RCS coolant inventory remained subcooled through the transient, thus ensuring adequate core cooling. The pressurizer emptying was brief (less than 50 seconds) in duration before HPI actuation started refilling the system. Only additional failures, such as bypass or relief valves stuck open, could increase the cooldown rate experienced during the transient. ESFAS terminates the excessive feedwater flow. With the fill rates of A& B-9 11/79 1471 253

RESPONSE TO 10 CFR 50. 54( f) APPENDIXES A AND B main feedwater assumed, the steam generators will overfill in approximately 90 seconds. The reactor coolant pumps running case represents the maximum cooling rate. Therefore, no voiding for this case ensures that the reactor coolant pump trip case, which would reduce the cooldown rate, also would not produce voids in the reactor coolant system. B. Accid en ts 1. Scope of Evaluation Maximum overcooling of the RCS results from an uncontrolled blowdown of the secondary plant (i.e., SLB accident). The double-ended rupture from full power has been demonstrated in the SAR to result in maximum overcooling. Selection of the worst coolant inventory shrinkage case for this event has been studied by analyzing a spectrum of different co nd it io ns. Table A&B-7 shows the various conditions and identifies these different analyses by case number for further reference in the discussion of results provided in the following sections. 2. SLB Analysis A double-ended guillotine break is assumed to occur in the 33.5-inch inside diameter steam line. The location of the break is outside of the reactor building. This analysis assumed that the safety grade AFW level control system did not function and that overcooling was maximized by continuous AR1 injection at its design flowrate. Other system parameters, models, and assumptions are as presented in Section III. The sequence of events is given in Tables A&B-8 through A&B-15 for each case analyzed. The figures for each case are listed on the table for that case. The figures for Case 1, reactor coolant pumps running, also include a comparison of maxi-TRAP and mini-TRAP results, showing reasonably good agreement between the two models. Subsequent SLB analyses were performed using the mini-TRAr - 'sl. The SLB accident was analyzed for 10 minutes assuming no mitigative operator action and only safety grade equipment for transient mitigation. The overcooling rate, as anticipated, is much }k7\\ 11/79 A&B-10

RESPONSE TO 10 CFR 50.54(f) APPENDIXES A AND B higher for the SLB cases than that obtained for the MFW overfeed case presented in the previous section. The case resulting in the most severe consequences of RCS shrinkage occurs with LOOP at the time of ESF AS actuation. The assumption of no decay heat agg ravates this shrinkage ef fect. A bubble rise velocity of 5 feet per second was used in the hot leg piping nodes. It is important to note that the void formation data presented include entrained, as well as separated, bubble mass. Therefore, with reactor coolant pumps running and during the start of flow coastdown, the bubble mass will be almost totally entrained. Comparing the single-failure assumption of a stuck-open relief valve on the unaffected steam generator versus failure of one HPI pump, the stuck-open relief valve (Case 4) results in the maximum steady' steam void formation. However, for the one HPI failure (Case 7), the steam void remains in the RCS longer. The maximum steam void occurs in the hot leg attached to the pressurizer and is about 320 cubic feet for the cases analyzed. The first steam void formation that appears during the SLB accident is due to flashing (i.e., reaching saturation) in both hot legs. This occurs prior to the pressurizer emptying. On the loop side opposite the pressurizer and analyzed with the una f f e cted steam generator, this effect is small and returns to a solid, subcooled state about the time the pressurizer empties. On the loop with the pressurizer and the affected steam generator, this steam void continues to increase as the pressurizer empties. ESFAS initiation also occurs at approximately this time and HPI injection, as well as isolation of the affected steam genarator main steam and feedwater, tend to limit the size of the steam void formed. HPI flow is sufficient to overcome the shrinkage that is still occurring from the heat removal through auxiliary feedwater to the unaf fected steam generator. As refill and repressurization of the RCS continue by the HPI, the steam void is quenched and collapsed. Core flow is maintained throughout the transient. During LOOP cases, natural circulation is maintained by the cooling from the unaffected steam generator side of the RCS. If no credit is taken for the safety grade AFW 1evel control system, the unaffected steam A&B-11 1471 255 11/79

RESPONSE TO 10 CFR 50.34(f) APPENDIXES A AND B generator fills in 6 to 7 minutes. The pressurizer is filling, but has not completely filled in the first 10 minutes of the accident. Thus, adequate time is available for operator action to prevent pressurizer overfill. Taking credit for the safety grade level control system on the unaffected steam generator would allow earlier repressurization of the RCS, thereby leading to earlier collapse of the void. C. Conclusions Steam void formation in the upper hot leg regions was found to occur during the steam line break accident. The magnitude and duration of the steam void formation varied with the conditions under which the analysis was performed. In all cases, core flow was maintained and the core remained subcooled. Some of the specific phenomena noted for the various cases analyzed are as follows: 1. The LOOP assumption at ESPAS produces slightly worse consequences than at an earlier time. This is because the pumps running maximize the overcooling such that the later the LOOP (up to ESFAS), the more shrinkage tnat has occurred. LOOP after ESFAS should not continue to increase the severity, because isolation of the affected steam generator main feedwater supply occurs at ESFAS and greatly reduces the evercooling rate. 2. The assumption of no decay heat aggravates the steam voiding situation However, as decay heat level decreases, the need for additional core flow decreases. In the extreme, no decay heat implies no core cooling is necessary. 3. Single failure of a relief valve on the unaffected steam generator to maximize cooling rate and a single failure of one HPI pump to mrximize the refill repressurization effects were examined. The larger magnitude of steam void occurred for the stuck-open relief valve case, whereas the steam void formation was of longer duration for the HPI failure case. 4. The void formation in a given loop was large enough to create temporary flow blockage in that loop. However, the net core flow remains positive throughout the transient, and is never interrupted to the point that saturation occurs in the core reg ion. 1471 256 A&B-12 11/79

RESPONSE TO 10 CFR 50.54(f) APPENDIXES A AND B No mitigative operator action was assumed for 10 minutes in the analysis. With the fill rates of auxiliary feedwater assumed, the unaffected steam generator will overfill in 6 to 7 minutes if credit for the safety grade AFW level control system is not taken. Core cooling appears adequate for all cases analyzed because subcooled conditions are maintained in the core region. V. DESIGN BASIS FOR CORE PROTECTION Required ECCS and RPS actions necessary to protect the core have been summarized in Table A&B-5 and discussed in more detail for each transient in Section IV. No operator action has been assumed within 10 minutes for mitigation in the analysis. This section demonstrates that the design criteria for the number of actuation cycles are adequate. Twenty-five different types of transient cycles (several are SAR analyses) are used in evaluating the acceptable number of design cycles. These operating transients are listed in Table A&B-16, along with the number of design cycles for each transient type. These data are the basis on which the stress evaluation i performed for the plant and will be contained in the technical specifications for the plant. The number of cycles for transient types listed in Table A& B-16 is not meant to be an absolute limit, but was chosen on the basis of expected frequency (plus margin) and is shown to be acceptable in the stress evaluation. Special transient analyses can be performed based on any actual transient data, thereby allowing categorization of the special case into one of the allowable transient design cycles. The adequacy of the number of design cycles can be inferred f rom operating plant data. Table A&B-17 compares the actual arrival rate for RPS and ESPAS actuation to date on plants of B&W design to the rates allowed by the design basis (Table A& B-16). The operating data are less than the allowable actuation rate for both systems, thereby supporting the adequacy of design. 1471 257 A&B-13 11/79

REEPONSE TO 10 CFR 50.54 (f) APPEMDIXES A AND E VI. REFERENCES 1. J.J.

Cudlin, P.W.

Dagett, TRAP 2-FORTRAN Program for Digital Simulation of the Transient Behnvlor of the Once-Through Steam Generator and Associated C331 ant System, BAW-10128 (August 1976), Babcock & Wilcox, Lynchburg, Virginia 2. R. A. Hedrick, J.J. Cudlin, and R.C.

Foltz, CRAFT 2-FORTRAN Program for Digital Simulation of a Multinode Reactor Plant During Lo5s of Coolant, BAW-10092, Revision 2 (April 1975), Babcock & Wilcox, Lynchburg, Virginia 147i 258 A&B-14

RESPONSE TO 10 CFR 50.54(f) TABLE A&B-1 MAXI-TRAP NODE AND PATH DESCRIPTION Description Node Number i 1 Reactor Vessel Lower Plenum 2 Core, Upper Plenum and Outlet Nozzles 3, 16 Hot Leg Piping 4-13, 17-26 Primary, Steam Generatcr 14, 27 Cold Leg Piping 15 Reactor Vessel Downcomer 28, 55, 56 Pressurizer 29 Containment 30-39, 40-49 Secondary, Steam Generator 50, 51 Steam Risers 53, 54, 68, 69 Steam Generator Downcomer 64, 66 Feedwater Piping 63 Turbine and Process Steam Plant 65, 67 Feedwater Piping and Feedwater Heater 52, 57-62 Steam Piping 1471 259 A&B-15

RESPONSE TO 10 CFR 50.54(f) TABLE A&B-1 (Cont'd) Flow Path flumber Description 1 Core 2 Core Bypass 3, 4, 17, 18 Hot Leg Piping 5-13, 19-27 Primary, Steam Generator 14, 28 RC Pumps 15, 29 Cold Leg Piping 16 Reactor Vessel Downcomer 30 Pressurizer Surge Line 31-39, 41-49 Secondary, Steam Generator 40, 50 Steam Riser 51, 52, 56, 69, 70, 71 26 Inch Steam Piping 53, 58 Aspirator 54, 55, 85, 86 Steam Generator Downcomer 59-62 Pressurizer 63, 66 Feedwater Pumps 64, 65, 67, 68 Feedwater Piping 72 36 Inch Steam Piping 73, 76 MSIV 74, 75, 77, 78 Process Steam and Turbine Piping 79 Feedwater Piping Crossover 80 Steam Piping Crossover 57, 84 Break 83 Aux. Feedwater }47l C 81 HPI 82 LPI (Not Used) A&B-16

RESPONSE TO 10 CFR 50.54(f) 1 i TABLE A&B-2 MIfil-TRAP fl0DE AtlD PATH DESCRIPTIO:1 Node flumber Description 1 Reactor Vessel, Lower Plenum 2 Reactor Vessel, Core 3 Reactor Vessel, Upper Plenum 4, 10 Hot Leg Piping (including " Candy Cane") 32, 33 " Candy Cane" and Upper S.G. Shroud 5-7, 11-13 Primary, Steam Generator Tube Region 8, 14 Cold Leg Piping 9 Reactor Vessel Downcomer 15 Pressurizer 16, 24 Steam Generator Downcomer 17, 25 Steam Generator Lower Plenum 18-20, 26-28 Secondary, Steam Generator Tube Region 21, 29 Steam Risers 22, 30 Main Steam Piping 23 Turbine 31 Containment Path Number Description 1 Core 2 Core Bypass 3 Upper Plenum, Reactor Vessel 4, 11 Hot Leg Piping 5, 12 Upper Steam Generator Shroud 45, 46, 47, 48 Top of Hot Leg " Candy Cane" 6, 7, 13, 14 P.imary Heat Transfer Region, S.G. 8, 15 RC Pumps 9, 16 Cold Leg Piping 10 Downcomer, Reactor Vessel 17 Pressurizer Surge Line 18, 19, 26, 27 Steam Generator Downcomer and Plenum 20, 21, 28, 29 Secondary Heat Transfer Region, S.G. 22, 30 Aspirator 23, 31 Steam R1ser, Steam Generator 24, 32 Main Steam Piping 25, 33 Turbine Piping 34 Steam Crossover 36, 37 HPI 38, 39, 43, 44 AFW 40, 41 Main feed Pumps 42 LPI 49 Stuck Open Relief Valve 35, 50 Leak Paths 1471 261 A&B-5 A&B-17

TABLE A&B-3

SUMMARY

OF EVENTS ANALYZED Initiating Event Single Failure Sensitivity Studies A. Anti <cipated Event Made More en Severe By Single Failure Di Reactor Trip / Turbine Trip Main Feedwater Overfeed M 5 B. Design Basis Overcooling -m Double Ended Steam Line Main Steam Relief Valve Stuck e LOOP at Reactor Trip Break Open e LOOP at Low RC Pressure ESFAS Trip E e Decay lleat g e HPI Single Failure e Steam Generator Level Control e Break on Different OTSGs P --J s N (7 N

RESPONSE TO 10 CFR 50.54(f) OVERC00LitlG Af1ALYSIS If1PUT ASSUMPTI0f15 TABLE A&B-4 Parameter 177 FA Power Level 102% T 579

ave, RCS Operating Pressure (at Pressurizer tap),

psig 2155 Pressurizer Level (indicated), in. 180 RPS Trip S.ignals High Flux, % FP 105.5 Low Pressure (core outlet), psig 1855 LSFAS Trip Setpoints Low RC Press., psig 1500 Low SG Press., psig 585 ESFAS Trip Delay, sec. 2.5 MSIV Closure Time, sec. 5 MSIV Closure Time (linear ramped area), sec. 15 Auxiliary Feedwater Design Capacity ~~~' Turbine, gpm 885 Motor, gpm 885 Temperature, OF 4C Initiation Time After ESFAS, sec. With Offsite Power 15 With Loss of Offsite Power 40 Main Feedwater Tempera'ture, UF 430 HPI System Design Capacity per Pump, gpm 2 pumps @ 500 each Temperature, F 40 Boron Concentration, ppm 2270 Initiation Time After ESFAS, sec. With Offsite Power 25 With Loss of Offsite Power 30 1471 763 OTSG Outlet Pressure, psig 910 ~ A&B-19

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RESPONSE TO 10 CFR 50. 54 ( f) TABLE AaB-6 !!Alti FEEDWATER OVERTE1:D SI:Ol'E::CE OF EVENTS EVENTS TIME (SEC,) Turbine Trip 0.0 Turbine Stop Valvec Close 0.0 Reactor Trip 0.4 Turbine Bypass Valves Open 3.0 Atmospheric Dump Valves Open 4.0 ' Pressurizer Empty 170.0 Low RC Pressure ESFAS 188.4 FSIV's Close 200.9 IEWIV's Close 203.4 HPI Actuation 218.4 Pressurizer Starts to Fill 220.0 (Refer Figures A&B-3 to A&B-13) 147) 2c5 d A&B-21

TABLE A&B-7 SLB SEflStTIVITY STUDIES RC pumps LOOP at LOOP at LOOP at ESTAS, Steam line break running reactor trip ESEAS with no decay heat With stuck open relief valve on un-Case 1(*} Case 2 Case 3 Case 4 affected generator, 2 I!PI pumps available (b) Casc With failure of one llPI pump, no case 5 Case 6 o g(c) stuck open relief valve m 8z tn ITJ g (a) Maxi-/. Mini-TRAP ccmparison presented for this case. O (b)The SLB occurs in the LOOP with the pressurizer. to o i" (c)The SLB occurs in the opposite LOOP from the pressurizer. o ] o N

RESPONSE TO 10 CPR 50.54(f) TABLE A&B-8 DOUBLE ENDED STEAM LINE BREAK CASE 1 - NO LOOP SEQUENCE OF EVENTS EVENT TIME, s Double Ended Rupture of 33.5" ID Steam Line Betucen SG and MSIV 0.0 Closure of Turbine Stop Valves 0.00 Reach Low RC Pressure Setpoint 1.5 Control Rod Insertion Starts 2.2 Reach Low Steam Pressure ESFAS Setpoint 1.9 Low RC Pressure ESFAS 5.8 MSIV's Closed 9.4 MFWIV's Closed 16.9 Unisolated SG Dry Out 20.0 Pressurizer Empty 15.0 Auxiliary Feeduater Initiation to Good SG 26.9 HPI Injection Starts 30.8 215.0 Pressurizer Starts to Fill Up SG Tube Region Full of liquid 430.0 (Refer Figures A&B-14 to A&B-25) O 1471 267 e A&B-23

RESPONSE TO 10 CFR 50.54(f) TABLE A&B-9 DOUBLE ENDED STEAM LINE BREAK CASE 2 - LOOP AT TRIP SEQUENCE OF EVENTS EVENT TIME, s Double Ended Rupture of 33.5" ID Steam Line Between SG and MSIV

0. 0 Closure of Turbine Stop Valves 0.00 Reach Low RC Pressure Setpoint + LOOP Initiation 1.5 Control Rod Insertion Starts 2,2 Reach Low Steam Pressure ESFAS Setpoint 1,8 Low RC Pressure ESFAS 7.0 MSIV's Closed 9.3 MFWIV's Closed 16.8 Pressuri::er Empty 18.0 Unisolated SG Dry Out 20.0 HPI Injection Starts 37.0 Auxiliary Feedwater Initiation 59.4 Pressurf::cr Starts to Fill Up 50.0 SG Tube Region Full of Liquid 38'i,0 (Refer Figures A&B-26 to A&B-34) 1471 2b8 A&B-24

RESPONSE TO 10 CFR 50.54(f) TABLE A&B-10 DOUBLE ENDED STEMi LINE BREAK CASE 3 - LOOP AT ESFAS SEQUENCE OF EVENTS . EVENT TIME, s Double Ended Rupture of 33.5" ID Steam Line Between SG and MSIV 0.0 Closure of Turbine Stop Valves.

0. 0 Reach Low RC Pressure Setpoint 1.5 Control Rod Insertion Starts 2.2 Reach Low Steam Pressure ESFAS Setpoint 1.9 Low RC Pressure ESFAS + LOOP Event Initiation 5.8 MSIV's Closed 9.4 MFlIIV's Closed 16.9 Pressurizer Empty 17.0 Unisolated SG Dry Out 18.0 HPI Inj ection Starts 35.8 Auxiliary Feedwater Initiation 55.5

'Pressuriser Starts to Fill Up 80.0 SG Tube Region Full of Liquid 380.0 (Refer Figures A&B-35 to A&B-43) 1471 269 A&B-25

RESPONSE TO 10 CFR 50.54(f) TABLE A&B-ll DOUBLE ENDED STEAM LI:!E BREAK CASE 4 - LOOP AT ESFAS, NO DECAY IIEAT e SEQUENCE OF EVENTS EVENT TIME, s Double Ended Rupture of 33.5".ID Stea: Line Ectueen SG and MSIV 0.0 Closure of Turbi..e Stop Valves 0.0 Reach Low RC Pressure Setpoint 1.5 Control Rod Insertion Starts 2.2 Reach Low Steant Pressure ESFAS Sctpoint 1.9 Low RC Pressure ESFAS + LOOP Event Initiation 5.8 MSIV's Closed 9.4 liFWIV's Closed 16.9 Pressuriner E=pty 17.0 Unisolated SG Dry Out 20.0 35.8 IIPI Injection Starts Auxiliary Feedwater Initiation to Good SG 55.5 Pressuriner Starts to Fill Up 330.0 SG Tube Region Full of Liquid 380.0 (Refer Figures A&B-44 to A&B-52) 8 \\$ \\ 2 O 4 A&B-26

RESPONSE TO 10 CFR 50.54(f) TABLE A&B-12 DOUBLE ENDED STEN! LINE EREAK CASE 5 - LOOP AT TRIP, 1&I FAILURE, NO STUCK RELIEF VALVE SEQUENCE OF EVENTS EVENT TIME, s Double Ended Rupture of 33.5" ID Steam Line Between SG and MSIV

0. 0 Closure of Turbine Stop Valves 0.0 Reach Low RC Pressure Sctpoint + LOOP Event Initiation 1.5 Control Rod Insertion Starts 2.2 Reach Low Steam Pressure ESFAS Setpoint 1.8 I

Low RC Pressure ESFAS 7.0 MSIV's Closed 9.3 MFWIV's Closed 1G.8 Pressurizer.Enpty 18.0 Unisolated SG Dry Out 22.0 HPI Inj ection Starts 37.0 Auxiliary Feedwater Initiation to Good SG 57.0 SG Tube Region Full of Liquid 310.0 Pressurizer Starts to Fill Up 430.0 (Refer Figures A&B-53 to A&B-61) \\41\\ L A&B-27

RESPONSE TO 10 CFR 50.54(f) TABLE A&B-13 DOUBLE E"DED STEAM LINE BRE/' CASE 6 - LOOP AT ESFAS, ITI FAILURE, NO STUCK OPEN RELIEF VALVE EVENT ' TIME, s Double Ended Jupture of 33.5" ID Steam Line Between SG and MSIV

0. 0 Closure of Turbine Stop Valves 0.0 Reach Low RC Picssure Setpoint 1.5 Control Rod Insertion Starts

2. 2 Reach Low Steam Pressure ESFAS Setpoint 1.9 Low RC Pressure ESFAS + LOOP Event Initiation 5.8 MSIV's Closed 9.4 MFRIV's Closed 16.9 Pressurizer Empty 17.0 Unisolated SG Dry Out 20.0 IIPI Ihjection Starts 35.8 Auxiliary Feedwater Initiation to Good SG 54.5 SG Tube Region Full of Liquid 320.0 Pressurizer Fill Up Starts 450.0 (Refer Figures A&B-62 to A6B-70)

\\41\\ 211 ~ A&B-28

RESPONSE TO 10 CFR 50.54(f) TABLE A&B-14 DOUIiLE ENDED STEAM LINE BREAK CASE.7 - LOOP AT ESFAS, IIPI FAILURE, NO DECAY llEAT, NO STUCK OPEN RELIEF VALVE EVENT TIME, s I Double Ended Rupture of 33.5" ID Steam Line Between SG and MSIV 0.0 . Closure of Turbine Stop Valves 0.0 Reach Low RC Pressure Setpoint 1.5 Control Rod Insertion Starts 2.2 Reach Low Steam Pressure ESFAS Setpoint 1.9 Low RC Pressure ESFAS + LOOP Event Initiation 5.8 MSIV's Closed 9.4 I MFWIV's Closed 16.9 Pressuri:cr Empty 17.0 Unisolated SG Dry Out 20.0 HPI Injection Starts 35.8 Auxiliary Feedwater Initiation to Good SG 54.5 SG Tuin Region Full of Liquid 290.0 (Refer Figures A&B-71 to A&B-79) ~ ' 1471 273 9 6 A&B-29

RESPONSE TO 10 CFR 50.54(f) TABLE A&B-15 g DOUBLE ENDED STEAM LINE BREAK CASE 8 - SLB ON OPPOSITE LOOP FROM PRESSURIZER, LOOP AT ESFAS, HPI FAILURE, NO STUCK OPEN RELIEF VALVES EVENT TIME, s Double Ended Rupture of 33.5" ID Steam Line Between SG and MSIV 0.0 Closure of Turbine Stop Valves 0.0 Reach Low RC Pressure Setpoint 1.5 Control Rod Insertion Starts 2.2 Reach Lou Steam Pressure ESFAS Setpoint 1.9 Low RC Pressure ESFAS + LOOP Event Initiation 5.8 MSIV's Closed 9.4 MFWIV's Closed 16.9 Pressurizer Empty 17.0 Unisolated SG Dry Out 20.0 HPI Injection Starts 35.8 Auxiliary Feedwater Initiation to Good SG 54.5 SG Tube Region Full of Liquid 350.0 (Refer Figures A&B-80 to A&B-88) i471 274 A&B-30

RESPONSE TO 10 CFR 50. 54 ( f) TABLE A&B-16 OPERATIfiG TPAflSIEflT CYCLES Transient Design fiumber Transient Description Cycles 1 Heatup and Cooldown (flormal Condition) 500F/hr heatup and cooldown with no decay heat 10 500F/hr heatup and cooldown with decay heat 230 Total 240 2 Power change 0 to 10% (Normal Condition) 730 and 15 to 0% 240 3 . Power Loading 8% to 100% power (Normal Condition) 3000 Power Loading 15% to 100% power (Normal Condition) 15000 4 Power Unloading 100% to 8% power (Normal Condition) 3000 Power Unloading 100% to 15% power (Normal Condition) 15000 5 10% Step Load Increase (Normal Condition) 40000 6 10% Step Load Decrease (Normal Condition) 40000 7-Step Load Reduction from 100% to 8% power (Upset Condition) Resulting from turbine trip 150 Resulting from electrical load re-150 jection Total 300 8 Reactor Trip (Upset Condition) Type A 120 Type B 140 Type C 120 Trips included in transient numbers 11, 15, 16, 17 & 21 112 Total 492 9 Rapid Depressurization (Upset Condition) 80 10 Change of Flow (Upset Condition) 30 11 Rod Withdrawal Accident (Upset Condition) 40 12 Hydrotests (Test Cor dition) 20 '3 Steady-State Power Variations (Normal Condition) 14 Control Rod Drop (Upset Condition) 40 15 Loss of Station Power (Upset Condition) 40 16 Steam Line Failure (Faulted Condition) 1 17A Loss of Feedwater to One Steam Generator (Upset 1471 275 Condition) 20 A&B-31

RESPONSE TO 10 CFR 50.54(f) TABLE A&B-16 (Cont'd) Transient Design fiumber Transient Description Cycles 17B Stuck Open Atmospheric Dump Valve (Emergency Condition) 10 18 Loss of Feedwater Heat (Upset Condition) 40 19 Feed and Bleed Operations (Normal Condition) 18000 20 Miscellaneous A (Normal Condition) 30000 6 Miscellaneous B 4 x 10 Miscellaneous C 20000 21 Loss of Coolant (Faulted Condition) 1 22 Test Transient - High Pressure Injection System (flormal Condition) 40 Test Transients - Core Flooding System (Normal Condition) 240 23 Steam Generator Fill, Draining, Flushi.ig and Cleaning (flormal Condition) 9 Steam Generator secondary side filling 240 Steam Generator primary side filling 240 Flushing 40 Chemical Cleaning 20 540 24 Hot Functional Testing (Normal Condition) 5 25 Leak Testing (Test Condition) 100 1471 276 A&B-32

RESPONSE TO 10 CFR 50.54(f) TABLE A&B-17 RPS/ESFAS FREOUENCY Actual Data Allowed Number Frequency Frequency No. of Reactor Trips (RPS) 228 6.95/yr 10/yr No. of Automatic ESFAS Actuations 27 .816/yr 2.0/yr No. of Plants Included 9 32.8 Reactor-Years 147) 277 A&B-33

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RESPONSE TO 10 CFR 50.54( f) APPENDIX C Ouestion c Provide a schcdule of completion of installation of the identified systems and components.
~~Response~~
Attached Table C-1 contains the construction status of the systems and components identified in Fnclosure 3 of your letter dated October 25, 1979, with the addition of the main feedwater system and integrated control system. Although this table includes the HPI system, DHR system, CFT system, quench tank, and RCS piping, as you requested in your letter, Consumers Power Company can find no relation or interaction between these items and the issue of OTSG sensitivity. Therefore, hardware and procedural changes for these systems are'not addressed. The table consists of a matrix for both units showing, for each system and component, the percent complete by quantities and the estimated completion date. The percent complete figure for small pipe (7. inches and under), large pipe, major equipment (panels, switchgear, pamps, valves, heat exchangers, and tanks), electrical equipment (cable, conduit, and trays,), and instrumentation ( transmitters, controllerse, tubing, and indicators) is based on actual quantities installod as of November 1, 1979, and compared to total quantitics estimated in February 1978. Some increases in total quantity are expected in small pipe and electrical quantities as a result of the present schedule review. Completion date is defined as the date when construction is 100% complete for all the equipment and components within the scope of the system or component and when the system or component is ready for turnover for testing. The completion dates reflected in the table are for the Consumers Power Company existing test schedule, which reflects fuel load dates of June 1981 and November 1981 for Units 2 and 1, respectively. They are currently under review and may be revised in early 1980 when a revised project schedule will be issued. Construction activities for large pipe and installation of major equipment for the listed systems / components are currently "on schedule" to meet the above target fuel load dates.
However, increased electrical quantities for raceway, small pipt, wire, and cable, plus constraints due to space limitations, are impacting small pipe and electrical construction activities for the listed systems / components.
Control room layout schedule activities are essentially complete, with 72 of 90 panels already installed. Panel board layout and control panel arrangement have been finalized, the indicating or readout devices and control device have been fixed, and most of the devices are already installed in the boards and wired by the C-1 11/79 1472 006
RESPONSE TO 10 CFR 50.54(f) APPENDIX C panel fabricator. The remainder of the devices are currently being installed in the field. HVAC installation work is complete, and electrical connections and terminations work is being performed on the installed panels. 1472 007 C-2 11/79
TA m2 C-1 CONSTRUCTION STATUS MIDLAND PLANT UNITS 1 AND 2 Unit 2% Complete (Installed) Unit I t Complete (Installed) Smalltu Largeni Completton Sma l l'" Large"' Completion s2n 83 s 8d System / Component Pipe , Pipe Equip Elec 8 I n s t Date Pipe 2) pipe Equip Elec'3' Inst ' Date HPI NA 75 100 68 6 01/10/80 NA 65 100 68 6 04/24/80 AEM <10 80 100 31 0 0/28/80 <10 75 100 26 0 08/06/80 DilR 50 65 100 57 4 12/21/79 20 55 100 55 1 04/15/80 CPT NA 95 100 43 17 01/25/80 NA 90 100 43 0 06/06/80 RCS pressure control 10 50 20 33 1 05/05/80 0 40 10 28 2 07/23/80 Makeup and le tdown 5 65 100 39 3 12/14/79 5 55 100 27 3 04/11/80 h Pteam generator pressure control 60 75 7 5 50 36 03/06/80 60 75 75'5' 33 36 08/21/80 g O Steam generator NA NA 90 NA NA 05/02/80 NA NA 90 NA NA 08/01/80 l Pressurizer'" NA 50 90 NA NA 05/05/80 NA 0 90 NA NA 07/23/80 E Quench tank NA 50 90 NA NA 05/05/80 NA 10 90 NA NA 07/23/80 Control room 8 layout NA NA 75 20 75 By system NA NA 75 20 75 By system RCS piping NA 90 NA NA 9 06/12/80 NA 75 NA NA 0 08/16/80 ICS'" NA NA 100 S a' NA 02/06/81 NA NA 100 i 3 s' NA 03/18/81 i MFW 70 95 100 47 17 02/25/80 55 92 100 36 2 06/04/80 'HPipe percent represents the summation of pipe spools, hangers, restraints, and field welds. 12'Small pipe is primarily vents and drains, e): Pulling cable was weighted as 75% of ef fort and terminating cable was weighted as 25% of ef fort. - * ' ' Tubing,.aonnting, ari electrical connections were weighted equally. .g:::. Rema in ing 2 5 % is installation of MAD valvea, which are onsite. N '"M.is scoped, the Includes surge line. O Gs'About ICS includes only the control cabinet. Also, field transmitters are included in each respective system. D i 50% of ICS system ables are pulled. Few are terminated. Cables in this system are mostly multi-(2) conductor. This number of connection greatly influences total percent complete. CD CD
RESPONSE TO 10 CFR 50.54(f) APPENDIX D Question d Identify the feasibility of halting installation of these systems and components as compared to the feasibility of completing installation and then effecting significant changes in these systems and components.
~~Response~~
Consumers Power Company's review of the feasibility of halting installation of these systems and components, as compared to completely insta11ating and then ef fecting significant changes, may be divided into two primary parts: 1) review of overall plant construction status, and 2) assessment of schedule impact of possible changes. With regard to overall plant construction status, the following information is provided with the percent complete figures based on quantities as discussed in Appandix C. a. Civil - Civil construction work is 82% complete; concrete work is 94% complete. Primary and secondary shield wall construction is complete in both containment buildings. The civil construction opening for the Unit 1 containment building was closed in September 1979. The opening for the Unit 2 containment building was closed earlier in 1979. Within both containment buildings and the auxiliary building, essentially all temporary civil construction openings have been closed. Post-tensioning of Unit 2 is 67% complete. Civil canstruction is essentially complete on the Midland plant. 5. Mechanical - All major mechanical equipment and components in both containment buildings and the auxiliary building have been set. All major NSSS components have been final set and the reactor coolant pump internals and motors have also been installed. The nuclear steam supply system (NSSS) for Unit 2 has all major loop piping welded and stress relieved. Presently, the NSSS erector is working on the reactor vessel internals fit-up and head assembly in Unit 2. The NSSS for Unit 2 is 3 months ahead of Unit 1. Eighty percent of the large pipe installation of NSSS support systems is installed, and it approaches that of a completed plant. Remaining mechanical work consists of small pipe, which is 45% complete, and both large and small pipe hanger installation, which is 60% complete. c. Electrical - All major electrical equipment and components in both containment buildings and the auxiliary building have been set. Installation of electrical bulk commodities is as follows: cable tray is 96% complete; conduit is 72% D-1 11/79 1472 009
RESPONSE TO 10CFR 50.54(f) APPENDIX D complete; and electrical cable is 41% complete for both
~~units, d.~~
2,strumentation - Installation of this portion of the plant Is'13% complete for both units. Consumers Power Company's assessment of halting installation of systems versus continuing installation and then effecting changes indicates that halting installation does not enhance the ability to modify the systems. Major component and large pipe installation is advanced beyond the point of effecting significant changes without major disruption. Small pipe, electrical, and instrunentation installation can accommodate changes, but halting installation is not deemed appropriate. Continuing installation of small pipe, electrical, and instrumentation and then effecting changes will have less impact on project cost and schedule than halting installation because electrical and instrumentation are on the present critical path for completion of the project. It is essential that Consumers Power Company continue with the installation of these items. Halting construction on some of the systems impacts others in the same physical area because of installation of restraints and hangers. In addition to the schedule delay and increased costs associated with a halt in construction, key personnel would be lost to the project. Consumers Power Company has evaluated the Three Mile Island accident for impact on the Midland design and has closely monitored industry and NRC pertinent activities. Through this process, the effect of pctential plant m'odifications on construction has been analyzed with, in general, a decision to continue these activities. In some circumstances, a conclusion has been to hold construction in specific areas pending final design determinations. A specific example of this is the MAD valves which are on an installation hold until completion of design review. 1472 010 D-2 11/79
RESPONSE TO 10 CFR 50.54(f) APPENDIX E Question e Comment on the OTSG sensitivity to feedwater transients. Ras ponse The Babcock & Wilcox nuclear steam supply system employs once-through steam generators (OTSGs) for heat transfer from the primary to the secondary system. The nuclear OTSG is a vertical straight shell and tube boiler in which the primary coolant (heat source) is on the tubeside and the secondary coolant is on the shellside. Main feedwater enters near the bottom of the tube bundle and flows upward. As it gathers heat, steam is generated and superbeated before exiting to the steam piping system. The overall primary-to-secondary heat transfer is cont. rolled by the rate of feedwater introduction to the generator. This, in turn, controls the area of the total tube bundle length which is exposed to liquid secondary coolant for a given input of primary power. Increasing feedwater flow increases the heat transfer and decreasing feedater flow decreases neat transfer. The design of the OTSG has yielded superior performance both in safety and efficiency in pressurized water reactors. The once-through design, with its superheated steam, exhibits a higher thermal efficiency than a recirculating steam generator, resulting in less waste heat rejected to the environment, better utilization of the uranium fuel, and a lower cost for electric power generation. The OTSG has exhibited an exceptional tube integrity record over its operating experience. This not only maximizes generator availability, but also minimizes the risk of radioactive release via a tube rupture. One inherent feature of this design is the responsiveness to feedwater control mentioned above. This responsiveness makes possible an accuracy of control which has both operational and safety advantages. Safety analysis of limiting feedwater and secondary system pressure disturbances has demonstrated the ability to maintain safe core cooling without radioactive release under the applicable licensing assumptions. However, the frequency of feedwater transients leading to disturbances of pressure and/or pressurizer level in the primary system of B&W plants has been higher th a desir ed. This has been somewhat exacerbated by restrictions on plant operations which have been imposed since the TMI-2 accident. Consumers Power Company supports the concept of defense-in-depth; and existing plant features accomplish this defense-in-depth as indicated on the attached Figure E-1, which uses an overcooling event as an example. Additionally, through studies of the Three Mile Island accident and evaluation of the operating history of B&W plants, Consumers Power Company has reviewed the Midland design for changes providing positive enhancement to the defense-in-depth concept. Plant modifications and areas identified for further investigation as a result of this 1472 01i examination are presented in hppendix F. E-1 11/79
RESPONSE TO 10 CFR 50.54(f) APPENDIX E Existing plant features, plus these changes, are sufficient to resolve many of the concerns expressed in Enclosure 1 of your letter. In support of this conclusion, the following comments provide a point-by-point discussion of your Enclosure 1. In summary, we have concluded that it is neither necessary nor desirable to modify the excellent performance record. a. Concern: " System modifications to increase the reliability of the AFW may have resulted in more frequent AFW initiation. However, use of AFW results in introduction of cold (100 versus 400F) feedwater into the more sensitive upper section of the steam generators. This may act to enhance syst sensitivity." Comment: The Midland auxiliary feedwater system is a. safety grade system' affording improved reliability as compared to older designs. AFW injection into the upper region of the OTSGs is an excellent design in that this configuration aids the initiation and maintenance of reactor coolant natural circulation. It is recognized that upper head injection serves to more closely couple AFW flow and temperature conditions with primary system response. Modifications to the AFW level control system, as discussed in Appendix F, will serve to alleviate this concern. b. Concern: "Further system modifications provide control grade reactor trips based on secondary system malfunctions such as turbine or feedwater pump trip. While these reactor trips do serve to reduce undercooling feedwater transients by reducing reactor power promptly following LOMFW, they may amplify subsequent overcooling." Comment: Anticipatory reactor trip on loss of main feedwater has, in fact, yielded very smooth system response. This has been confirmed by recent field data. Use of anticipatory trips should be eliminated, however, for those disturbances (such as turbine trip) which can be handled by plant control system action without challenging the plant safety systems. This will reduce the number of plant trips (see Item d below). Discussion of the anticipatory reactor trip system to be incorporated in the Midland design can be found in Appendix F. c. Concern: "A reexamination was made of small break and loss of feedwater events for B&W plants. This resulted in a modification of operator procedures for dealing with a small break which includes prompt RCP trip and raising the water level in the steam generators to 95% to promote natural circulation. Both these actions are taken when a prescribed low-pressure setpoint is reached in the reactor coolant system and for anticipated transients such as loss of 1472 012 E-2 11/79
RESPONSE TO 10 CFR 50.54(f) APPENDIX E feedwater. These actions may amplify undesirable primary system responses." Conment: The addition of an automatic reactor coolant pump trip, based upon the coincidence of signals indicating both low coolant system pressure and significant voids in the primary system, will eliminate the necessity for the operator to manually trip the reactor coulant pumps and raise OTSG water level. Witn the addition of this automatic function, reactor coolant pump trip should occur only for actual small breaks in the primary system. It should not occur for overcooling events initiated by feedwater transients. Such an automatic coincidence system is to be installed on Midland and is further discussed in Appendix F. d. Concern: "In addition to the post-TMI changes discussed above, actions were also taken to reduce the challenges to the power-operated relief valve (PORV) by raising the PORV setpoint and lowering the high-pressure reactor trip. While these actions have been successful in reducing the frequency of PORV operation, they have resulted in an increased number of reactor trips. This occurs because the reactor will not trip for transients it previously would have ridden through by ICS and PORV operation." Comment: The raising of the PORV setpoint and lowering of the high-pressure reactor trip have increased the number of reactor trips on the B&W operating plants. For Midland, modifications are discussed in Appendix F which will restore the controlled relief capability of the PORV while providing an increased level of protection against PORV malfunction. A resetting of the reactor protection system high-pressure setpoint and the 20RV setpoint to the original values will restore the capability of the B&W nuclear steam system to sustain a wide range of operational transients without a high-pressure reactor trip. e. Concern: "It is felt that good design practice and maintenance of the defense-in-depth concept requires a stable, well-behaved system. Meticulous operator attention and prompt manual action is used on these plants to compensate for the system sensitivity, rather than any inherent design features." Comment: The B&W OTSG and nuclear steam systems are designed to avoid reactor trip during various secondary system trancients. This responsiveness is an inherent feature of the design. Some B&W operating plants do place reliance upon the operator to limit feedwater excursions which may result from control system failure. However, Midland already includes a number of features to reduce this reliance upon the operator. Several additional modifications are being E-3 11/79
RESPONSE TO 10 CFR 50.54(f) APPENDIX E investigated which will further reduce the requirements for the operator to act in response to a control system failure and will thus improve our defense-in-depth against primary system parameter excursions resulting from moderate secondary system upsets. These changes are discussed in Appendix F. f. Concern: "It appears that in many cases the main feedwater control system does not react quickly enough or is not sufficiently atable to meet feedwater requirements.
~~Rather, the system will often oscillate from underfeed to overfeed conditions, causing a reactor trip and sometimes a high-pressure injection initiation.~~
One undesirable element of this lack of stability is that overcooling transients on the primary side proceed very much like a small break LOCA (decrease in pressurizer level and pressure). Thus, for a certain period of time, the operators may not know whether they are having a LOCA or an overcooling event." Comment: Overcooling transients in all PWR systems proceed initially like a small break LOCA, and thus are not a unique problem of the OTSG. For example, on a recent reactor trip in a PNR with a recirculating steam generator, a stuck-open turbine bypass valve with approximately 5% capacity caused an er.ssive overcooling which resulted in a prompt loss of reactor system pressure to the setpoint of the automatic safeguards injection system and contraction of the primary coolant sufficient to take pressurizer level below the range of indication. Consumers Powcr Company believes that proper design will result in a reduction in the frequency of such events to the greatest degree practicable, which, when combined with satisfactory design mitigative capability, adequate operator indications, and detailed training, will help the plant operators to deal confidently and safely when these abnormal events occur. Consumers Power Company efforts to improve identification and response to overcooling events are addressed in Appendix F. g. Concern: " A major area of concern arising from the B&W OTSG sensitivity is the response of pressurizer level indication. Several B&W feedwater transients have led to loss of pressurizer level indiation. Most notable was a November 1977 incident at Davis-Besse where level indication was lost for several minutes." Comment: The loss of pressurizer level indication following a reactor trip is an operational concern and should be minimized for expected abnormal occurences. However, it should be noted that the loss of indicated pressurizer level on B&W operating plants is not synonymous with a loss of liquid in the pressurizer. Certain B&W plants, such as the ' Davis-Besse Unit 1 reactor, have pressurizer level indicators which do not cover the full span of the pressurizer volume. E-4 11/79 1472 014
RESPONSE TO 10 CFR 50.54(f) APPENDIX E In the case of Davis-Besse, more than 40 inches of pressurizer capacity remain below the zero point of the level indication system. Thus, at these plants a momentary loss of indicated level should not be confused with an emptying of the pressurizer and potential for loss of natural circulation. For Midland, the indicated pressurizer level range will more closely relate to the full fluid volume of the pressurizer and, therefore, the loss of indicated pressurizer level will be minimized. With this expanded indication range, pressurizer level is expected to remain on-scale for feedwater upset transients such as those that have occured at Davis-Besse. h. Concern: "Some concerns also exist with regard to the operation of the pressurizer heaters when loss of level takes place. Nonsafety grade control circuitry trips the heaters off when pressurizer level is low. If these nonsafety grade cutoffs snould fail, the heaters would be kept on while uncovered." Comment: B&W operating plants include a control grade circuit to remove power from the pressurizer heaters when liquid level is low, and in no instance have the pressurize heaters on B&W operating plants been energized while uncovered. The function of the heater interlock is being reviewed for design adequacy. i. Concern: " Overfeed transient (MFW) (not uncommon to B&W) causes overcooling; pressurizer level shrinks, pressure reaches 1,600 psi, RS actuates, RCP is tripped; AFW on (possible RCP seal failure)." Comment-For the Midland plant, automatic equipment will be installed to eliminate the reactor coolant pump trip associated wit'.) low reactor coolant pressure only. In addition, main feedwater overfeed limiting equipment, independent of the integrated control system, will be investigated as a means to terminate main feedwter flow before excessive overcooling occurs. This investigation is further discussed in Appendix F. j. Concern: " Operator manually controls AFW (possibla MFW instead or in addition if MFW is not isolated such that OTSG level comes up to 9L% of operating range). This massive addition of cold water may lead to emptying of pressurizer and interruption of natural circulation (or the hot leg may flash due to depressurization and interrupt natural circulation even if pressurizer does not empty)." 1472 015 E-5 11/79
RESPONSE TO 10 CFR 50.54(f) APPENDIX E substantial defense-in-depth against sequences of the sort discussed in this section. Concern: "Regardless of the reasons, B&W plants are currently experiencing a number of feedwater transients which the NRC Staff feels are undesirable. The NRC Staff believes that modifications should be considered to reduce the plant sensitivity to these events and thereby improve the defense-in-depth which will enhance the safety of the plant." n. Comment: Safety analysis has shovn that adequate core cooling will be maintained and radioactive release will be avoided even for the most severe secondary system accidents within the plant's licensing basis. Midland already incorporatis a number of design features which address the issues raised in this paper by improving system reliability and reducing the consequences of secondary system upsets. In addition to this, a carefully considered group of investigations and modifications discussed in Appendix F are being undertaken to reduce primary system response to feedwater disturbances and to reduce the magnitude and frequency of secondary system feedwater upsets. These modifications will improve plant performance and enhance safety through the defense-in-depth concept by terminating or mitigating transients early in their course before they result in seriously abnormal conditions. 1472 016 E-7 11/79
RESPONSE TO 10 CFR 50.54(f) APPENDIX E Comment: The auxiliary feedwater system control circuitry will be modified for Midland to minimize tne excessive adeition of cold water which could lead to emptying of the pressu.rizer. Further discussion of this subject is found in Appenclx F. k. Concern: "HPI delivers cold water, no heat transfer in OTSG, vapor from core leads to system repressurization; steam may condense or PORV may lift." Comment: B&W calculations do not predict an interruption of core cooling or heat transfer to the OTSG as a result of the events sequence outlined. Delivery of the cold water by the high-pressure injection system will refill the reactor coolant system and quench any voids to provide additional assurance of adequate core cooling. 1. Concern: "No pump restart criteria are available, und circulation may not be reestablished." Comment: CriterIt for restart of a reactor coolant pump are already provided in the current small break operating guidelines to permit forced flow to be reestablished promptly following repressurization of the reactor coolant system. Further work in this area is proceeding under the abnormal transient operation guidelines (ATOG) program discussed in Appendix F in which Consumers Power Company is participating. Concern: "It appears that an upgraded safety quality ICS m. which is designed to balance power to OTSG level in a ber:er fashion could reduce the sensitivity illustrated in the above sequence." Comment: The integrated co; trol system is designed to provide smooth and stable operation of the complete power plant during power operation. One of its functions is to maintan the reactor plant online following various secondary system disturbances and eliminate unnecessary challenges to the reactor trip system. Following reactor trip, the ICS has a function in maintaining stable plant conditions within design limits. The recently completed ICS failure modes and effects analysis (FMEA) has identified measures which would improve the reliability of all control functions related to the B&W operating plant ICS design. Consumers Power Company's response to the results of this FMEA is addressed in Appendix F. Control of auxiliary feedwater is provided by a safety grade system independent of the ICS. As discussed in Item i, a system separate from the ICS to limit the main feedwater introduction which right occur as a result of primary control system failure is being investigated. The combination of improvements presently incorporated in the Midland design and those under consideration should provide E-6 11/79
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RESPONSE TO 10 CFR 50.54 t f) APPENDIX F Question f Provide recommendations on hardware and procedural changes related to the need for and methods for damping the primary system sensitivity to perturbations in the OTSG. Include details on any design adequacy studies you nave done or have in progress. Res ponse Much of the concern expressed about the " sensitivity" of the B&W OTSG PWR design is based on the operational experiences with the currently operating 177-FA plants, and particularly that experience accumulated since the accident at TMI-2. It is important to recognize that the normal evolution of design that has occurred on Midland as a result of new regulatory requirements, improvements of the state-of-the-art in hardware, and the feedback of operating experience have resulted in the incorporation of several new features. These features serve to improve the reliability of the systems and equipment and thereby reduce the probability of challenges to the safety system, improve the response to the NSCS to those events that do occur, and provide better capability to mitigate the events that occur. Some of the more significant pre-TMI-2 changes include: a. Upgrade the required pressurizer hcaters and controls to safety classification to ensure RCS subcooling b. Addition of a two-channel, Class lE auxiliary feedwater control system c. Initiation of auxiliary feedwater by the Class lE engineered safety features actuation system (ESFAS) d. Addition of feed only good generator (FOGG) logic to the ESPAS to help ensure that auxiliary feedwater is delivered only to the intact steam generator following secondary system breaks e. Adoption of newer control systems hardware (NNI/ICS) which uses dual, auctioneered power supplies for the logic modules rather than individual power supplies for each logic module as in the earlier design In addition to the described design improvements over current operating plants afforded Midland as a result of state-of-the-art advancement, Consumers Power Company has initiated a reevaluation of plant design in light of the TMI-2 accident and its implications concerning further modifications. Some of these investigations have been initiated specifically to address to concern of overcooling in B&W type plants. The following material discusses changes that have been identified for F-1 11/79 1472 019
RES PONSE TO 10 CFR 50. 54 ( f ) APPFNDIX F incorporation in the Midland design pertinent to this issue and also addresses additional evaluations pertaining to overcooling that are being conducted by Consumers Power Company. In general, the impact of presently identified modifications has been incorporated in the Midland project schedule now undergoing revision. Areas undergoing further evaluation have been revi_..__ for construction impact and, where appropriate, steps have been taken to ensure accommodation of expected changes within the construction schedule. I. DAMPING THE PRIMARY SYSTEM SENSITIVITY TO PERTURBATIONS IN THE OTSG As an outgrowth of the Three Mile Island accident, IE Bulletin 79-05B outlined new requirements to enhance plant response to undercooling type transients. Plant modifications resulting from these requirements were expected to enhance the creation of natural circulation by inhibiting RCS voiding during these events and thus limit the impact on the RCS of anticipated transients leading to undercooling events. In response to these requirements, the B&W operating plants, with the concurrence of the NRC, inverted the PORV and high RCS pressure trip setpoints and installed automatic reactor trip logic actuated by either turbine trip or loss of main feedwater. These changes address the NRC desire to minimize the operation of the PORV, thereby reducing the probability of RCS blowdown caused by a stuck-open valve. Additionally, energy input into the RCS was reduced through prompt reactor trip during transients that resulted in primary system pressure increases. Although these changes have succeeded in limiting the PORV actuations and RCS stored energy resulting from undercooling events, they have resulted in a significant increase in the frequency of reactor trips. Specifically, post-Three Mile Island plant history compiled by B&W demonstrates as much as a doubling of trip frequency of certain plants. Because undercooling events are most likely to occur following reactor trip, it can be concluded that the potential for these transients has increased. Therefore, while the applicable concerns of the NRC Staff resulting from events at Three Mile Island seem valid, it appears that the prescribed solution is inadvisable because the method used to minimize the impact of an undercooling transient may increare the probability of an overcooling event. CPCo intends to adopt an alternative solution that addresses TMI-2 concerns regarding primary system overpressure transients while maintaining a plant design resistant to overcooling events. This solution incorporates the following features: A. Original B&W 177-FA PORV and high RCS pressure setpoints (2,255 psig and 2,355 psig, respectively) F-2 11/79 1472 020
RESPONSE TO 10 CPR 50.54(f) APPENDIX F B. Safety grade anticipatory reactor trip on total loss of feedwater C. Fully qualified safety grade PORV D. Reliable safety grade indication of PORV position E. Dual safety grade PORV isolating block valves actuated by low RCS pressure ESFAS signal F. Test program to demonstrate PORV operability (EPRI) Thus, for seconu'ry transients (turbine trip / load rejection), the original B&W desip. features of turbine bypass, ICS runback, and PORV actuation are retained to keep the reactor online. Therefore, a critical reactor at power is available to minimize the probability of an overcooling event. To address the TMI-2 concern of actuation of an assumed unreliable PORV, design modifications are incorporated to ensure the proper operation of the valve, to display adequate indication of its position, and provide automatic isolation of the valve if it fails. Specifically, the commitment to provide an additional block valve and automatic isolation of the PORV addressed in Item e above is contingent upon restoration of the PORV pressure-reducing function as afforded by Item a. For loss of feedwater events during which reactor trip is a certainty, specific additional trip circuitry is provided to anticipate the high PCS pressure trip and thus minimize energy input into the primary system. In summary, the design features discussed above address the issue of overcooling by minimizing unnecessary reactor trips while providing the capability to prevent undercooling transients or, if necessary, adequately mitigate their consequences. This approach provides the most balanced and logical method for dealing with these two opposite, yet related, plant transients. II. OTHER RELATED DESIGN ADEQUACY STUDIES A. Auxiliary Feedwater System A design review of the Midland AFW system since TMI-2 has resulted in several modifications to the original system design. The most significant was a modification of the AFW pump suction piping from one interconnected system for both Midland units to two systems operating independently to supply AFW for each unit. Additionally, AFW flow indication is being upgraded to safety grade. Another potential modification previously identified is the addition of redundant flowpaths from the discharge of each AFW pump to each steam generator. This potential change is being examined to gage its potential impact on system reliability in an in-depth F-3 11/79 1472 021
RESPONSE TO 10 CFR 50.54(f) APPENDIX F reliability assessment of the Midland AFW system. To protect the Midland project schedule while this evaluation is being conducted, the additional AFW flow control valves that may be necessary are being ordered. The AFW analysis is being conducted with the aid of an outside consultant, and is to identify both independent and dependent component failure modes, including the effects of equipment maintenance and operator errors, under the following three scenarios: 1. Loss of MFW with offsite ac power available 2. Loss of MFW with offsite ac power unavailable 3. DC power available only The probability of system failure for each scenario will be calculated via fault and event tree techniques. No significant additional contributors to system failure having a substantial construction impact are expected to be identified in this formal reliability analysis. For transients such as loss of main feedwater and loss of off site power, the proper operation of the AFW level control system is essential to the prevention of RCS overcooling. System control, as presently designed, is based solely on steam generator level error and allows essentially full AFW flow to the OTSGs until actual level approaches the setpoint. Midland is currently investigating modifications to the AFW level control system which would limit the primary system cooldown rate following AFW actuation and incorporate multiple setpoints for final level. The level setpoint selected would be dependent on conditions of the reactor coolant pumps and would include the higher level setpoint required for mitigation of small break LOCAs. Limiting the cooldown rate of the primary system will allow time for the makeup system to recover pressurizer level and allow time for the operator to take actions necessary to prevent loss of indicated level. Analysis work is proceeding on an AFW ?evel control scheme which limits primary system cooldown rates by limiting the rate of steam generator level increase _ (i.e., limiting AFW flowrates). The major impact of this change will be in obtaining the electronic hardware necessary to implement the new control scheme. Changeout of control electronics has a minimal impact on overall system construction because it can be accomplished within a few weeks followi.ng receipt of the necessary hardware. Therefore, there is no need to halt F-4 11/79 1472 022
RESPONSE TO 10 CFR 50. 54 ( f) APPENDIX F construction on the AFW system based on expected changes to the AFW control scheme. As discussed in the introduction to this section, the Midland design includes a FOGG system whose function is to identify the ruptured steam generator following a secondary systems line break and to prevent feeding AFW to this steam generator if the break is upstream of and cannot be isolated by the main steam and feedwater isolation valves. Blocking AFW flow to the ruptured steam generator prevents an uncontrolled cooldown of the primary system. The FOGG system accomplishes this without need for operator action. The current Midland FOGG logic permits AFW flow to the steam generator which repressurizes to 1725 psig following an actuation of the main steam line isolation system (MSLIS). This repressurization results in a permissive allowing AFW flow only to the intact steam generator. Recent steam line break analysis work by B&W has shown that for certain sizes of steam line breaks, the intact steam generator will not repressurize to 725 psig and, therefore, neither steam genrator will receive AFW flow. As a result of this potential for the presently designed FOGG system to block AFW flow to 6.gth eceam generators, the logic for FOGG actuation is being reviewed. The following two options for correcting the identified problem with the FOGG system are being investigated. 1. Lowering the FOGG setpoint to a value less than 725 psig such that in all steam line break cases it can be shown that the intact steam genrator will repressurize above this value. 2. Modifying the FOGG logic to use differential pressure between the steam generators as a detecting parameter for FOGG actuation. The latter option, actuating FOGG on steam generator differential pressure, appears to be the best method at present. Additional analytica. work is required to determine the differential pressure setpoint to be utilized to actuate this system and to verify operability over the range of main steam line breaks. Either change in the method of actuating FOGG described above will result in changes to control circuitry only. No changes to piping are required to modify the FOGG system. Because control circuitry changes can be made within a few weeks of receipt of hardware, no halt in construction is justified based on potential modifications to the FOGG system. 1A72 023 F-5 11/79
RESPONSE TO 10 CFR 50.54(f) APPENDIX F B. Pressurizer As mentioned in the introduction to this section, redundant portions of the pressurizer heaters and heater controls have been upgraded to safety grade. This upgrade provides the ensured capability of maintaining adequate subcooling after all anticipated transients through proper RCS pressure control. Additionally, redundant pressurizer level and reactor coolant pressure indications have been upgraded to safety grade on the main control boards and auxiliary shutdown panel. To specifically address the concern of loss of pressurizer level indication due to overcooling events, the indication range is being extended to a scale of 0 to 400 inches. The original design range of 0 to 320 inches creates a greater potential for an actual off-scale low level as demonstrated by operating plant history. The 40-inch increase at both ends of the present operating range, in conjunction with anticipated improvements in the AFW level control scheme discussed in Section II. A,, will provide additional assurance that the pressurizer level will remain on-scale for all anticipated operational occurrences. This design modification is currently being implemented. In the event of loss of liquid inventory in the pressurizer, future availability of the pressurizer heaters may require their deenergization before uncovery. As a result, the existing heater low lcvel interlock design is being reviewed to judge its adequacy. Because modifications resulting from this investigation would affect only control and/or instrumentation design, no impact on construction schedule is expected. C. Transient Identification As discussed in Appendix E, overcooling events in all FWR systems proceed initially like a small break LUCA. Therefore, it is important that any auotmatic plant response required for either of these events be able to differentiate between similar appearing transients in order that system actuations only occur when desired. Additionally, sufficient indications are necessary to allow the operator to follow the course of transient and verify proper safeguard features operation and adequate core cooling until the exact cause of the event can be positively identified. The current status of investigations by Consumers Power Company in these two areas is discussed below. In general, specifically identified design changes can be accommodated within the F-6 11/79 1477 074
RESPONSE TO 10 CFR 50.54(f) APPENDIX F present s struction schedule and modifications res ultinc. 4 rom ongoing investigations are expected to effect only control and instrumentation design and therefore can be instituted during system construction with no anticipated impact. 1. Automatic Plant Response Additional investigations initiated as a result of the small break LOCA analyses submitted to the NRC by B&W (Evaluation of Transient Behavior and Small Reactor Coolant System Breaks in the 177 Fuel Assembly Plant, May 7, 1979) have demonstrated tha t under conservative tripping of the RCPs is necessary for mitigation of certain size small breaks. Tripping of the reactor coolant pumps for overcooling type transients is, however, undesireable because this action is not necessary for proper plant recovery and, in fact, sacrifices enhanced controlability afforded by forced circulation. To prevent automatic RCP tripping due to ESFAS actuation initiated by overcooling events, the Midland pump trip logic will include coincidence circeitry sensing RCP motor current. This input will actuate on degraded pump current indicative of significant RCS void formation characteristic of a LOCA. For overcooling events, the extent of void formation will not reach a point where degraded pump current will actuate RCP trip. 2. Plant Indications a. Psat/Tsat Meter - Consumers Power Company is committed to providing a subcooling meter with redundant safety grade hot leg temperature and reactor coolant system pressure input, b. Core Exit Thermocouples - CPCo is assessing a technical proposal to utilize core exit thermocouples as a means of determining adequate core cooling. Specifically, the use of nonsafety grade core exit thermocouples in conjunction with the plant computer is being assessed for possible use in providing core map temperature trending, margin to saturation of the average incore map temperature trending, the hottest valid thermocoupl e temperature. 1472 025 F-7 11/79
RES PONSE TO 10 CFR 50. 54 ( f) APPENDIX F c. Primary Coolant Level Indication - Consumers Power Company is participating in a B&W engineering study to determine the most appropriate method for operator recognition of inadequate coolant level. The method presently being considereo to provide the information is het leg water level in lieu of reactor vessel water level. Differential pressure on the hot leg ( from the top of the candy cane to the bottom of the hot leg piping) is the technique being evaluated for measuring the level. d. Natural Circulation Flow Indication - Consumers Power Company is reviewing the technical feacibility of providing a low flow indication as a means of confirming core cooling during natural circulation modes of cooldown. Control room panel space is available for the hard wire display of the above-menthioned plant indications, if implemented. However, core exit thermocouple information is intended to be displayed in the control room through the plant computer-printer and/or CRT. D. Integrated Control Systems (ICS) FMEA In response to the TMI-2 event, B&W performed a failure mode and effects analysis (FMEA) of the ICS. The results of this analysis, supported by ConGumers Power Company through the B&W owners group, have been supplied to the NRC ( B AW-15 64, Aug us t 1979 ). As a result of this effort, several areas have been identified as warranting additional review on a plant-specific basis for evaluation of possible changes which may result in the enhancement of reliability and safety. Consumers Power Company is evaluating the recommendations contained within the ICS FMEA and intends to make modifications necessary to elicit improvements based on the results of this evaluation. Design changes resulting from this investigation would affect only control and/or instrumentation and, therefore, could be accommodated at any time during system construction. 1472 026 F-8 11/79
RES PONSE TO 10 CFR 50. 54 ( f) APPENDIX F E. Main Feedwater 4) As a result of your 10 CFR 50.54(f) request of October 25, 1979, B&W has underriken several reviews designed to further evaluate causes of overcooling events and mitigative plant response. One of these studies consisted of examination of operating plant experience aimed at identifying the sources of overcooling transients and assessing the ef fect of possible modifications. Additionally, B&W has reviewed the typical sequence of events for overcooling transients, identified the existing plant design features which provide defense-in-depth against the occurrence of inadequate core cooling, and investigated the need for additioanl changes where suggested to improve these defenses. These studies, the ICS FMEA discussed in Section II.D, and the Consumers Power Company review of B&W operating plant experience and Midland plant design have identified various MFW faults which could lead to secondary system upsets. Consumers Powcr Company intends to bring together information from these sourcec in a detailed review and analysis of the MFW system. The outcome of this task is expected to be an identification of changes which would significantly decrease the frequency of feedwater upsets. From the analysis that was preeented on turbine / reactor trip and main feedwater overfill, it has become apparent that the OTSG may become filled and water will enter the main steam lines. Consumers Power Company believes that this condition is not desirable and will provide protection against this occurance upon evaluation of the options available. This change and any other changes to the feedwater system which may result from our continuing review are expected to impact controls and instrumentation only. Therefore, it is expected that any resulting changes can be accommodated at any time during system construction. F. Miscellaneous Studies In May 1979, Consumers Power Company contracted with EDS Nuclear to conduct a design review of selected Chapter 15 accidents and aelected plant systems (safety and non-safety). Sixteen safety and operational sequence diagrams and fifteen auxiliary system diagrams are being used as a vehicle for this review. The methodology for the analysis is identical to that referenced in Chapter 15 (Page 15-5) of Regulatory Guide 1.70, Rev 3. All identified potential design inadequacies are being formally documented and resolved through joint action resulting from Consumers Power Company, Bechtel, and B&W F-9 11/79 1472 027
RESPONSE TO 10 CFR 50.54(f) APPENDIX F review. The analysis has presently identified some deficiencies (e.g., improper main steam line isolation signal initiation logic). This deficiency, which is believed to be representative of others which may be uncovered. will be corrected by modifications to the system controls and therefore can be accommodated during system construction. Following the relase of the Short Term Lessons Learned Report (NUREG-0578), the B&W 177-FA owners group, including Consumers Power Company, embarked on the anticipated transient operating guidelines (ATOG) program. The basic input, with minor modications in scope, is the safey sequence analysis performed by EDS Nuclear for Consumers Power Company. This analysis provides the design input for the ATOG program which involves construction of event trees, dynamic analyses, and development of operating guidelines. Because the safety sequence analysis provides the basic design input to the program, no hardware changes are expected to result from ATOG that will not ficst be identified by the ELS program. Expected changes resulting from ATOG will be procedural in nature and therefore do not impact construction. Finally, B&W has performed an analysis of the dynamic post-trip response of the NSSS to overcooling transients. This post-trip responsiveness study investigated primary system senstivity, measured by fluctuations in pressurizer level, to changes in various plant parameters. Consumers Power Company is presently reviewing this analysis te determine its implications on plant design. Preliminary review indicates most concerns have already been addressed cr are identified for further study. 1472 028 F-10 11/79
RESPONSE TO 10 CFR 50. 54 ( f) APPENDIX F III. S UMM ARY The defense-in-depth approach to maintaining adequate core ccoling is accomplished through system design and plant procedures. In the specific car of overcooling events, Figure E-1 depicts the implementation of this approach through provisions to minimize the frequency of the transient, indications to allow the operator to detect the event and evaluate the adequacy of the response, and procedures to ensure proper actions are taken and to identify additional steps to counteract failures or degraded conditions as identified. While current plant design fulfills the requirements for defense-in-depth, Consumers Power Company believcs that additional measures can and should be taken to strengthen the Midland plant's resistance to overcooling events and to ensure acceptable mitigation if these transients which do occur. Design changes described in this appendix, along with additioani modifications and procedural changes which may result from the stulies that have been addressed are expected to accomplish this goal. Table F-1 summarizes these items and Figure F-1 shows how they will compliment existing plant features to provide additional overcooling defense-in-depth. Consumers Power Company believes that this approach will adequately resolve current concerns. In conclusion, Consumers Power Company is actively pursuing the issue of overcooling and has committed to modifications which, coupled with the outcome of various ongoing plant studies, result in a final design which provides adequate de'fenses to these events. We believe that most changes which are significantly impacted by construction status have already been initiated and that any remaining modifications resulting from completion of design studies can be accommodated during system construction. 1472 029 F-ll 11/79
RES PONS E TO 10 CFR 50. 54 ( f) APPENDIX F TABLE F-1 DEFENSE-IN-DEPTH FEATURES FOR MAINTAINING ADEQUATE CORE COOLING 1. Automatic Closure of PORV Block Valves on ESFAS Actuation 2. PORV Upgrade and Qualification 3. Pressurizer Heater Upgrade 4. Extended Pressurizer Indication Range and Upgraded Qualification 5. Fully Safety Grade APW System 6. FOGG System 7. Total Loss of Main Feedwater Anticipatory Reactor Trip 8. Safety Grade PORV Position Indication 9. AFW System Improvements (Reliability Analysis, Flow Indication Upgrade, Piping Modifications)
10. Improved AFW Flow Control

11. Pressurizer Heater Interlock

12. Automatic RCP Trip Circuitry Featuring Low Motor Current Incidence Logic

13. Instrumentation to Detect Inadequate Core Cooling

14. ICS FMEA

15. MFW System Review

16. ATOG Program

17. Restoration of Original PORV and High RCS Pressure Trip Setpoints i472 030 F-12 11/79
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ML19210E292

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