ML20042A682
| ML20042A682 | |
| Person / Time | |
|---|---|
| Site: | Byron  |
| Issue date: | 03/31/1982 |
| From: | COMMONWEALTH EDISON CO. |
| To: | |
| Shared Package | |
| ML20042A674 | List: |
| References | |
| ENVR-820331-01, ENVR-820331-1, NUDOCS 8203230678 | |
| Download: ML20042A682 (150) | |
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{{#Wiki_filter:- Byron ER-OLS AMENDHENT NO. 3 MARCH 1982 INSTRUCTIONS FOR UPDATING YOUR ER To. update your copy of the Byron Station Environmental Report-Operating License Stage, please remove and destroy the following pages and figures and insert the Amendment No. 3 pages and figures as indicated. REMOVE INSERT VOLUME 1 Page ii Page ii. Pages 1.0-i/1.0-ii and Pages 1.0-1/1.0-ii and 1 0-iil/1.0-iv 1.0-lii/1.0-iv . Page 1.0-1 Page 1.0-1 . Pages 1.1-1/l.1-2 through Pages 1.1-1/l.1-2 through 1.1-41/1.1-42 1.1-41 Page 1.3-1 Page 1.3-1 l Page 2.0-xv/2.0-xvi Pages 2.0-xv and 2.0-xva/2.0-xvi O' A- Page 2.1-1/2.1-2 Pages 2.1-1/2.1-2 and 2.1-2a Page 2.1-7/2.1-8 Pages 2.1-7/2.1-8 and 2.1-8a Page 2.1-11/2.1-12 Page 2.1-11/2.1-12
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Page 2.1-35/2.1-36 Page 2.1-35/2.1-36 Figures 2.1-3 and 2.1-4 Figures 2.1-3 and 2.1-4 Figures 2.1-6 and 2.1-7 Figures 2.1-6; 2.1-7; and 2.1-7A Page 2.3-7/2.3-8 Page 2.3-7/2.3-8 Page 2.3-29/2.3-30 Page 2.3-29/2.3-30 Pages 2.4-11/2.4-12 through Pages 2.4-11; 2.4-11a/2.4-12; 2.4-13/2.4-14; .and 2.4-15/2.4-16 2.4-15/2.4-16 Figures 2.4-2 and 2.4-3 Figures 2.4-2 and 2.4-3 Figure 2.4-5 Figure 2.4-5 Figure 2.4-10 Figure 2.4-10 Figure 2.4-16 Figure 2.4-16 s- Page 2.6-1/2.6-2 Page 2.6-1/2.6-2 8203230678 820310 PDR ADOCK 05000454 C PDR E -
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' Byron ER-OLS AMENDMENT NO. 3 MARCII 1982
() INSTRUCTIONS (C0nt'd) REMOVE INSERT VOLUME 2 Page 11 Page ii , Pages 3.0-1/3.0-ii and Pages 3.0-i/3.0-ii and 3.0-lii/3.0-iv 3.0-lii/3.0-iv Pages 3.3-1/3.3-2 and Pages 3.3-1/3.3-2 and 3.3-3/3.3-4 3.3-3/3.3-4 Figure 3.3-1 Figure 3.3-1 Pages 3.4-1/3.4-2 Pages 3.4-1/3.4-2 and 3.4-2a Pages 3.5-7/3.5-8 and Pages 3.5-7/3.5-7a; 3.5-9/3.5-10 3.5-8/3.5-9; and 3.5-9a/3.5-10 Pages 3.5-15/3.5-16 through Pages 3.5-15/3.5-16 through 3.5-19/3.5-20 3.5-19/3.5-20 Page 3.5-23/3.5-24 Page 3.5-23/3.5-24 () Pages 3.5-27/3.5-28 through 3.5-31 Pages 3.5-27/3.5-28; 3.5-29/3.5-30; and 3.5-30a/3.5-31 Figure 3.5-1 Figure 3.5-1 Pages 3.5A-1/3.5A-2 Pages 3.5A-1/3.5A-2 through 3.5A-5/3.5A-6 through 3.5A-5/3.5A-6 Pages 3.5A-9/3.5A-10 Pages 3.5A-9/3.5A-10 through 3.5-13/3.5A-14 through 3.5A-13/3.5A-14 and 3.5A-14a Page 3.5A-19/3.5A-20 Page 3.5A-19/3.5A-20 Page 3.6-1/3.6-2 Pages 3.6-1/3.6-2 and 3.6-2a Pages 3.6-7/3.6-8 through Pages 3.6-7/3.6-8 through 3.6-11 3.6-11 Page 4.0-i/4.0-il Page 4.0-i/4.0-li Page 4.1-1/4.1-2 Page 4.1-1/4.1-2 Page 4.1-9/4.1-10 Pages 4.1-9 and 4.1-9a/4.1-10 Page 4.3-1 Page 4.3-1 Page 5.1-13/5.1-14 Pages 5.1-13 and () 5.1-13a/5.1-14 4 2
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Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 INSTRUCTIONS (Cont'd) (} REMOVE INSERT VOLUME 2 (Cont'd) Page 5.1-25/5.1-26 Page 5.1-25/5.1-26 Figure 5.1-6 Figure 5.1-6 Page 5.2-3/5.2-4 Pages 5.2-3 and 5.2-3a/5.2-4 Page 5.2-9/5.2-10 Page 5.2-9/5.2-10 Page 5.2-15/5.2-16 Page 5.2-15/5.2-16 Pages 5.3-5/5.3-6 Pages 5.3-5/5.3-6 and 5.3-7 and 5.3-7 Pages 5.6-5/5.6-6 Pages 5.6-5/5.6-6 and 5.6-7 and 5.6-7 Figure 5.6-1 Figure 5.6-1 Page 8.0-1 Page 8.0-1 Pages 12.0-1/12.0-2 Pages 12.0-1/12.0-2 s and 12.0-3/12.0-4 and 12.0-3/12.0-4 U Page 13.0-3/13.0-4 Pages 13.0-3 and 13.0-3a/13.0-4 Following Amendment No. 1 Tab Page Q291.1-1 Page Q291.1-1 Page Q320.1-1 Page Q320.1-1 Pages Q320.4-1/0320.4-2 Pages 0320.4-1/0320.4-2 and Q320.4-3 and Q320.4-3/0320.4-4 Page Q320.5-1 Page Q320.5-1 Pages Q320.6-1/0320.6-2 Pages Q320.6-1/0320.6-2 and Q320.6-3 and Q320.6-3 Pages Q320.8-1/0320.8-2 Pages Q320.8-1/0320.8-2 and 0320.8-3/0320.8-4 and Q320.8-3/0320.8-4 Following Amendment No. 2 Tab Following Page Q470.2-2 Amendment No. 3 tab (do not remove) and NRC Questions and Responses (Page Q.0-i; Page Q371.9-1/0371.9-2; Figures Q371.9-1 through 0371.9-3; and Page Q371.10-1) (} 3 _J
Byron ER-OLS AMENDMENT NO. 1 JU LY 1981 AMENDMENT NO. 2 ) {s '_ s SEPTEMBER 1981 AMENDMENT NO. 3 MARCil 1982 CONTENTS (Cont'd) 4 Cl! APTER VOLUME Appendix 6.lA - Formulas.Used in Analyses of Algal Data 2 Chapter 7.0 - Environmental Effects of Accidents 2 Chapter 8.0 - Economic and Social Effects of Station Construction and Operation 2 . Chapter 9.0 - Alternative Energy Sources and Sites 2 Chapter 10.0 - Station Design Alternatives 2 Chepter 11.0 - Summarp Cost-Benefit Analysis 2 Chapter 12.0 - Environmental Approvals and Consultation 2 Chapter 13.0 - References 2 Amendment No. 1 - NRC Review Questions and Responses 2 1 Amendment
- No. 2 - NRC Review Questions and Responses 2 2
! Amendment No. 3 - NRC Review Questions and Responses 2 3 i i !O 11 .
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Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 O MARCH 1952 CHAPTER 1.0 - PURPOSE OF THE PROPOSED FACILITY AND ASSOCIATED TRANSMISSION TABLE OF CONTENTS PAGE 1.1 SYSTEM DEMAND AND RELIABILITY 1.1-1 1.1.1 Load Characteristics 1.1-3 1.1.1.1 Load Analysis 1.1-3 1.1.1.2 Demand Characteristics 1.1-4 1.1.1.2.1 Load Forecasting Methodology 1.1-4 1.1.1.2.2 Econor.1etric Model IV 1.1-6 1.1.1.2.3 Econometric Model V 1.1-8 1.1.1.2.4 Explanatory Variable Projections 1.1-9 1.1.1.2.5 Growth Perceptions by Others 1.1-10 3 1 1.1.1.2.6 End Use Consid2 rations 1.1-10 1.1.1.2.7 Development of Peak Load Estimates 1.1-10 1.1.1.2.8 Forecasting with the Models 1.1-12 1.1.1.3 Power Exchanges 1.1-12 1.1.2 System Capacity 1.1-12 0~ 1.1.3 . Reserve Margins and Generating System Reliability 1.1-13 Percent Reserve Margin 1.1-14 3 1.1.3.1 1.1.3.2 Interconnections 1.1-14 1.1.4 External Supporting Studies 1.1-14 1.2 OTHER OBJECTIVES 1.2-1 1.3 CONSEQUENCES OF DELAY 1.3-1 1 i l O 1.0-i c- J
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCH 1982 O CHAPTER 1.0 - PURPOSE OF THE PROPOSED FACILITY AND ASSOCIATED TRANSMISSION LIST OF TABLES TITLE PAGE NUMBER 1.1-1 Existing CECO Generating Units for the 3 Summer of 1982 1.1-15 1.1-2 Actual CECO System Peak Loads and Output 1.1-16 1.1-3 Estimated CECO System Peak Loads and Output 1.1-17 1.1-4 CECO's Annual Load Duration Curve for 1980 1.1-18 1.1-19 1.1-5 Monthly Summary for 1980 1.1-6 Load Characteristics on CECO's System's Peak Day: July 15, 1980 1.1-20 1.1-7 Actual and Long Range Estimated System Peak Loads and Output Required for Sales to Ultimate Consumers and Municipalities for Years 1960 to 2001 1.1-22 1.1-8 Definitions of Explanatory Variables Used
- in Model IV 1.1-23
. 1.1-9 Model IV Using 1967-1981 Observations 1.1-25 3 1.1-10 Definitions of Explanatory Variables Used in Model V 1.1-26 1.1-11 Model V Using 1967-1981 Observations 1.1-27 1.1-12 Summary of Assumptions Used on Explanatory 1 Variables 1.1-28 1.1-13 Documentation of Weather Variable Predictions: 20-Year (1961-1980) Average Peak-Making Weather Values for Summary Peak Load Days 1.1-29 1.1-14 Growth Indicators 1.1-30 Official Peak Load Estimates for 1982 1.1-15 l
through 1991 1.1-31 l 1.1-16 CECO Summer Peak Load Forecasts: 1966-1991 1.1-32 1.1-17 CECO Summer Peak Load Forecasts as Percentages of Actual Peak Loads: 3 1966-1981 1.1-33 1.1-18 CECO Summer Peak Load Forecasts as Percentages of Reconstructed Peak Loads: l 1966-1981 1.1-34 1.1-19 Reconstructed Annual Peak 1.1-35 1.1-20 Commonwealth Edison Company - Actual Monthly Peak Loads and MWh Sold Versus Estimated Values from January 1.1-36 3 1973 to December 1981 1.1-21 Firm Power Interchanges at Times of Annual Peak Demand 1.1-38 1.0-ii i
1 Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 O MARCH 1982 LIST OF TABLES (Cont'd) NUMBER TITLE PAGE 1.1-22 Planned Generating Unit Additions and 1.1-39 3
- Retirements i 1.1-23 Generating Unit Capabilities and Estimated Capacity Factors
- 1975-1990 1.1-40 1 1.1-24 Load and Capacity Statement for Commonwealth Edison Company 1.1-41
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Byron ER-OLS AMENDMENT NO. 1 JULY 1981 CHAPTER 1.0 - PURPOSE OF THE PROPOSED FACILITY AND ASSOCIATED TRANSMISSION LIST OF FIGURES NUMBER TITLE 1.1-1 1975 Energy Efficiency Ratio Educational Ad 1.1-2 1975 Air Conditioner EER and Conservation Ad 1.1-3 1975 Air Conditioner EER Ad 1.1-4 1975 Heat Pump Ad 1.1-5 1977 Insulation Conservation Ad 1.1-6 1977 Insulation Financing Ad 1.1-7 1977 Air Conditioning EER Ad 1.1-8 1977 Air Conditioner Cleaning Ad 1.1-9 1977 Heat Pump Ad 1.1-10 1978 Caulking Conservation Ad 1.1-11 1978 Insulation Conservation Ad 1.1-12 1980 Heat Pump Ad 1.1-13 1980 Air Conditioner EER and Conservation Ad 1 1.1-14 1980 Ice Storage System Ad 1.1-15 1981 Conservation Ad 1.1-16 Load Duration Curve for 1980 l.1-17 Daily Load Duration Curve for Peak Day of 1980 0 O 1.0-iv t --
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 O MARCH 1982 CHAPTER 1 - PURPOSE OF THE PROPOSED FACILITY AND ASSOCIATED TRANSMISSION This chapter demonstrates the need for the Byron Nuclear Generating Station - Units 1 & 2 (Byron Station) and describes the estimated effects of any delay in its construction or operation. The Final Environmental Statement with respect to the construction permit was issued in July 1974. Since that time, various construction and licensing delays have occurred, some of them resulting from Three Mile Island. Commonwealth Edison Company (CECO) has, therefore, adjusted its capacity expansion i program. As a result of these changes, the service date of Byron Unit I has been deferred from May 1980 to February 1984 and that 3 of Byron Unit 2 from May 1981 to February 1985. i i 1 O . 1 0 1.0-1 __ _ _ J
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AMENDMENT 60. I JULY,1981 AMENDMENT-NO. 3 [^/) \-
\ MARCH 1982 1.1 SYSTEM DEMAND AND RELIABILITY ThissectiondiscussestherequirementsfortheByronnucidak units in CECO's system._ CECO's planning studies are based on' forecasted loads and generating capabilitiec of its units along '
x with the reliability and economic benefits of being interconnected with other utilities. CECO ~is a member of the ., Mid-America Interpool Network (MAIN), one of the inine reliability- ,1 councils in the country and is directly interconnected with most of the MAIN, member utilities. In addition, Ceco has interconnections to the East-Central Area Reliability council (ECAR) and the Mid-Continent Area Reliability Coordination Agreement council (MARCA), which allow CECO the benefits of interconnections with their member utilities. Additional generating capacity is required for three reasons. The first is that new capacity is required to meet the increased load caused by load growth. Second, new capacity is required to economically replace the. capacity of old generating equipment retired because of obsolescence or environmer.tal considerations. Third, new capacity is needed to meet the increased t reserve
- requirements caused by the added load.
The capacity of CECO for the summer of 1982 is as follows: Nuclear 5,826. Base Fossil 5,286 Cyclical Fossil 4,323 3 Pucped Hydro (leased) 624 Fast Start Peaking Units 1,277 TOTAL: 17,336 MW Table 1.1-1 presents a listing of all the CECO generating facilities for the summer of 1982 showing their station and unit name, year of installation, and net generating capability. Footnotes in Table 1.1-1 give the key to unit type and show which CECO units are cooperatively owned. At the present time, the only units in which CECO participates jointly are the Quad Cities Nuclear Units shared with Iowa-Illinois Gas and Electric Company, which owns one-fourth of the station. CECO also has leased 624 1 MW of pumped hydro capacity at Ludington, Michigan. (~% CECO's program for conservation in the consumption of electrical \ energy has been expanded, and a Load Management and Conservation Department has been established to coordinate conservation activities. New ideas and sales promotion techniques are being employed to increase the effectiveness of customer energy 1.1-1 J
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 conservation. Radio and T.V. commercials, newspaper releases on energy conservation, and newpaper advertisements in both major Chicago metropolitan newspapers and local and regional papers are directed at helping customers in the " wise" and " efficient" use of electricity (see Figures 1.1-1 through 1.1-15). CECO's booklet "101 Ways to Conserve Electricity at Home" succinctly provides customers with suggestions on energy savings for oil and gas as well as electricity. Proper selection of new appliances (air conditioners with high energy cfficiency ratios, well-insulated ovens, heat pumps, and non-frost free refrigerator- 1 freezers) and the proper maintenance of both new and existing appliances are items mentioned that help reduce electricity costs and conserve energy. Furthermore, a program has been developed to ensure that CECO's largest commercial and industrial customers are contacted by marketing field personnel within a 3-year period. The customers are surveyed to determine their energy needs, energy substitution considerations, and expansion or relocation plans. The purpose of the program is to inform these customers of " wise" energy utilization and future energy availability. Innovative engineering planning, design, and operation of new and present system facilities are other methods considered to conserve energy resources. Examples of these include the 1 following:
- a. studying the feasibility of compressed air, underground pumped hydro, and electrochemical cells to conserve scarce energy resources (petroleum and natural gas);
- b. peak load management with thermal energy storage 1 devices to make better use of off-peak energy as well as automatic meter reading systems with time of day meter reading capacity to permit implementation of load >r.anagement methods;
- c. research for solar energy utilization and the electric car;
- d. augmentation reservoirs for large nuclear and fossil plants to avoid capacity limitations due to cooling water makeup restrictions; at low flows augmentation
> reservoirs for large nuclear and fossil plants to avoid capacity limitations at low river flows due to 1 cooling water makeup restrictions;
- e. interchanges of power with neighboring utilities to conserve scarce fuels; and
- f. transmission and distribution engineering innovations to reduce energy losses.
During the past several years CECO, like other electric utilities, has found it necessary to increase its rates. 1.1-2 m
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 e- AMENDMENT NO. 3 ( ,3) MARCH 1982 Although this increase undoubtedly caused many customers to reduce consumption, CECO has no way of measuring this effect. 1 In addition to the increases in charges, CECO has significantly restructed its rates to more closely reflect the costs of providing electric service to different classes of customers at different times. Because the peak demand for CECO's service occurs on hot summer days, summer demand charges have been increased substantially more tnan the demand charges applicable in other months. Also, because production costs are higher during the heavy-load daytime and early evening hours of working days than during nighttime and early morning hours of such days or on weekends, CECO has a mandatory time-of-day rate that is applicable to its largest customers. Under these rates, kilowatthours used during on-peak hours cost substantially more than kilowatthours used during off-peak hours. While CECO is not certain of the extent to which such rate restructuring has resulted in energy conservation, the new rates offer incentives for customers to delay consumption from periods 1 when electricity is most costly to produce to periods when it is least expensive to produce. A shift of load from peak to off-peak times will result in a long-run capacity saving and probably (")3
\m an immediate oil saving since CECO is often operating combustion turbines or steam cycling units fired by expensive oil during peak hours. During.off-peak hours, oil is not often used.
Consumption shifted from peak to off-peak hours, therefore should reduce oil consumption by the use of coal or nuclerar fuel. 1.1.1 Load Characteristics 1.1.1.1 Load Analysis i I Table 1.1-2 shows the annual peak load demand and kilowatthour l consumption for the CECO system from 1962 to 1981. The estimated i annual peak load demand and kilowatthour consumption from 1982 3 l until 2001 are shown in Table 1.1-3. Since the Byron Station units will be in service for 30 to 40 years, it is difficult to project total CECO system-demand over their entire lifetime. '~ The load duration curve for the year 1980 is shown in Figure 1.1-16, and the supporting data are listed-in Table 1.1-4. Table 1 l 1.1-5 gives a monthly summary for 1980 of various load parameters. The year 1980 was used instead of 1981 because 1981
- was not a typical year. No new peak load was created in 1981 as 3 a result of abnormal weather conditions and reduced load due to The load duration curves for the years an economic recession.
1982, 1983, and 1984 should closely resemble the curve in Figure 1.1-16 since the annual load factors should be nearly the same. f)
' In 1984, with the first unit at the Byron station in service, the base load capacity will be about 68% of the total expected system l3 capacity. This amount of base load capacity is in accord with 1.1-3 J
Byron ER-OLS- AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCH 1982 industry-wide studies of economical generation mixes. It also agrees with CECO's generalized studies that indicate that base load generation is the most economical form of generation when operated over 3000 hours per year. Figure 1.1-17 is the daily load duration curve for Tuesday, July 15, 1980, which is the peak day for CECc through 1981. The 3 predicted peak load for 1980 was 14,750 MW, and the actual y recorded peak was 14,228 MW. Table 1.1-6 shows the data for that day. There were no firm power sales or purchases on that day, however, tnere were non-firm purchases. Due to a large amount of generation out of service and summer limitations, CECO was forced to import an additional 2025 MW to meet peak demand requirements. The predicted peak load for 1981 was 15,000 MW; unseasonably cool 3 weather and a weak economy held the actual peak to 13,299 MW. 1.1.1.2 Demand Characteristics 1.1.1.2.1 Load Forecasting Methodology Because of the long lead time required to install new generating units, forecasts of peak demand more than 10 years into the l3 future must be made. The demand forecasts offer a guide to the amount of new capacity required. Table 1.1-7 lists actual peak 1 demand and output for the years 1960 through 1981 and projections of peak demand and output through the year 2001. There are some readily apparent factors that can affect peak electrical loads, such as the level of business activity and weather. These two factors, however, are only a small part of a complex structure of economic, social, and psychological interactions affecting the demand for electricity. Because of 1 this complexity, the forecasting of electrical peak demands requires a high degree of judgment and involves unavoidable error. CECO attempts to minimize the forecasting error by using a multiple model approach refined by a multidisciplinary review committee. There are several forecasting techniques available, several of 1 which use statistical models that attempt to correlate the effects of many variables into a systematic series of projections. Regardless of the techniques employed, whether simple straight-line analyses or complex econometric models, there is at least one weakness cn mon to all: they rely on historical data and therefore cannot tcke into account new 1 factors. The best means of anticipating new factors is throngh informed judgment. Because of this deficiency, even the best model cannot always predict turning points or aberrations in long-run trends. The responsibility for forecasting annual peak demands is 1 assigned to CECO's Load Estimates Committee. This committee has 1.1-4 L
i s Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 O MARCH 1982 l 14 senior management members representing the following areas of CECO: Rates, Engineering, Division Operations, Marketing, System y Planning, Power Supply, Fuel and Budgets, Statistical Research,
. and Financial. Each member of the committee, because of his background within CECO, brings a different viewpoint and l judgmental approach into the decision-making process. The committee's forecasts, because of the influences of its various members, represent a balance of attitudes and judginents. The Load Estimates Committee meets at least twice a year, after the establishment of the year's summer and winter peak demands.
4 Meetings are held more frequently if conditions warrant. The forecasts, however, are not based upon judgment alone. ' Within CECO's Statistical Research Department'is a group of analysts with the necessary economic, mathematical, computer, and 1 other technical skills to analyze demands and develop mathematical models that can aid the Lead Estimates Committee. The techniques employed by this group have varied over recent years to accommodate changing conditions. i Up until the mid 1960's, the lead time required to build new generating units was 5 years or less. During the period up to 1973, load growth followed a regular pattern with electrical O- demands doubling approximately every 10 years. Trend lines, fitted to various periods of growth in demand, could have provided adeouate guidance for the Load Estimates Committee to make its decisions. During the committee's deliberations in the l
- mid 1960's, there was a growing awareness that changes were occurring. For example, since 1964, the summer peak demand has also been the peak demand for the year. As a result, different models were developed and analyzed in an attempt to isolate changes and improve the forecasting guides. Such models have since provided one of the bases for CECO's official demand estimates. One of these models, referred to as Model I, was developed in 1966, and through the years underwent considerable modification as knowledge of its operation and reliability progressed. A major drawback of Model I has been its inability to explain demand responses based on the fluctuation of energy prices. It was determined that Model I could no longer contribute significantly to the load forecasting process, and it 1 i was eliminated as a forecasting tool. Model II, which was a single equation model, was altered and became Model III, which is j a two equation model.
i Models III, IV, V, and VI are more sophisticated econometric models that attempt to explain some of-the changes in demand patterns that have occurred since the Arab oil embargo in late 1973. Models IV and V were chosen for consideration by the Load () Estimates Committee in its deliberations on the 1981-1990 peak load forecast. Model III was not explicitly considered by the committee due to its similarity to Model IV in specification and Model VI is a three-equation peak load 3 forecasting results. 1.1-5 i
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCH 1982 model, disaggregated by customer classes. Developmental work l continues on the data base for Model VI in an effort to stabilize its statistical results. The load forecasting staff is continually reviewing the latest forecasting techniques and testing the models in many ways. Traditional statistical measures to determine correlation, standard error of estimate, goodness of fit, and so forth are used. However, the output of any model is only as good as the input data and the user's understanding of the working of the medel. In addition, the models are constantly analyzed by altering the method of estimation, examining and redefining 1 explanatory variables, and by testing experimente.1 variables. CECO is proceeding cautiously and systematically to improve tne input and test the functioning of each model and to develop new models. The sections that follow provide a detailed description of the two econometric models considered by the Load Estimates Committee in preparing the 1982-1991 peak load forecast. 3 1.1.1.2.2 Econometric Model IV Model IV is an econometric peak load model developed in 1977 and has the following noteworthy characteristics:
- a. The model consists of two equations, one for the base O load and the other for the weather sensitive load.
The combination of the two yields the peak load forecast.
- b. The model obtains estimates of the parameters using a method called Seemingly Unrelated Regression (SUR).
This method was not used on previous forecasting models.
- c. The model includes the Illinois Gross State Product 3 l
variable, which was revised in 1980 from an annual figure to an annualized third quarter value. The explanatory variables in Econometric Model IV are given in the following list. Detailed descriptions of these variables are provided in Table 1.1-8. 1 O 1.1-6
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCH 1982 Os Base Load Equation Weather Sensitive Load Equation la. Real price index of Ib. Number of residential electricity to all CECO central air conditioners. customers (Average Price) 2a. Price lagged 1 year 2b. Two weather variables representing a long-term heat build-up and a temperature-humidity index. 3a. Price lagged 2 years 4a. Price lagged 3 years Sa. Price lagged 4 years 6a. Illinois Gross State Product (Income) 7a. CECO customer index (number of customers) Ba. Real price index of natural gas in Illinois (price of 1 competing fuels) 9a. Dummy variable to account for low base load observations in 1974 and 1975 Model IV is a two equation model, one for base load and the other Each year enters monthly' peak data for weather sensitive load. Observations for June, July and August. are expressed as first differences of the natural logarithms. The 1981 statistical 3 results of Model IV may be found in Table 1.1-9. The method of estimation used is the Seemingly Unrelated Regression. The general form of the model equation is as follows: +u Dln (MW) = bo + b Din (X )t + b, Din (X,)t + ... + b n Di n(Xn )t t where: b = coefficients determined by regression, X = explanatory variables, Din = difference in natural logarithms of two observations one year apart, l 1.1-7 J
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Byron ER-OLS~ _ AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCH 1982 u = error term, and MW = dependent variable (base load or weather sensitive load). 1.1.1.2.3 Econometric Model V Model V is an econometric peak load model developed in 1979 that has the following distinctive features:
- a. The model has one equation and uses ordinary least squares regression to obtain estimates of the parameters,
- b. The model uses the three highest reconstructed peak loads as dependent variables. In contrast, the dependent variables in Model IV are selected from the set of actual monthly peak loads from June, July, and August, and these actual peaks are then reconstructed. The highest reconstructed peak load is not necessarily equal to the highest actual load that is later reconstructed.
- c. The model considers the real marginal price of electricity that is expressed as a weighted average 1 based on a polynomial distributed lag function.
- d. The model ecuation was modified in 1980 to include a 3 variable that is the product of DBT 2 hours prior to peak and the number of residential air conditioners.
The explanatory variables in Econometric Model V's present form for the peak load equation are listed below. Detailed descriptions of these variables are shown in Table 1.1-10.
- 1. Real price index of electricity (weighted average marginal price, index is polynomial distributed lag function)
- 2. Real per capita income in Chicago SMSA
- 3. Number of residental air conditioners times the dry bulb temperature 2-hours prior to peak
- 4. Dummy variable to account for low base load observations in 1974 and 1975
- 5. Two weather variables representing weather conditions just prior to peak and long-term heat build-up conditions Model V is a single equation model. Each year enters data for three highest reconstructed peak load days. Observations are expressed as the first difference of the natural logarithms. The 1981 statistical results of Model V are shown in Table 1.1-11. 3 lll 1.1-8 i
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 () MARCH 1982 The method of estimation used is the Ordinary Least Squares Regression. The general form of model equation is as folloss: Dln(MW) = bo+b3 Dln (X )t +b, Dln (X,)t + ... + bn Dln 'Xn )t +u t where: b= coefficients determined by regression, X= explanatory variables, Dln = difference in natural logarithms of two observations one year apart, u= error term, and MW = dependent variable (peak load). 1.1.1.2.4 Explanatory Variable Proiections
/"T To forecast the peak demand for electricity with an econometric
\_s/ model, future values of the explanatory variables used in the j model must be projected.. The quality of the explanatory variable 1 projections directly affects thq quality of the model's forecast.
Imprecise projections of income, number of customers, prices and other variables can result in a poor forecast, even with the most sophisticated of econometric models. The load forecasting staff employs a number of mathematical methods in projecting explanatory variable values, such as l historical growth rates, trend lines, and Box-Jenkins techniques. i Wherever possible, as a further validity check, these projections are compared to those made in other responsible forecasts. 1 Sensitivity analyses are performed on individual variable projections to determine the effect a range of values would have on the final forecast. The Load Estimates Committee is responsible for determining the final set of projections used in each model. These projections require a good deal of judgment, and affect the range and accuracy of the model's forecast. The importance of judgment in affecting the model forecast is the reason that model outputs are not directly adopted as official peak load forecasts. Table 1.1-12 shows the 1981 explanatory variable projections 3 approved by the Load Estimates Committee on October 19, 1981. To project values for weather variables, CECO assumes that average
' peak-making weather will prevail throughout the forecast horizon.
The 20-year average peak-making weather values for weather variables in Models IV and V are shown in Table 1.1-13. 1.1-9 _ _. , . . . . _ _ _ _ - . _ _ _ _ . . - , _ _ . - _ - . . _ . _ _ _ _ . _ _ _ . . - ~ . . _ _ _ _ __ _
( -, s . Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCH 1982 1.1.1.2.5 Growth Perceptions by Others Growth perceptions by others for both electricity and the economy are reviewed by the Load Estimates Committee. Various comparative growth rates and forecasts made by associations and trade groups are presented for comparison in Table 1.1-14. The committee noted that the most recent forecasts seemed not to reflect as great a reduction in expectations as last year, which could indicate that the recent pattern in downward revisions in long-term expectations might be flattening out or in some cases reversing. CECO's average annual peak load forecast of 2.0% 3 appears reasonable when compared to other electricity growth estimates. 1.1.1.2.6 End Use Consid';ations 2 Econometric models have been the primary input to peak demand forecasting. These models rely on the historical relationships of their explanatory variables in order to predict future peak loads. They can, therefore, be insensitive to changes in demand patterns that have no historical precedent. Acknowledging that usage patterns do change over time, CECO is investigating and developing " engineering" or "end use" models in an attempt to isolate the effects of these changes. An end use model examines the impact that specific types of energy-using equipment, such as residential air conditioners, have on peak demand. By incorporating such variables as deman_d per unit, percentage of units operating and appliance saturation, these models can be sensitive to changes resulting from such developments as increasing efficiency standards, pricing responses, and load management. It is impractical to develop end use models for all uses of electricity, and it is difficult to expand these models to account for the total peak load. However, an end use model contributes a sensitivity to factors affecting appliance usage, and can be used to complement econometric models, particularly when these factors are expected to deviate from historical trends. 1.1.1.2.7 Development of Peak Load Estimates 3 During its deliberations, the Load Estimates Committee reviewed and discussed model results and the underlying assumptions of future economic conditions involving such matters as business activity, housing starts, expected number of customers, relative vitality of the service area, prices and availability of alternative energy sources, evolving technologies, appliance saturations, and regulatory considerations. The results from the forecasting methodologies and the committee's knowledge of activity in CECO's service area indicated that consumer patterns 1.1-10
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 (~T ( ,) MARCH 1982 may be changing such that electric demand will increase at a lower rate than previously forecast. Several specific points were made during the deliberations:
- a. The change in model results from this year to last year would suggest a decrease in peak load growth rate of less than one percentage point.
3
- b. After adjusting for the recession and the weather, the 1981 peak load would suggest that growth rates will remain well below levels experienced before the 1973 oil embargo.
- c. A major portion of the electric energy conservation effort thus far has been price induced rather than voluntary. Although it is not possible to quantify the conservation impact, the substantially lower growth rates since the oil embarga would indicate that it has been significant. The future impact of conservation is not certain. It is possible that most of the cost-effective conservation measures have already been taken, making future efforts more
/~)
V difficult.
- d. This year's analysis of policy issues suggested a possible negative net impact on future peak load 1 growth.
In light of indications by the models, opinions of others, and the best judgment of the committee, it was proposed that a peak load forecast of 2.0% was reasonable given the available information. All members of the committee concurred and a 10-year forecast showing an average annual compound growth rate ! of 2.0% was adopted. In addition, the committee agreed upon a 3 high-growth scenario of 3.0% and a low-growth scenario of 1.0%. These rates approximate the gain or loss of five-years' growth by 1991. l The Load Estimates Committee reviewed and approved the 1982-1991 low, most likely, and high peak load estimates listed in Table 1.1-15. The committee also reviewed estimates from CECO's models and the explanatory variable assumptions used in them, the economic outlook for CECO's service territory, outside economic and industry forecasts, and growth rates of recent periods. The models provided the following 10-year forecasts: Model IV 1.9% 3 Model V 2.4% 1.1-11
]
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCH 1982 Based on all factors presented in the preceding discussions, the Load Estimates Committee approved the following 1982-1991 average annual compound peak load growth rates: Low Growth 1.0% 3 Most Likely Growth 2.0% High Growth 3.0% 1.1.1.2.8 Forecasting with the Models A comparison of past CECO demand projections and the actual loads experienced are presented in Table 1.1-16. The estimates, expressed as percentages of the actual peak loads, are presented in Table 1.1-17. Estimates for all years before 1974 deviate, on the average, only 2.7% from the actual peak load. Estimates for the years after 1973 are, of course, based on a normal business cycle--the Load Estimates Committee did not anticipate the oil 1 embargo and the ensuing energy crisis. Furthermore, estimates expressed as percentages of the " reconstructed" peak load (see Table 1.1-18) indicate that estimates for years before 1974 deviate, on the average, 2.1% from the " reconstructed" peak demand. The " reconstructed" peak load (calculated for the years 1959-1981 on Table 1.1-19) adjusts the actual peak load to its l true potential by reflecting estimated load reductions caused by industrial vacations, voltage reductions, electric furnace interruptible service, etc. Monthly data for peak load and energy appear in Table 1.1-20. Both the actual and the estimated megawatthours sold from January 1973 through the most current month available are given in the table. 1.1.1.3 Power Exchangec Table 1.1-21 shows the net power exchanges at the time of the past annual peak loads from 1962 to 1981. The expected net power 3 exchanges for 1982 through 1990 are also shown. 1.1.2 System Capacity Required system capacity is predicated on the forecasts by the Load Estimates Committee. As discussed earlier, three forecasts are made based upon an expected estimate that is bracketed by a high load and a low load estimate. Generation capacity additions are proposed for each of the three load growth plans. The intent of the capacity additions is to provide capacity sufficient to meet system demand, total kilowatt-hour production requirements, and a required reserve 1 h margin to cover generation outages. CECO uses a 15% minimum 1.1-12 L
c Byron ER-OLS AMENDMENT NO. I JULY 1981 AMENDMENT NO. 3 rS MARCH 1982 ( ,) reserve margin for generating facilities. The reserve margin l1 consists of CECO-owned generating capacity less firm sales and summer limitations plus firm purchases, diversity exchange, and the Ludington purchase less the expected yearly peak load. Generation facilities are added to the CECO system by choosing the type of generating facility that will not only provide kilowatt capacity, but when added to the existing generating system, will most economically satisfy the load. A production costing computer program called PROMOD, which simula tes the CECO generation schedule and economically loads the units according to y their fuel cost, is used by CECO to make choices of potential generation additions. The program not only determines how the unit will operate, but also how it will affect the operation of all the other units. PROMOD can forecast sufficiently far into the future to measure the impact of a generating unit over a broad time horizon. As additional units are added in succeeding years to satisfy kilowatt demand and kilowatt hour consumption, the resulting mix of units will be loaded to satisfy requirements according to the economic operation of the units. Table 1.1-22 lists the new generating units planned between 1982
/~T and 1991. Ridgeland Station. Units 1-4 are scheduled to be
(_) retired in 1982. The projected unit capabilities and capacity 3 factors for the units listed in Table 1.1-1 are shown in Table 1.1-23. These capacity factors through 1991 are predicated 1 on CECO's load growing according to CECO's official load growth estimates and on planned new generating units being added according to the tabulation in table 1.1-22. The capacity factors for these units will change if either the generation addition pattern (see Table 1.1-22) or the peak load growth pattern is changed. 1.1.3 Renerve Margins and Generatina System Reliability Generating system reliability for an electric utility is a function of many parameters among which is system reserve margin; number, size, and forced outage rate of each type of generating unit; system load profile; uncertainty of load forecast; strength of interconnections to other systems; and planned generating unit maintenance. Utilities attempt to directly control the level of 1 system reliability by installing additional generating capacity This reserve margin serves to achieve a target reserve margin. to provide, in part, the necessary added generating capability to prevent interruption of customer load when generating units fail and are forced out of service. O v 1.1-13 2
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCH 1982 1.1.3.1 Percent Reserve Margin Expressing reserve margin as a percent of system annual peak load is a convenient way of stating reserve margin levels. CECO plans new generating capacity to result in a 15% target reserve margin level. Loss of Load Probability (LOLP) studies indicate that 15% planned reserve, in conjunction with expected help from interconnections, will result in an LOLP of about 1 day in 10 1 years. Furthermore, CECO has planned for this level over a period of many years and the result has been a high degree of generating system reliability. Although this 15% reserve margin is somewhat lower than the margins used by many companies, CECO believes it adequate because of their strong interconnections. 1.1.3.2 Interconnections The role of interconnections is extremely critical to generating system reliability. They allow reserves of one utility to be shared with those of neighboring utilities, raising the overall reliability level of both utilities. The net result is that each utility benefits by needing lower reserve levels and thus less generating capacity to achieve a desired degree of reliability. In fact, LOLP studies have shown that CECO would require reserve margins of more than 30% were it not for interconnections. Table 1.1-24 summarizes load and capacity projections for peak h periods from 1982 through 1991, and shows the estimated reserve l3 margin for each year. Reduced load estimates following the Arab oil embargo and the subsequent recession have had a significant effect oa the relationship between planned capacity and estimates of future loads and capacity requirements. 1.1.4 External Supporting Studies Because reliability is a region-wide concern and not just an individual utility concern, CECO relies heavily on the work done by the MAIN Guide 46 Working Group in which it is an active participant. MAIN Guide #6, " Procedure of Generation Reserve Requirements," (1972) establishes a procedure for determining minimum generation reserve requirements for tiAIN as an aid in planning future 1 generation. The MAIN Executive Committee in November 1978 revised MAIN Guide 46 adopting the LOLP method for the determination of minimum generation reserve requirements for MAIN and a criterion of a LOLP of 1 day in 10 years as an aid in planning future generation. Before that, MAIN used the Probability of Positive Margin method, which is a less sophisticated tool than LOLP. 1.1-14
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCH 1982 (Vm) TABLE 1.1-1' EXISTING CECO GENERATING UNITS FOR THE SUMMER OF 1982 TYPE or YEAR Or NET CAPABILITY (MW) STATION - UNIT UNITa INSTALL. itINTER SUMMER Bloom T.S.S. 33, 34 P 1971 126 103 Calumet 31-34 P 1969-70 276 220 O 1978 554 554 Collins Collins 1 2 O 1977 554 554 1 Collins 3 0 1977 530 530 Collins 4 0 1978 530 530 Collins 5 0 1979 530 530 Crawford 7 C 1958 216 213
- 8 C 1961 326 319 31-33 P 1968 189 149 l1 Dresden I b N 1960 207 197 2 N 1970 794 772
- 3 N 1971 794 773 Electric Junction 31-34 P 1970-71 243 193 y risk 19 C 1959 321 316 20 D 1966 11 11 31-34 P 1968 231 157 Joliet 6 C 1959 308 298
" 7 C 1965 503 499 8 C 1966 522 518
[ " 9 D 1967 11 11 ( " 31, 32 P 1969 1967 131 554 103 554 Kincaid 1 C 2 C 1968 554 554 LaSalle 1 N 1982 1078 1048 3 Lombard 31-33 P 1969 136 108 Powerton 5 C 1972 700 700 6 C 1975 700 700 Quad-Cities" 1 N 1972 591 576 2 N 1972 592 577 3 Sabrooke 31-34 P 1969-70 135 109 1
' State Lane 3 4
C C 1955 1962 187 318 187 318 l3 Waukegan 6 C 1952 100 100 1 7 C 1958 328 328 8 C 1962 297 297
- 31, 32 P 1968 150 113 Will County 1
'C 1955 106 101 1 2 C 1955 154 148
" " C 1957 262 251 3
4 C 1963 520 510 Zion 1 N 1973 1040 1040
" N 1974 1040 1040 2
[h " KEY: N
- Nuclear, C = Coal, O = Oil, P = Peaking, and D = Diesel,
'( k bDresden Unit 1 is taken out of service for chemical cleaning. l3 CThe capability figures indicate CECO's 2/3 ownership of Cuad Cities Stations Iowa-Illinois E6G's 1/3 interest represents a 296 MW and 288 MW capsbility for winter and summer, respectively. 1.1-15
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCH 1982 TABLE 1.1-2 O ACTUAL CECO SYSTEM PEAK LOADS AND OUTPUT TOTAL PEAK LOAD SALES PEAK LOAD OUTPUT DATE (MW) (MW) (MW) (1,000 x MWh) 1962 (Aug. 24) 5,143 78 5,221 28,165 1963 (July 1) 5,372 94 5,466 30,037 1 1964 (Aug. 3) 6,102 115 6,217 32,352 1965 (July 23) 6,468 97 6,565 34,788 1966 (July 12) 7,491 150 7,641 38,189 1967 (June 15) 7,643 255 7,898 40,018 1968 (Aug. 23) 8,950 92 9,042 43,457 1969 (July 16) 9,265 154 9,419 46,972 1970 (July 2) 10,027 67 10,094 49,751 1971 (June 28) 10,943 30 10,973 52,144 1972 (Aug. 18) 11,750 241 11,991 56,063 1973 (Aug. 27) 12,462 241 12,703 60,058 1974 (July 19) 12,270 80 12,350 59,274 1975 (Aug. 1) 12,305 40 12,345 60,310 1976 (July 14) 12,907 59 12,966 62,567 1977 (July 15) 13,932 132 14,064 65,1102 1978 (Sept. 8) 13,720 57 13,777 67,927 1979 (Aug. 7) 13,804 0 13,804 67,650 1 1980 (July 15) 14,228 0 14,228 66,946 1981 (July 8) 13,299 0 13,299 66,199 l3 O 1.1-16
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 O' MARCH 1982 , TABLE 1.1-3 ESTIMATED CECO SYSTEM PEAK LOADS AND OUTPUT i PEAK LOAD SALES TOTAL PEAK LOAD OUTPUT DATE (.MW) (MW) (.MW) (1,000 x MWh) 1982 14,650 - 14,650 67,600 1983 15,050 - 15,050 69,300 1984 15,450 - 15,450 70,850 1985 15,750 - 15,750 72,450 1986 16,050 225 16,275 74,100 1987 16,350 - 16,350 75,750 i 1988 16,700 - 16,700 77,650 1989 17,050 - 17,050 79,600 n' A- 1990 17,400 - 17,400 81,600 1991 17,750 - 17,750 83,650 1 3 1992 18,100 - 18,100 85,750 1993 18,450 - 18,450 87,900 1994 18,800 - 18,800 90,100 1995 19,200 - 19,200 92,350 1996 19,600 - 19,600 94,650 1997 20,000 - 20,000 97,000 1998 20,400 - 20,400 99,450 1999 20,800 - 20,800 101,950 2000 21,200 - 21,200 104,500 2001 21,600 - 21,600 107,100 1.1-17
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 TABLE 1.1-4 CECO'S ANNUAL LOAD DURATION CURVE FOR 1980 PERCENT OF MINIMUM PERCENT OF MINIMUM PERCENT OF MINIMUM PERCENT OF MINIMUM PEAK LOAD HOURS PEAK LOAD HOURS PEAK LOAD HOURS PEAK LOAD HOU RS 1 8784 26 8784 51 4825 76 305 2 8784 27 8784 52 4627 77 280 3 8784 28 8783 53 4408 78 254 4 8784 29 8776 54 4188 79 221 5 8784 30 8763 55 4000 80 201 6 8784 31 9738 56 3795 81 185 7 8764 32 8713 57 3590 82 167 8 8784 33 8668 58 3366 83 152 9 8784 34 8601 59 3129 84 135 10 8784 35 8493 60 2831 .3 116 11 8784 36 8377 61 2542 86 10 '. 12 8784 37 8180 62 2282 87 85 13 8784 38 7974 63 2049 88 72 14 8784 39 7746 64 1835 89 57 15 8784 40 7528 65 1610 90 44 16 8784 41 7278 66 1412 91 34 17 8784 42 7051 67 1183 92 24 18 8784 43 6794 68 981 93 17 19 8784 44 6532 69 796 94 17 20 8784 45 6263 70 664 95 13 21 8784 46 6005 71 551 96 12 22 8784 47 5736 72 465 97 7 23 8784 48 5505 73 411 98 4 24 8784 49 5265 74 360 99 4 25 8784 50 5042 75 333 100 1 Notes: ' Maximum Load for Period: 14,228 MW Maximum Load Occurred on: July 15 Minimum Load for Period: 3962 Mw Minimum Load Occurred cn May 26 Total Energy for Period: 67,029,760 Mwh Load Factor for Period: 53.64 i O 1.1-18
TABLE 1.1-5 MONTHLY SUMMRY FOR 1980 PERCENTAGE l, MAXIMUM MINIMUM MEAN LOAD ENERGY OF YEAR'S MONTH LOAD (MW) LOAD (MW) LOAD (MW) FACTOR (TWU) MAXIMUM JAN 10,715 5,255 8,244 0.769 6.13 75.31 FEB 10,252 5,627 8,188 0.799 5.70 72.06 MAR 10,000 5,066 7,696 0.770 5.73 70.28 r to 4 g APR 9,597 4,185 7,011 0.731 5.05 67.45 5 z
'w 10,126 3,962 6,636 0.655 4.94 71.17 s MAY JUN 12,892 4,182 7,200 0.558 5.18 90.61 6 j e 1
- 100.00
~
JUL 14,228 4,047 8,503 0.598 6.33 AUG 13,838 4,364 8,484 0.613 6.31 97.26 . SEPT 11,227 4,425 7,304 0.651 5.26 78.91 rg ' OCT 9,515 4,788 7,118 0.748 5.30 66.88 @m
<z NOV 9,694 4,834 7,271 0.750 5.23 68.13 sE l DEC 10,577 4,816 7,896 0.747 5.87 74.34 *8
' 2 , ? YEAR 14,228 3,962 7,631 0.536 67.03 - g i I l
s Byron ER-OLS AMENDI1ENT NO. 1 JULY 1981 TABLE 1.1-6 LOAD CilARACTERISTICS ON CECO'S SYSTEM'S PEAK DAY: JULY 15, 1980 MINIMUM MINIMUM PERCENT OF !!OURS OF PERCENT OF liOURS OF PEAK LOAD DURATION PEAK LOAD DURATION 1 24 36 24 2 24 37 24 3 24 38 24 4 24 39 24 5 24 40 24 6 24 41 24 7 24 42 24 8 24 43 24 9 24 44 24 10 24 45 24 11 24 46 24 12 24 47 24 13 24 48 24 14 24 49 24 15 24 50 24 16 24 51 24 17 24 52 24 18 24 53 24 19 24 54 24 20 24 55 24 21 24 56 24 22 24 57 24 23 24 58 24 24 24 59 24 25 24 60 23 26 24 61 21 27 24 62 21 28 24 63 21 1 29 24 64 20 30 24 65 20 31 24 66 18 32 24 67 18 33 24 68 18 34 24 69 18 35 24 70 17 1.1-20
Byron ER-OLS MiENDMENT NO. 1 JULY 1901 O TABLE 1.1-6 (Cont'd) MINIMUM. MINIMUM PERCENT HOURS OF PERCENT OF HOURS OF PEAK LOAD DURATION PEAK LOAD DURATION 71 17 86 13 i 72 17 87 13
- 73 17 88 13 1
74 17 89 13 I 75 17 90 12 76 16 91 12-77 16 92- 10 78 15 93 8 1 79 15 94 8 80 15 95 8 i 81 15 '36 7 82 15 97 6 83 15 98 4 84 15 99 4 85 14 100 1 Note: Maximum Load for Period: 14,228 MW O Minimum Load for Period: 8,519 MW Total Energy for Period: 285,725 MWh 1 Load Factor for Period: 83.7% 1.1-21 _J
Byron ER-OLS AMENDMENT NO. 1 JU'LY 1981 AMENDMENT NO. 3 fuiRCII 1982 TABLE 1.1-7 ACTUAL AND LONG RANGE ESTIMATED SYSTEM PEAK LOADS AND OUTPUT REQUIRED FOR SALES TO ULTIMATE CONSUMERS AND MUNICIPALITIES FOR YEARS 1960 TO 2001 PERCENT GUMMER INCREASE OVER INCREASE ANNUAL PEAK LOAD PREVIOUS YEAR OUTPUT OVER LOAD YEAR, (MW) "fMW) FERClisi (GWh) PREV. YEAR FACTOR 1960 4,590 357 8.4 24,822 5.1 59.8 1961 4,840 250 5.4 26,178 5.5 60.1 1962 5,143 303 5.9 28,165 7.6 60.9 1963 5,372 229 4.5 30,037 6.6 62.0 1 1964 6 102 730 13.6 32,352 7.7 58.5 1965 2,468 366 6.0 34,788 7.5 59.5 1966 7,491 1,023 15.6 38,189 9.8 58.2 1967 7,643 152 2.0 40,018 4.8 59.8 1968 8,950 1,307 17.1 43,457 8.6 55.3 1969 9,265 315 3.5 46,972 8.1 57.9 1970 10,027 762 8.2 49,751 5.9 56.6 1971 10,943 916 9.1 52,144 4.8 54.4 1972 11,750 807 7.4 56,061 7.5 54.3 1973 12,462 712 6.1 60,058 7.1 55.0 1974 12,270 192* 1.5* 59,274 1.3* 55.1 1975 12,305 35 0. 3 60,310 1.7 56.0 1976 12,997 602 4.9 62,567 3.7 55.2 1977 13,932 1,025 7.9 65,110 4.1 53.3 1978 13,720 212' l.5* 67,927 4.3 56.5 1979 13,304 84 0.6 67,650 0.4* 55.9 1980 14,228 424 3.1 66,946 1.0* 53.7 198a 13,299 929* 6.5* 66,199c 1.1* 56.8
-------------Estimsted d ----------------- -----------------Estimated'----------------
1982 14,650 1,351 10.2 67,600 2.1 52.7 1983 15,050 400 2.5 69,300 2.5 52.6 1984 15,450 400 2.5 70,850 2.25 52.3 1905 15,750 300 2.0 72,450 2.25 52.5 1986 16,050 300 2.0 74,100 2.25 52.7 1997 16,350 300 2.0 75,750 2.25 52.9 l 1988 16,700 350 2.0 77,65n 2.5 53.1 1989 17,059 350 2.0 79,600 2.5 53.3 1990 17,400 350 2.0 81,600 2.5 53.5 3 1991 17,750 350 2.0 83,650 2.5 5'.8 1992 18,100 350 2.0 85,750 2.5 54.1 1993 19,450 350 2.0 87,900 2.5 54.4 1994 18,800 350 2.0 90,100 2.5 54.7 1995 19,200 400 2.0 92,350 2.5 54.9 1996 19,600 400 2.0 94,650 2.5 55.1 1997 20,000 400 2.0 97,000 2.5 55.4 1998 20,400 400 2.0 99,450 2.5 55.7 1999 20,800 400 2.0 101,950 2.5 56.0 2000 21,200 400 2.0 104,500 2.5 56.3 2001 21,600 400 2.0 107,100 2.5 56.6 Note Asterisk (*) indicates decrease. doutput estimates are Lased on & 365-day year. b Excludes Lincoln & Albion. cReissued to show actual 1981 output. d For the period 1982-1991: Peak laad estimat es approved October 26, 1981; Output estimates approved November 4, 1981. Estimates beyond 1991 are not official and are extrapolated from 1991 estimates. t ePeak load and autput e s t ina t e s are derived f r om the eat inated perceritage changes as shown, rcunded to the nearest 50. 1.1-22 t
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 6
~s)
TABLE 1.1-8 DEFINITION OF EXPLANATORY VARIABLES USED IN MODEL IV Aggregate Real Price Index of Electricity (Average Price): An average cost per kilowatthoar is computed for several representative customers in the residential, small commercial and industrial, and large commercial and industrial classes, using August 1 rates for the year in question. These costs are then weighted to obtain an average cost per kilowatthour for each class. The fuel adjustment charge and state tax are added to the price charged to all three customer classes. The prices to the three customer classes are combined using a weighted average. Each weight represents an estimate of a class's percent contribution in kilowatts to the 1967 summer peak, normalized so that the sum of the weights equals one. The nominal price is then divided by an index of the average price of all other goods and services (e.g., CPI, 1967=100) This real price is I_s in order to arrive at a real price.
\- ') indexed such that 1967=100.
Price Lagged 1, 2, 3, and 4 Years: The above Real Price index of Electricity for each of the four years preceding 1 the year in question. Illinois Gross State Product (Income): The Illinois Department i I of Commerce and Community Affairs publishes a historical I series on This the Illinois Gross State Product deflated to 1972
" income" variable is used to represent the dollars.
gross income of Commonwealth Edison customers, thereby reflecting their addition of electric appliances and housing, an improved standard of living, increased commercial and industrial activity, etc. Dummy Variable for Low Base Load Observations in 1974 and 1975: This variable is set to one in the base load equation for 1974 and 1975 observations and to zero for all other observations. This' variable attempts to reflect the dis-l continuities of 1974 and 1975 brought about by the Arab oil l l embargo. Real Price Index of Natural Gas in Illinois: The industry average price (S/106 Btu) of natural gas in Illinois is divided by an index of the average price of all other goods (~} (my and services (CPI, 1967=100) to obtain the real price. The I series is in'dexed such that 1967=100. 1.1-23
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCH 1982 TABLE 1.1-8 Number of Residential Air Conditioners: Estimate of the percentage of CECO residential customers that have the equivalent of central air-conditioning, multiplied by the number of residential customers: Two Weather Variables: (1) Cumulative Cooling Degree Days (CDD) from May 15: The number of CDD are totalled from May 15 through the peak i demand day in June, July and August for the years 1967-1981. l3 (2) Pour-Day Weighted Average Temperature Humidity Index (THI): The second weather variable is the THI at the time of the system peak and the THI's at the hour of the daily peaks 1, 2, and 3 days before the system peak. Weights are developed and applied to each of the four THI observations in June, July and August for the years 1967 through 1981 to provide a representation l3 short-term heat buildup. O l O 1.1-24
I , [
! D \_/ \
4 1 TABLE 1.1-9 l l MODEL IV USING 1967-1981 OBSERVATIONS 3 REGRESSION STANDARD EQUATION VARIABLE COEFFICIENT T-STATISTIC ERROR _ Base Load Intercept 1.54314 2.3418 0.65895 j Customer Index 0.11671 0.2483 0.47006 Illinois Gross State Product 0.76304 6.3761 0.11967 Real Price Index of Natural Gas -0.08967 -1.7292 0.05186 Dumy Variable 1.60754 1.7443 0.92158
.Real Price Index of Electricity -0.14238 -2.0417 0.06996 ~
Price Lagged 1 Year 0.02804
-0.14539 0.4991
-2.3405 0.05618 0.06212.
Price Lagged 2 Years g
. Price Lagged 3 Years -0.10333 -1.6982 0.06084 a i7 Price Lagged 4 Years -0.23952 -3.8217 0.06267 1 3 to ; $ Y O
l Weather Sensitive Load Intercept -0.63806 -0.2342 2.72414 [ j Total Cooling Degree Days Since May 15 0.07108 1.7030 0.04174 Temperature Humidity Index 4.23161 9.6399 0.43897 Residential Central Air Conditioners 0.62936 2.9582 0.21275 Note: System R2 = 0.8353
=
x $ e e, O Z H: Z mO O i-3H2 H tn o tn W Z CD Z co8HH Z Z-
.O .O h
yr n ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 TABLE 1.1-10 MARCH 1982 DEFINITIONS OF EXPLANATORY VARIABLE USED IN MODEL_V O Real Price Index of Electricity (Marginal Price) : Most CECO customers fall into one of three classes: residential, small commercial and industrial (SC&I), or large commercial and industrial (LC&I). These three customer classes comprise well over 90% of the load on any summer peak day. A marginal or incremental price is computed for a representative customer of each class, using August 1 rates for the year in question. The residential customer's incremental price is considered the tail block of Rate 1; the SC&I's price is the energy charge at 1,500 kWh under Rate 6 plus the charge in lieu of demand; and the LC&I's price is the energy charge at 1,600,000 kWh and the incremental demand charge using a 56% load factor assumption under Rate 6L. The fuel adjustment charge and state tax are added to the price charged to all three customer classes. The real marginal price of electricity is expressed as a weighted average based on a polynomial distributed lag function. Real Per Capita Income in Chicago SMSA: Total personal income in the Chicago SMSA as published by the Illinois Bureau of the Budget is divided by the Chicago SMSA population. Per capita income is deflated using the Chicago Consumer Price Index (1967=100) to obtain real per capita income. This variable is used to represent the per capita income of CECO residential customers, thereby reflecting their improved standard of living, addition of electrical appliances, etc. 1 Air Conditioning Saturation and Heat Indication: The number of CECO residential customers who have the l3 equivalent of central air conditioning, multiplied by dry-bulb temperature 2 hours before the peak. Dummy Variable for Low Base Load Observations in 1974 and 1975: See Model IV definitions in Table 1.1-8. Two Weather Variables: (1) Cumulative cooling degree days (CDD) from May 15: The number of CDD are totaled from May 15 through the date of the observation for each of the three highest reconstructed peak load days. (2) A weather index: This is used to reflect peak day heat build-up conditions by combining peak day minimum morning temperature ( F) with dry-bulb temperature ( F) two hours before peak load occurrence. O 1.1-26
O O O i 4 k TABLE 1.1-11 MODEL V USING 1967-1981 OBSERVATIONS 3 i REGRESSION STANDARD VARIABLE COEFFICIENT T-STATISTIC ERROR i } EQUA"' ION l Peak Load Intercept 1.29678 1.6908 0.76695 Number of Air Conditioners x Dry Bulb temperature 0.21876 2.9288 0.07469 ' 4 Peak Day Heat Build-Up Weather Index 0.63798 5.9956' O.10641 f to H Total Cooling Degree Days Since May 15 0.01624 2.5921 0.00627 )O
+
D 1 H Weighted Average Real Marginal Price of 1 3 I b Electricity -0.35861 -1.7748 0.20206 $: , w O Dummy variable -2.88248 -2.7091 1.06399 ta vs ! Real Per Capita Income 0.93071 5.3819 0.17293 Note: R2 = 0.8995 NM
> C3 T t1 M l
O. Z >< Z
.I: O O 3H3 HMeM e Z c3 2 mdHd i
N 2 z ! O O l i t
Byron ER-OLS ARENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 TABLE 1.1-12
SUMMARY
OF ASSUMPTIONS USED ON EXPLANATORY VARIABLES lO-YEAR VARIABLE GROWTH RATE Illinois Gross State Product 1.9% Real Per Capita Income 1.2% Real Price of Electricity - Marginal 0.5% Real Price of Electricity - Average 0.5% 1 3 Real Price of Natural Gas in Illinois 4.4% Customer Index 1.1% Residential 1.3% C&I Customers Inside Chicago -2.1% C&I Customers Outside Chicago 2.3% Air Conditioning Saturation 1.5% Residential Equivalent Central Air Conditioners 2.8% Weather Average Peak - Making Weather O 1.1-28
UU" ~ AMENDMENT NO. 1 JULY 1981 C'\ f\'/ TABLE 1.1-13 DOCUMENTATION OF WEATHER VARIABLE PROJECTIONS: 20-YEAR (1961-1980) AVERAGE PEAK-MAKING WEATHER VALUES FOR SUMMER PEAK LOAD DAYS PARAMETER AVERAGE VALUE MODEL IV Total cooling-degree daysa since May 15 581.01 Temperature humidity index-four day weighted 81.63 average 1 MODEL V Temperature 2 hours before end of peak hour 91.80' F Total cooling-degree-daysa since May 15 581.01 ( () Peak day heat build-up weather index 1.00 >Q 'l . aDegree days are calculated for the 24-hour period ending at 2 p.m. on 1 the day in question. 1.1-29
Byron ER-OLS AMEMDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCH 1982 TABLE 1.1-14 GROWTH INDICATORS 10-YEAR GROWTH RATE PARAMETER AND SOURCE CURRENT LAST YEAR Real GNP 3.0% 3.0% Wharton Econometrics 2.8%-3.0% Data Resources Inc.a 2.9% Electrical Worldb 3.7% 2.9% Industrial Productig Data Resources Inc. 3.7% 4.0%-4.1% 4.4% 3.0% 1 3 Electrical World Wharton Econemetrics 5.4% --- Peak Electrical Load (kW) Electrical World 2.5% 3.9% National Electric Reliability Councile 3.4% 4.0%
" Source: Data Resources, Inc. (undated).
b Source: Edison Electric Institute (1981). cSource: National Electric Reliability Council (1981). 1.1-30
O O O TABLE 1.1-15 OFFICIAL PEAK LOAD ESTIMATES FOR 1982 THROUGH 1991 3 LOW GROWTu MOST LIKELY GROWTII !!IGII GROWTli RATE "C" RATE "B" RATE "A" PERCENT GROWTII PERCENT GROWTH PERCENT GROWT11 PEAK FROM PEAK FROM PEAK FRJM l YEAR (MW) PREVIOUS YEAR (MW) PREVIOUS YEAR (MW) PREVIOUS YEAR ( a a 1982 14,650 0.5 14,650 0.5 14,850 2.0 1983 14,850 1.5 15,050 2.75 15,450 4.0 m 1 15,000 15,450 2.5 15,900 3.0 N l 1984 1.0 P 1985 15,150 1.0 15,750 2.0 16,400 5.0 0 16,050 2.0 16,900 3.0 .U H 1986 15,300 1.0 b 1987 15,450 1.0 16,350 2.0 17,400 3.0 y H 1988 15,600 1.0 16,700 2.0 17,900 3.0 a
'1989 15,750 1.0 17,050 2.0 18,450 3.0 @
19,000 3.0 U3 1990 15,900 1.0 17,400 2.0 19'J1 16,050 1.0 17,750 2.0 19,550 3.0 1 3
$$c5 w tn t~ to l
95"5 aHa H tn w tn m Z co z co e H e "Z O Z O
" Based on an adjusted 1981 peak load of 14,575 MW.
w H
TABLE 1.1-16 CECO SUMMER PEAK LOAD FORECASTS: 1966 - 1981 (Values Exclude Lincoln and Albion Loads) St.9ETR DA TF 'f FE7W*TF 11 2.M g.y ) .9A 5 15.y IM O .10 10.; 73 PAR
} l-25 19 6 72 10-1 % 72 5-7-7T,- k 9. p. r$ g .g g 1/AB (W) 12-12 M 33%f3 4-19-(1 k - 17# 9 IYA 7,k91 -
19f7 7,03 8,c33 - 8,9% 9,6ko 8, 7 10 - IW9 14 9 9,M5 9,2*7 9,3T 9.5T - 10,027 9,77b 10,130 10,390 10,3'k' 1970 10,721 10.To l l ,2*o 11,260 11.110 - 1991 10, % 3 11,%0 12.190 12,1T 12,190 12,190 - 17"* 11,750 11.527 12,750 g 12,790 13,190 13,190 13,190 12.8 % 1 973 12,b62 12.393 1k,2 9 1h,230 13,690 13,760 13,310 - 12,270 13,790 14,230 19 % O 15,%0 15,4ko t h ,990 1k,910 13,500 - l3 H :gr5 12,305 ik,9k0 15,?bo 16,170 15,9ho Ik,5ko 13,500 - 12.T* 16,5ko 16,5k0 16,5ko M H 17a5 15,6 M 1h 310 13,930 - l 17,W4 17 To 17,k30 17.1 % y 19'T 13,9 9 J ,6')O 15,390 16,t'0 1k ,k50 - 19,0IC 19,ffo 19,8no 19,kl0 19'9 13,720 16,k60 15.220 15, 710 - - U 20,410 20,250 19,760 !?,740 15,'Dn U) 13,% 20,b10 19?9 15,04C 1 k ,750 21,210 19,9V 17,550 16,m 16,020 15,760 - 21,R20 21,810 F4k1 J k ,r9 15,000 18,690 17,900 16,950 16,kio 15,780 15,270 23,k70 22,7 % 20,1 p 1981 13,299 15,600 Ik ,6 % 21,7o 19,870 18,980 17,720 17,2r 16,550 15,919 2k ,350 1982 16,676 16,050 15,050 22,700 21,120 20,010 19,620 19,010 17,290 26,050 19A3 17,k70 16,550 15,k50 2h,0% 22,k10 21.210 19,5(4 19,8M 17, @ 0 19 % 25,k90 23,790 22,b70 20 5k0 i 19,660 18,700 19,290 17.050 15,750 Q 1985 23,7T 21,560 20,5?O 19,k50 19,150 17,550 16,e50 yh 1e6 22,610 n,kw 20,230 20.030 18,100 16,350 O Z M' Z O O 1997 22,yc 21,020 20,9p 18,650 16,n XHV H m @ E0 1989 21,+ . 21,9 w 19,200 17,090 m z co 2 199 19,900 15,100 1930 1 T,750 Z Z im O O Forecast s saade bef** IM are W ifel,=1=' eifer* *473Fere*:'s t
- en t i 4e recit en1 T1't els ^-e % Flectrie 5:te division for each forcenst before l'e4 are ret available, H
H W G" O e
m
\
TABLE 1.1-17 1966 - 1981 CECO SUMMER PEAK LOAD FORECASTS AS PERCENTAGES OF ACTUAL PEAK LOADS: (Values Exclude Lincoln and Albion Loads) stasen MsN OF FSTfMAN PEAK 12-12-66 3-15-65 3-1 69 h-17 69 11-25-p 6 72 10-14-72 5-7-7h IT-T.h 9 30-75 11 7 10-29-77 2 6-79 19% 5-15-m 10 21 =lo '0-19-H g ItinD Dat) 19f4 7,b91 100 1967 ' 7,6k3 105.1 100 1%8 8,950 96.5 97.2 10 0 1969 9,265 100.2 100.3 103.5 100 1 710 10.027 99.5 101.0 103.5 103.5 100 10,943 98.0 . 100.2 102.9 102.9 101.5 100 1971 11,750 100.8 103.7 103.7 103.7 103 7 100 1 772 98.1 102.6 105.0 105.8 105.8 103.0 102.3 100 1973 12 b62 99.b 116.0 113.1 112.1 108.5 100 M 171b 12,270 - 112.3 116.0 116.0 M H 124.7 124.7 124.7 U1.8 120.4 - 109.7 100 0 e 1 715 12,305 - 120.6 128.1 128.1 u8.1 125.3 123 5 - 112.7 10k.6 100 1776 12,907 - - W 127 5 125.1 123.0 - 112.2 102.7 200.6 1m 19r7 13,912 . - - 127.5 1 138.9 137.0 13h.2 - 121.6 112.1 108.h 105.3 100 1979 13,720 138.9 0 128.8 119.2 116.h 110.3 109.2 100 g1 1 719 13.804 147.9 147.9 146.7 Ik3.1 - 153.3 lb9.1 - 133.0 123 3 117.9 112.6 110.8 10f>.1 103.7 1a0 1980 14.228 - 153.h
- - 170.9
- 151.4 140.5 133.8 126.7 126.9 113.7 114.9 112.3 100 1981 13,299 l l
l i
% L'J U N i OZNZ i
lI: O 3H H tTJ @ Z Z listes Estimates es percentages of eetual peak loads made before 1966 ore not included einre adjustments to esclude O bd Cerittel Illinole f.es & FMtrie division for each foreccet before 1966 are not evelloble. M Z Z O
. .O W
TABLE 1.1-18 CECO SUliMER PEAK LOAD FORECASTS AS PERCENTAGES OF RECONSTRUCTED PEAK LOADS: 1966 - 1981 (Values Exclude Lincoln and Albion Loads) litr'ormitt 17D DATE & ES7 DIAM -% 10 M supeelt n2K 2-1-69 b- 17-69 11-25-M 6 1A72 10-13-72 5 73 10-P-7b 2-M-M 11-5-K. yQ 2gj 19% r D-r l l TTJul Il1AD (W)* 12- 12-((; 3-1943 l'l(6 7,591 10 0 1967 7.7*32 103.2 100 159 9.127 94.7 99.3 100 IV9 99.7 100.9 102.9 loo 9.319 (I! 10,17o 99.1 99.6 102.1 102.1 100 N 1770 N 99.7 102.4 102.k 10 1.0 100 1971 10,903 97.5 H lok.1 104.1 104.1 104.1 100 1772 11,708 98.5 101.1 g 100 97.0 100.1 102.6 102.6 IN.6 100.4 99.9 1973 12,773 % 111.9 115.9 115.9 115.9 112.8 111.8 108.1 100 i l A 197h 12.310 - Q 121.1 119.6 - 109.1 loo 119.9 123.9 12 3. 9 12 3.9 19T5 12.3'9 - 122.6 111.8 103.9 loo 127.2 118.0 118.0 124.4 - 1 776 13,003 - - 121.4 - 110.8 101.4 99.2 lor ISP, 14,107 - - - 12 5.9 125.9 12 3.6 135.2 122.5 112 .9 109.2 06.1 100 140.0 1h0.0 1%.1 - 17'9 13.617 128.9 119 3 114.h 110.3 109.2 loo 100 13,777 147.9 lb7.9 lb6.8 lb3 2 - 1979 122.2 116.9 111.5 109.7 105.6 102.7 100
- 153.4 151.8 147.7 -
1 31.8 1980 1 4,3(23 122.5 117.3 13 3.5 111.5 100
- - 168.9 - 149,6 139 .9 1 32. 3 125.2 l 1%1 13,b55 miC OZMZ rm l2: O O lC H 3:
H t:1 W M
@ Z CD Z CDdHd g
%. con.tr=s.a .ecorains s. 7.nl.1.1-19. Z Z O
.O .
I H W W 9 9 9
Byron ER-OLS AMENDMENT NO. 1 JULY 1931 AMENDMENT NO. 3 TABLE 1.1-19 MARCH 1982 RECONSTRUCTED ANNUAL PEAK ACTUAL VOLTAGE RECONSTRUCTED a DATE PEAK VACATIONS REDUCTION RIDER 17 OTHER b PEAK 8-25 1959 4,233 48 0 0 -239 4,42' 9-8 I 1960 4,590 51 0 0 -136 4,6?$ 8-31 1961 4,840 35 0 0 -130 4,935 6-24 1962 5,143 50 0 0 -138 5,231 7-1 1963 5,372 -84 0 0 -155 5,611 8-3 1964 6,102 -20 0 0 -189 6,311 7-23 1965 6,468 -73 0 0 -203 6 744 7-12 1966 7,491 -57 0 0 -43 7,591 6-15 1967 7,643 61 -150 -50 0 7,782 8-23 1956 8,950 8 -100 -10 -75 9,127 1- M g Ad(9 9,265 -53 0 0 0 9,318
% 1 7-2 1970 10,027 -48 -83 -12 0 10,170 6-28 1971 10,943 -55 0 0 0 10,998 8-18 1972 11,750 42 0 0 0 11,708 8-27 1973 12.462 69 -300 -80 0 12,773 7-19 1974 12,270 -40 0 0 0 12,310 8-1 1975 12,305 -74 0 0 0 12,379 7-14 1976 12,907 -96 0 0 0 13,003 7-15 1977 13,932 -115 0 -60 0 14,107 9-8 1978 13,720 103 0 0 0 13,617 8-7 1979 13,804 7 0 0 0 13,797 7-15 14,228 -74 0 -61 0 14,363 1980 7-8 13,299 +15G 0 1981 0 0 13,455 3
(
- Electric rurnace Interruptible service.
b Strikes, voluntary load control, sales to CIE6G, etc. 1.1-35
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCH 1982 TABLE 1.1-20 COMMONWEALTH EDISON COMPANY - ACTUAL MONTHLY PEAK LOADS AND MWH SOLD VERSUS ESTIMATED VALUES FROM JANUARY 1973 TO DECEMBER 1981 3 LATEST ESTIMATE CONSOLIDATED
%CTUAL OF PEAR LOAD ACTUAL PEAR BEFORE MEGANATTHOURS YEAR LOAD OCCURENCEa soLa MONTH (DATE OF ESTIMATE) (MW) (MW) (INCL. RESALE)
Jan. 1973 9,204 8,990 4,899,482 Feb. 8,885 8,890 4,868,574 Mar, 8,305 8,560 4,623,403 Apr. 8,376 8,180 4,471,260 May 8,001 9,470 4,383,134 June 11,356 11,900 4,529,039 July 12,176 12,560 4,753,372 Aug. 12,462 12,750 5,017,134 Sept. 10,273 11,930 5,228,681 Oct. 9,316 B,460 4,945,926 Nov. 8,863 9,100 4,677,904 Dec. 9,006 9,650 4,648,384 Jan. 1974 8,922 9,750 4,703,993 Feb. 8,773 9,540 4,843,769 Mar. 8,560 9,250 4.649,494 Apr. 8,277 8,720 4,516,056 May 9,262 9,220 4,309,951 June 10,773 12,390 4,361,554 July 12,270 13,100 4,643,768 Aug. 11,518 13.310 4,961,974 Sept. 10,714 12,430 5,016,021 Oct. 8,647 8,580 4,687,779 Nov. 9,008 9,250 4,695,264 Dec. 9,211 9,490 4,850,549 Jan. 19'S 9,451 9,500 4,844,735 Feb. (12-19-74) 9,089 9,280 4,997,342 Mar. 8,629 8,930 4,836,667 Apr. 8,572 8,360 4,437,180 May 10,494 9,600 4,100,285 June 11,549 12,360 4,462,900 F July 12,240 13,440 4,953,894 l Aug. 12,305 13,500 5,239,553 Sept. Oct. 10,524 8,990 12,200 8,950 5,141,668 4,522,807
}
Nof. 8,991 9,580 4,408,480 Dec 9,817 9,790 4,751,010 Jan. 1976 9,859 9,860 5,007,999 ! Feb. (12-1-75) 9,444 9,540 5,160,790 I Mar. 9,008 9,110 4,827,215 Apr. 8,756 8,610 4,510,883 May 8,827 9,700 4,263,540 June 11,919 12,260 4,465,008 July 12,907 13,370 4,969,907 Aug. 12.543 13,350 5,274,338 Sept. 11,296 12,000 5,110,357 Oct. 8,889 8,980 4,719,537 Nov. 10,186 9,870 4,871,583 Dec. 10,103 10,190 5,203.054 Jan. 1977 10,323 10,340 5,461,928 Feb. (11-29-76) 9,497 9,820 5,498,830 Mar. 9,138 9,510 5,063,922 Apr. 9,217 9,150 4,279,748 May 11,974 10,630 4,570,752 J une 12,236 13,150 5,016,645 July 13,931 13,990 5,538,927 Aug. 12,013 13,990 5,534,154 Sept. 10,733 12,310 5,274,031 Oct. 8,994 9,290 4,873,869 Nov. 9,832 10,310 4,656,693 Dec. 10,551 10,740 5,279,526 9
- Based on peak-inaking weather conditions.
1.1-36
Byron ER-OLS AMENDMENT NO. 1 JU'LY 1981 ex AMENDMENT NO. 3 TABLE 1.1-20 (Cont'd) MARCH 1982 LATEST ESTIMATE CONSOLIDATED ACTUAL OF PEAK LOAD ACTUAL PEAK bEFORE MEGAWATTHOURS YEAR LOAD OCCURENCEa SOLD MONTH (DATE OF ESTIMATE) (MW) CfW) (INCL. RESALE) Jan. 1978 10,726 10,850 5,734,839 Feb. (12-9-77) 10,057 10,310 5,755,660 Mar. 9,600 9,750 5,553,462 Apr. 9,014 9,600 4,821,240 May 10,969 11,130 4,686,545 June 12,851 13,580 4,859,617 7uly 13,517 14,450 5,418,634 Aug. 13,675 14.450 5,586,580 Sept. 13,720 12,570 5 772,320 Oct. 9,152 9,600 5,397,261 Nov. 10,284 10,830 5,076,672 , Dec. 10,423 11,290 5,378,144 J .n . 1979 11,068 11,400 5,691,198 Feb. (12-9-77) 10,728 10,830 5,906,071 Mar. 9,816 10,220 5,711,828 Apr. 9,793 10,010 5,635,360 May 11,211 11,720 4,811,667 June 12,146 14,310 5,094,554 1 July 12,553 15,220 5,385,321 Aug. 13,804 15,220 5,436,419 Sept. 11,446 13,240 5,353,641 Oct. 9,445 10,060 4,815,991 Nov. 10,156 11,380 4,882,758 Dec. 10,527 11,860 5,288,672 [~'N) \ _/ s Jan. reb. 1980 (2-6-79) 10,715 10,252 11,570 11,100 5,511,021 5,623,099 Mar. 10,000 10,640 5,545,503 Apr. 9,597 9,810 4,891,490 May 10,126 12,450 4,361,419 June 12,892 14,970 4,625,890 July 14,228 15,760 5,392,958 Aug. 13,838 15,440 5,628,654 Sept. 11,227 14.030 5,513,575 Oct. 9,515 9,963 4,721,731 Nov. 9,694 11,480 4,997,078 Dec. 10,577 11,960 5,408,478 Jan. 1981 10,603 10,720 5,629,764 Feb. (10-22-80) 10,778 10,250 5,622,700 Mar. 9,897 10,000 5,262,098 Apr. 9,161 9,880 4,645,148 May 9,889 11,700 4,699,718 June 12,749 14,040 4,921,086 Je l,- 13,299 15,000 5,498,952 3 Aag. 12,717 14,900 5,270,014 sept. 10,679 13,220 5,183,816 Oct. 9,388 10,000 4,646,349 Nov. 9,886 10,750 4,599,023 Dec. 10,399 11,140 5,247,113
/"%
\
[
" Based on peak-making weather conditions.
1.1-37
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 l AMENDMENT NO. 3 MARCH 1982 TABLS 1.1-21 , FIRM POWER INTERCHANGES AT TIMES OF ANNUAL PEAK DEMAND YEAR PURCHASESa (.MW) SALES (.MK) NET RECEIVED (MW) 1962 0 78 -78 1963 0 94 -94 1964 300 115 185 1965 150 97 53 1966 0 150 -150 1967 100 255 -155 1968 200 92 108 1969 700 154 546 1970 808 67 741 1971 750 30 720 1972 900 241 659 1973 360 241 119 1974 700 80 620 1975 700 40 660 1976 700 59 641 1977 700 132 568 1978 500 57 443 1979 0 0 0 1980 0 0 0 1981 400 0 400 1982b 370 0 370 1l3 1983 370 0 370 1984 0 0 0 1985 0 0 0 1986 0 225 -225 1987 0 0 0 1988 0 0 0 1989 0 0 0 1990 0 0 0 l aAll purchases indicated are contracted purchases, but exclude Ludington. lh Values for 1982 and succeeding years are estimated. l3 1.1-38
[J L 0)
%. 0)
\
TABLE 1.1-22 PLANNED GENERATING UNIT ADDITIONS AND RETIREMENTS GENERATING UNIT ADDITIONS ESTIMATED NET CAPABILITY (MW) PROJECTED YEAR AVAILABLE CAPACITY FACTOR a STATION - UNIT TYPE WINTER SUMMER SERVICE DATE FOR SUMMER PEAK FOR FIRST 10 YEARS La Salle County 1 N 1078 1048 April 1982 1982 60 to 70 La Salle County 2 N 1078 1048 June 1983 1983 60 to 70 Byron 1 N 1120 1120 February 1984 1984 60 to 70 Byron 2 N 1120 1120 February 1985 1985 60 to 70 $H
" 1120 1090 October 1985 1986 . Braidwood 1 N 60 to 70 0 Y trj W Braidwood 2 N 1120 1090 October 1986 1987 60 to 70 y
, o GENERATING UNIT RETIREMENTS D NET CAPABILITY (MW) AGE AT RETIREMENT STATION - UNIT TYPE WINTER SUMMER SERVICE DATE RETIREMENT (YEARS) DATE 4 Ridgeland 3 F 153 147 December 1953 28 Before Summer 1982 h$c$ ' Ridgeland 4 F 158 152 August 1954 27 Before Summer y$($ 1982 ::: C H Ridgeland 1 F 137 131 June 1951 31 Before Summer ph$$ 1982 Before Summer N
$%f$
Ridgeland 2 F 126 120 November 1950 32 g 1982
- o. o "N = Nuclear, F = Fossil bThe economic reasonableness of retiring Ridgeland Station is currently being considered by the Illinois Camnerce Commission.
e < .w
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3
"^ " '
TABLE 1.1-23 GENERATING UNIT CAPABILITIES AND ESTIMATED CAPACITY FACTORS: 1975-1990 ESTIMATED 1983-1990 CAPACITY I. NI mw FAC10P S FL'NC- ErMMER 1977 CApppIIII 19[3y 6 TTS 1981 1982 IN FTPCENT PLANT NAME $ NIT TYPE" TI JN D IVI3 19ib 1975 554 554 554 554 5-20 F C 0 0 0 515 554 5-20 rollius 1 0 0 $10 554 554 554 2 F C 0 530 530 5-20 0 0 500 0 530 530 3 F C a 0 530 530 530 530 10-20 F C 0 0 10-20 4 0 530 530 530 530 5 F C 0 0 0 0 0 0 0 e F C 01 64 0 0 20-45 Crawford 6 219 219 219 219 219 213 213 7 F C 222 319 319 20-45 8 F B 350 340 319 319 319 319 0 0 c F C 50 50 50 0 0 0 Dixon 4 0 0 e F C 65 65 65 0 0 0 5 0 0 0 d N B 200 197 197 197 197 Dresden 1 772 772 772 772 772 772 55-70 N B 780 772 2 780 773 773 773 773 373 773 773 55-70 3 N B 19 0 0 0 0 c 18 F C 146 119 Fisk 336 336 336 336 336 316 316 30-40 39 F B 336 P 11 11 11 11 11 11 11 11 1-2 20 F 85 0 0 0 0 0 e 5 F C 117 85 Joliet 334 330 330 330 330 330 298 298 20-40 6 F B 613 533 533 533 533 533 499 499 10-50 7 F B B 613 533 533 533 533 533 518 518 10-50 8 F 1- 2 P 11 11 11 11 11 11 11 11 9 F 606 606 606 606 606 554 554 45-55 Eincaid 1 F B 616 45-55 F B 616 606 606 606 606 606 554 554 2
* * - - - 1048 55-65 LaSalle 1 N B * -
Powerton 1 F P 0 0 0 0 0 0 0 0 c 2 F P 0 0 0 0 0 0 0 C c 3 F P O O 0 0 0 0 0 0 c 4 F P 0 0 0 0 0 0 0 0 e 1 5 F B 850 850 850 850 850 850 700 700 35-4C 6 F B 0 850 850 850 850 850 700 700 35-40 Quad Citie. 1 N B 585 576 576 576 576 576 576 576 60-75 2 N B $85 577 577 577 577 577 577 577 GO-75 Bidgeland 1 F C 152 152 157 157 157 157 157 0 e 2 F C 152 152 152 152 152 152 152 0 c 3 F C 137 137 137 137 137 137 137 0 e 4 F C 132 132 136 136 136 136 136 0 c Sabrooke 1 F C 0 0 0 0 0 0 0 0 c 2 F C 0 0 0 0 0 0 0 0 c 3 F C 34 0 0 0 0 0 0 0 e 4 F C 57 57 0 0 0 0 0 0 e State Line 1 F C ! ~. 6 171 171 0 0 0 0 0 e 2 F C 150 140 140 140 0 0 0 0 c 3 ? C 2 30 190 190 190 190 190 187 187 35-45 4 F B 358 318 318 318 318 318 318 318 20-SC waukegan 1 F P 0 0 0 0 0 0 0 0 e 2 F P 0 0 0 0 0 0 0 0 c 3 F P 0 0 0 0 0 0 0 0 e 5 F C 129 122 122 0 0 0 0 0 c 6 F C 119 88 88 bl 88 88 100 100 20-30 7 F B 338 310 328 32 8 128 328 328 328 20-35 8 F B 360 296 358 358 358 158 297 297 25-45 Will Coanty 1 F C 139 139 139 139 139 139 101 101 20-40 2 F C 148 148 161 161 161 161 148 148 10-45 3 F C 251 251 251 251 251 251 251 2S1 10-45 4 F B 513 503 510 510 510 510 510 510 10-45 Sion 1 N B 880 1040 1040 1040 1040 1040 1040 1040 50-65 2 N B 880 1044 1040 1040 1040 1040 1040 1040 50-65 Peaking Units - F F 1602 1467 1463 1463 1488 1488 1277 1277 1-5
*Abbreintions as follows t F - Fossil Unit M- Hydroelectric Unit; W - Nuclear Unit.
bAbbreviations as follows: B - Base Loads C - Cyclic Loads P - Feaking Load.
' Retired.
dTaken out of service for chemical cleaning. 1.1-40
I
, fm
/
s
)
(a) L/ (
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)
r TABL! 1.1-24 LOAD AND CAPACITY STATEMENT FOR COMMONWEALTII EDISON COMPANY (All Values in Megawatts) CAPABILITY - IVRON UNIT 5 W SGEDt'LL 1982 19H3 1984 1965 1%6 IW7 1988 19H9 1990 1911 Net Mditions & Retirements Since Previous Peak 478 0 2,198 1,120 1,120 1,120 0 0 0 0 Owned Net Generating Capacity a 17,242 17,242 19,440 20,560 21,600 22,800 22,800 22,800 22,800 22,800 Is ss Summer Limitations 530 530 560 560 590 620 620 620 E20 620 Imss Firm Sales 0 0 0 0 225 0 0 0 0 0 Plus: Firm Purchases 370 370 0 0 0 0 0 0 0 0 Plus: Indington Purchase 624 312 312 112 312 312 0 0 0 0 TOTAL CAPABILI7Y 17,706 17,394 19,192 20,312 21,177 22,492 22,180 22,180 22,180 22,180 e M M H Peak load 14,650 15,050 15,450 15,750 16,050 16,350 16,700 17,050 17,400 17,750 b H TOrAL RESERVE - BYRCN UNITS Cs. SCHEDULE 3,055 2,344 3,742 4,562 5,127 6,142 5,480 5,130 4,760 4,433 Total heserve Margin Percent Total Reserve b 20.9s 15.6% 24.2% 29.04 31.9% 37.6% 32.0% 30.1% 27.5% 25.06 p Excess or DeficiencyC 857 87 .,425 2,200 2,720 3,690 2,975 2,573 2,170 1,768 m Capacity Mdition Progrand LAS1 LAS2 BY2 BR1 BR2
-RDG BY1 Tf7 PAL P.PSERVE - WITHC17 BYRON UNITS 1 AND 2 Total Reserve Margin 3,055 2,344 2,622 2,322 2,887 3,902 3,240 2,890 2,540 2,190 Percent Total Reserve b 20.9% 15.64 17.0% 14.74 18.0% 23.9% 19.44 17.0% 14.60 12.3%
e.xcess or Inficiencyc 857 87 305 -40 480 1,450 735 333 -70 -472 % Capacity Mdition Progran d BRI IAS1 LAS2 BR2 xmem OZKZ
- O O ZHZ H tn o m
" Return to service of Dresden Unit 1 is indefinite. Its capacity is not shown in this table. to Z CO Z b CO d H d Percent reserve is reserve margin expressed as a percent of peak load, y Based on a required margin of 154 Z Z O O 4Jnits shown added are those units available for the indicated year's peak load and may have actually been added af ter the peak load of the year *
- before. Station abbreviations are as follows: IAS = LaSalles RDC = Ridgelands BY
- Byrons and BR
- Braidwood.
W H H W
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 [ ) MARCH 1982 1.3 CONSEQUENCES OF DELAY The most important consequences of a possible delay in the operation of the Byron Nuclear Generating Station - Units 1 & 2 is that replacement energy in the form of purchased power or increased generation using oil, or both, would be required. The 3 delay in Byron Units 1 and 2 would cause reserves in 1985, 1990, and 1991 to fall below 15%. Without an adequate supply, the possibility of voltage reductions, brownouts, or service interruptions is greatly increased. Furthermore, older units would have to be operated to supply the necessary energy to meet customers' requirements. A study completed in 1980 by CECO showed that a 1-year delay of the Braidwood Station, a two 1120 1 MW unit facility, would increase the cost of construction by $150 million and system operating cost by $300 million. A Byron station delay would have similar economic consequences. Because of this the Illinois Commerce Commission concluded that all six nuclear units now under construction (La Salle, Byron, and Braidwood) should be completed as promptly as possible. The environmental impact of operating older fossil-fueled units rather than nuclear units would also be a serious consequence of a delay. The reduced reserve margin if the units are delayed, l3 gg ( j including the capacity of existing and projected interconnections, is shown in Table 1.1-24. r em >
~/
1.3-1
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCH 1982 I'l V CHAPTER 2.0 - THE SITE AND ENVIRONMENTAL INTERFACES LIST OF FIGURES NUMBER TITLE 2.1-1 Location of Site in Relation to Illinois 2.1-2 Location of Site within Ogle County 2.1-3 Location of Site within Rockvale and Marion Townships 2.1-4 Site Layout and Exclusion Area 2.1-5 Location and Orientation of Principal Plant Structures 1 2.1-6 Topography of the Site Area 2.1-7 Major Roads and Railroads within 6 Miles of the Station 2.1-7A Route of Byron Station Railroad Spur l3 2.1-8 Cities Located within 10 Miles of the Station 2.1-9 Geographical Locations of the Population Sectors 2.1-10 Locations of All Major Cities within 50 Miles of the Station 2.1-11 Dairy Herds Located within the Site Vicinity 2.1-12 Industrial Land Use within 10 Miles of the Station fg 2.1-13 Pipelines Located within 5 Miles of the Station (_) 2.1-14 Major Roads and Their Associated Traffic Volumes within 6 Miles of the Station 2.1-15 Airports Located within 10 Miles of the Station 2.1-16 The Rock River within a 50-Mile Radius Downstream from the Station 2.2-1 Aquatic Sampling Sites Near the Byron Station 2.2-2 Length and Age Frequency for 4 Channel Catfish ' Collected from Rock River During January 1974 2.2-3 Length and Age Frequency for 5 Channel Catfish Collected from Rock River During March 1974 2.2-4 Length and Age Frequency for 56 Channel Catfish Collected from Rock River During April 1974 2.2-5 Length und Age Frequency for 106 Channel Catfish Collected from Rock River During July 1974 2.2-6 Length and Age Frequency for 13 Channel Catfish Collected from Rock River During October and November 1974 2.2-7 Rock River Fishing Sites Where Fishermen Were Interviewed Between May 5 and September 28, 1974 2.2-8 Summer Food Web for a Forest Community on the Byron Station Site 2.2-9 Summer Food Web for a Meadow Community on the Byron Station Site 2.2-10 Terrestaial Sampling Locations 2.2-11 TerrestriEl Survey of Pipeline Corridor 2.3-1 Number of Tornadoes Per County in Illinois (1916-k'~T
/ 1969) 2.0-xv i
. . - . - _ . _ ~-
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 i LIST OF FIGURES (Cont'd) NUMBER TITLE ! 2.3-2 Annual Wind Rose for 30-Foot Level at Byron Station 1 (1974-1976) I , i f I l
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Byron ER-OLS LIST OF FIGURES (Cont'd) O NUMBER TITLE 2.3-3 January Wind Rose for 30-Foot Level at Byron Station (1974-1976) 2.3-4 February Wind Rose for 30-Foot Level at Byron Station (1974-1976) 2.3-5 March Wind Rose for 30-Foot Level at Byron Station (1974-1976) 2.3-6 April Wind Rose for 30-Foot Level at Byron Station (1974-1976) 2.3-7 May Wind Rose for 30-Foot Level at Byron Station (1974-1976) 2.3-8 June Wind Rose for 30-Foot Level at Byron Station (1974-1976) 2.3-9 July Wind Rose for 30-Foot Level at Byron Station (1974-1976) 2.3-10 August Wind Rose for 30-Foot Level at Byron Station (1974-1976) 2.3-11 September Wind Rose for 30-Foot Level at Byron Station ( 1974-1976) 2.3-12 Detober Wind Rose for 30-Foot Level at Byron Station (1974-1976) 2.3-13 November Wind Rose for 30-Foot Level at Byron Station (1974-1976) 2.3-14 December Wind Rose for 30-Foot Level Byron Station (1974-1976) 2.3-15 Annual Wind Rose for 250-Foot Level at Byron Station (1974-1976) 2.3-16 Winter Wind Rose for 19-Foot Level at Argonne (1950-1964) 2.3-17 Spring Wind Rose for 19-Foot Level at Argonne (1950-1964) 2.3-18 Summer Wind Rose for 19-Foot Level at Argonne (1950-1964) 2.3-19 Fall Wind Rose for 19-Foot Level at Argonne (1950-l 1964) 2.3-20 Annual Wind Rose for 20-Foot Level at Rockford (1966-1975) 2.3-21 Vertical Temperature Cradient Histograms for Byron Station (1974-1976) and Carroll County Station (1975-1976) 2.3-22 Topographic Map of Area within 10 Miles of Byron Station 2.3-23 Topographic Cross Sections of Site Vicinity within 5 Miles of Station 2.3-24 Topographic Cross Sections of Site Vicinity between 5 and 10 Miles of Station 2.4-1 Station Site Area Topography 2.4-2 Outline of Major Station Structures l 2.0-xvi
Byron ER-OLS AMEF" MENT NO. 1 JULi 1981 AMENDMENT NO. 3 1 MARCH 1982 CHAPTER 2.0 - THE SITE AND ENVIRONMENTAL INTERFACES 2.1 GEOGRAPHY AND DEMOGRAPHY 2.1.1 Site Location and Description 2.1.1.1 Specification of Location The Byron Nuclear Generating Station - Units 1 & 2 (Byron Station) is located in northern Illinois, approximately 3.7 miles south-southwest of the city of Byron and 2.2 miles east of the Rock River, in Ogle County. The site is situated approximately in the center of the county in a predominantly agricultural area. Figure 2.1-1 locates the site in relation to Illinois. The site is within Rockvale and Marion townships. The site occupies portions of Sections 12, 13, 14, 15, and 24 of Rockvale Township and portions of Sections 7, 18, and 19 of Marion y Township. The location of the site within the county and within Rockvale and Marion townships is shown in Figures 2.1-2 and 2.1-3, respectively. The station site is roughly rectangular in shape, with the plant [h structures occupying the central portion of the site. The l1
\s I following coordinates of the centers of the containments in Zone 16 of the Universal Transverse Mercator Coordinate System are given below to the nearest 100 meters. Latitude and longitude are given to the nearest second.
Nuclear Unit Latitude and Longitude UTM Coordinates 1 890 16' 55" W x 420 4' 29" N 4,661,800 N 310,700 E 2 890 16' 55" W x 420 4' 32" N 4,661,888 N 310,700 E At its closest approach, the Rock River is approximately 1.5 miles west of the western site boundary and 2.2 miles west-southwest of the actual plant location. Byron is the closest sizeable city (1980 population of 2035) to the site boundaries, although Oregon is the largest city within a 1 10-mile radius (1980 population of 3559). Figure 2.1-2 shows the major cities within Ogle County and the vicinity of the site. 2.1.1.2 Site Area The Byron Station occupies approximately 1782 acres of land. 1 3 rN This area includes the main site area and the transmission and (_) pipeline corridor to the Rock River. The main site area occupies 1 approximately 1398 acres, and the corridor occupies the remaining 2.1-1
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCH 1982 O acres. The exclusion area is shown in Figure 2.1-4. The location and orientation of principal plant structures is shown in Figure 2.1-5. The site boundary lines are as delineated on 1 Figure 2.1-6. The topography of the main site area is also indicated on Figure 2.1-6. The topography in the northern half is dissected and slopes to the northeast. In the southern half, tha land slopes to the southwest and is slightly dissected and rolling. A north-west-trending upland ridge extends through Sectior- 13 and merges with a broader north-south ridge that parallels the site on the cast. The elevations range from approximately 906 feet above mean sea level (MSL) in the southeastern portion of the site to about 670 feet MSL in the portion of the pipeline corridor that lies adjacent to the Rock River. The grade level for the plant is 869 feet MSL. Before construction, the northern half of the l1 site was wooded with some cropland and the southern half was largely cropland. There will be no industrial, institutional, commercial, recreational, or residential structures on the site other than those used by Commonwealth Edison Company (CECO) in tha normal conduct of its utility business. The development of the site for 1 uses other than power generation and agriculture is not planned. Figure 2.1-7 indicates the major roads within the surrounding area. Illinois State Route 2 is the closest major highway to the site and is located 2.5 miles west of the Byron Station (measured from the centerline of the reactors). Other principal roads in the area are Illinois State Highways 72 and 64, located 3.5 miles north and 4.2 miles south of the station, respectively. The site is generally bounded by Deerpath Road to the south. The cicsest railroad is tne Chicago, Milwaukee, St. Paul and Pacific. It is located 4.0 miles north of the station, as indicated in Figure 2.1-7. Figure 2.1-7a shows the route of the railroad spur connecting the site to the Chicago, Milwaukee, St. Paul and Pacific Railroad. From the edge of the site the spur extends approximately 3.6 miles on a 150- to 200-foot wide right-of-way that covers about 75 acres, most of which was formerly 3 agricultural land. The spur connects to the now-abandoned Chicago and North Western Railroad tracks, which CECO purchased from that point for approximately 2.2 miles to the northwest to connect with the Chicago, Milwaukee, St. Paul and Pacific. 2.1.1.3 Boundaries for Establishing Effluent Release Limits The restricted area is used for establishing effluent release limits and enables CECO to fulfill the requirements of 10 CFR 20. l The restricted area boundary is specified to be the Site boundary, as shown in Figure 2.1-6. The expected concentrations 1llh l 2.1-2
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 O h?.RCH 198 2 of radionuclides in effluents are discussed in Section 5.2 and will be in compliance with 10 CFR 20.106 criteria. The minimum distances from the release point of gaseous effluents (the vent stack) to the nearest site boundary for each of the 16 1 directional segments are given in Table 2.1-1. The site boundary closest to the release point of gaseous effluents is in the south-southeast segment at a distance of 2625 feet. Liquid effluents will be discharged through the blowdown lines into the Rock River approximately 2.2 miles northwest of the reactors. The plant exclusion area is located en'i ely within the site 1 boundary lines. The minimum exclusion coundary distance from the l l fq.)\ 2.1-2a
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 / O state and private recreational facilities. Should all these people come from outside the 10-mile area surrounding the Byron site, which is highly unlikely, the total population of this area would be increased by 209%. 1 There are 28 industries within 10 miles of the site, as indicated in Table 2.1-10. Over 2300 people are employed by these industries, or approximately 11% of the 1977 popul tion located within 10 miles of the site. It can be assumed that most of these employees reside near their place of work and are transient only because they do not work at home and travel to their place of business. 1 There areenrollment 16 schoolsofwithin 5066 10 andmiles ofof a staff the site 426 with a total teachers, as 1980-1981 The great majority of students indicated in Table 2.1-11. attending'these schools reside within a 10-mile radius of the site. The 1977 and projected population within the 10-mile radius is given in Table 2.1-12. This table includes the residential and peak daily transient population resulting from recreational activities within the 10-mile area. Uses of Adiacent Lands and Waters I~) (_/ 2.1.3 2.1.3.1 Land Use 2.1.3.1.1 Land Use within 5 Miles The area within a 5-mile radius of the site is located entirely within Ogle County. Ogle County is predominantly agricultural with 91.8% of its total land acreage in farmland, according Table to the 1974 Agricultural Census (Bureau of the Census 1977a). 2.1-13 lists general farm statistics for Ogle and Winnebago counties and the State of Illinois. There are approximately 344,482 acres of farmland under cultivation in Ogle County. This area is approximately 71.0% of the total county acreage and 77.3% of the land devoted to agriculture. The major crops grown in Ogle County are corn and Table 2.1-14 soybeans. Wheat, cats, and hay are also grown. gives the 1974 and 1975 acreage, yield, production, and dollar value of these crops for Ogle and Winnebago counties and the state of Illinois. In general, Ogle and Winnebago counties oats, and hay produced less corn and soybeans and more wheat, than the state average. The one exception to this was county soybean production for 1975, which exceeded the state average. The acreage devoted to corn, wheat, oats, and hay either increased or remained the same between 1974 and 1975, while the
~) acreage devoted to soybeans decreased. This was true for both
' 's Ogle and Winnebago counties, and the state of Illinois. Corn and soybeans are the major crops grown within 5 miles of the site. 2.1-7
Byron ER-OLS AMENDMENT NO. 2 SEPTEMBER 1981 AMENDMENT NO. 3 MARCH 1982 The major livestock raised in Ogle County are cattle and hogs. Table 2.1-15 lists livestock statistics for Ogle and Winnebago counties for the years 1978 and 1979. A survey of milk cows and 2 milk goats was made for the area within a 5-mile radius of the Byron Station. The results are shown in Table 2.1-16 and Figure 2.1-11. One milk goat was found 4 miles south-southeast of the 2 site (Huebner 1981), and there are several commercial dairy herds within the 5-mile radius, with sizes ranging from 50 to 300 head (Wm. S. Lawrence and Associates 1977). The milk produced in Ogle County is predominantly Grade A (60%) and is used for drinking. The major markets for Grade A milk are located in the Chicago and Rockford areas. The remainder of the milk produced is Grade B and is used in the processing of dairy products such as butter, cheese, and ice cream. Much of this milk is sent to Carroll, Jo Davies, and Stephenson counties where the food processing plants are located (Smith 1977). There are only two cities within 5 miles of the site, Byron and Oregon, which are located and identified in Figure 2.1-2 and discussed in Subsection 2.1.2.1. Residential land use is centered around these two cities and in a few outlying housing developments. The remainder of the 5-mile area is predominantly rural. Table 2.1-17 lists the nearest residence and garden to the site in each of the 16 sectors to a distance of 5 miles. The nearest residence and garden are located 0.7 mile from the site 2 (Huebner 1981). 1 There are eight privately owned recreation areas, one county l3 park, and one state park within 5 miles of the site. They are listed in Table 2.1-9, which also describes the areas in terms of size, location, facilities, and attendance. Lowden Memorial State Park is located 3.5 miles southwest of the site. Camping, picnicking, hiking, and natural history interpretation are available on 207 acres, while fishing and boating are permitted on the Rock River located adjacent to the park. Weld Memorial Park, located 3 miles east-northeast of the site, is a 35 acre park owned by Ogle County which offers camping, picnicking, hiking, and fishing. There are eight schools within 5 miles of the site (Illinois State Board of Education 1977). Table 2.1-11 lists all schools with their location, grade levels, staff, and enrollment. There are no hospitals within 5 miles of the site. The nearest hospital is located in Rochelle, Illinois, approximately 15 miles southeast of the site (American Hospital Association 1972). The area within 5 miles of the site is not heavily industrialized. The nearest industries are located in Byron, l approximately 3.7 miles north-northeast. There are four industries in Byron and 17 in Oregon, as indicated in Table 2.1-8 t
I 2 i A Byron ER-OLS AMENDMENT NO. 3 t MARCH 1982 i 2.1-10 which lists all industries within 10 miles of the site, There are I their products, and their approximate employment. i l i 1 j I l a } I J a
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Byron ER-OLS AMENDMENT NO. 1 JULY 1981 2.1.3.2 Water Use 2.1.3.2.1 Surface Water The most important body of water near the site is the Rock River. l At its closest approach the Rock River is approximately 1.5 miles west of the western site boundary. This point is approximately 115 river miles upstream of the confluence of the Rock and ~ Mississippi rivers. Figure 2.1-16 outlines the Rock River within 50 miles downstream from the site. The Rock River is considered nonnavigable to commercial traffic except for that portion adjacentOnly to the Mississippi navigable waters River fall (Army under the Corps of Engineers 1977). The nearest dams U.S. Army Corps of Engineers permit procedures.approximately 21.6 miles to the site are located at Rockford, approximately 5.4 upstream of the intake point and one at Oregon,The U.S. Army Corps of miles downstream from the intake point. Engineers maintains no dams or locks on the Rock River, and it-does not dredge the river channel. Boating, The primary use of the Rock River is for recreation. fishing, and waterskiing are popular pastimes, and there are numerous residences located along the river banks. It is (~T estimated, based on information provided by the Site (_) superintendent of Lowden Memorial State Park, that approximately 16,900 pecple use the river annually for recreation purposes between Byron and the Oregon Dam (Hayes 1977). Sport fishing is a major recreational activity on the Rock River. Three creel surveys have been conducted near the Byron Station where the intake and discharge areas are situated: one conducted in 1967 by the Illinois Department of Conservation, 1972-1973, oneone and byby Environmental Analysts Incorporated They in also conducted 1 Espey Huston & Associates in 1975. 1977, 1978, and 1979; the data additional creel surveys in 1976, from these surveys are comparable to the data collected during the 1972 through 1975 surveys. During theChannel 1972-1973 survey, a cattish, which total of 954 interviews were conducted. were preferred by 47.4% of the fishermen interviewed, were the most abundant fish caught but carp accounted for the greatest weight. The average number of fish caught per rod-hour for the survey was 0.401. During the 1975 survey, 207 interviews were conducted. Table 2.1-30 summarizes the species of fish caught in the Rock River during The most frequently caught species 1975. catfish channel (26.7%), and shorthead were carp (42.9%), Fifteen other species redhorse (9.9%). comprised the remaining 20.5% of the total catch. During the census it was determined that most fishermen caught less than one fish per hour of effort (0.197 fish caught per rod-hour), but that the average catch per (~)
'- trip was approximately 5.7 fish. It was estimated by 158 i
fishermen interviewed that they made approximately 12.4 trips per l person annually to the Rock River (CECO 1977a). 2.1-11 L
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 2 SEPTEMBER 1981 AMENDMENT NO. 3 MARCH 1982 Within 50 miles downstream from the site, the Rock River is used for a variety of recreational uses such as boa;ing, fishing, waterskiing, and swimming. Table 2.1-31 lists the fishing areas within 50 radial miles downstream from the Byron Station that are known to have good sport fish populations. Table 2.1-32 summarizes the public access areas to the Rock River and their facilities that are also located within 50 miles downstream from the site. The areas listed in Tables 2.1-31 and 2.1-32 are shown in Figure 2.1-16. Illinois fishing license sales for 1975 within 50 radial miles of the Byron Station are given in Table 2.1-33. Winnebago County had the highest record of sales with 24,459 resident licenses. Ogle County recorded 5,094 resident licenses sold in 1975. Commercial fishing on the Rock River is limited to special contracts given by the Illinois Department of Conservation (CECO 1977a). There were only five commercial fishing operations, involving a total of'10 fishermen, registered by the Illinois Department of Conservation in 1976. Since 1972 the number of commercial fishermen has steadily declined. Table 2.1-34 lists the species and pounds of fish removed from the Rock River by commercial fishermen from 1970 to 1975. Table 2.1-35 lists the h commercial fish harvest for 1976, the names of the fishermen, and their fishing locations. In 1976, 245,428 pounds of fish were taken. Buffalo and carp were the predominant fish caught, and buffalo accounted for the greatest weight. There is only one commercial fishing operation within Ogle County. It is owned by Mr. Lee Gibson, who fishes the river between the Dixon Dam and the Ogle County line (Illinois Department of Conservation 1977c). 1 The only other uses of the Rock River are for industrial water supplies and some irrigation. The Rock River and the tributaries are not used for public water supply (Purcell 1981). Table 2.1-36 gives the owners and locations of industrial surface water intakes within 50 radial miles downstream of the site. There are 2 three intakes within this radius, all of which are located in either Dixon or Sterling. The closest industrial intake to the Byron site is the Lone Star Cement Company. It withdraws approximately 0.25 cubic feet per second. There is one farmer within Ogle County who uses the Rock River for irrigation. Mr. Rick McCanse irrigates 270 acres of corn at 3 two different locations downstream from the site. The two fields are located approximately 4.7 and 6.7 miles from the 11.take and discharge points for the Byron Station. Mr. McCanse uses approximately 8 or 9 acre inches of water per year and produces 170 bushels of corn per acre. The corn is sold to granaries located in Spring Valley and Hennepin, Illinois (Commonwealth Edison 1977b). 2.1-12
i Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCH 1982 TABLE 2.1-9 MAJOR RECREATIONAL AREAS WITHIN 10 MILES OF THE BYRON STATION i f DISTANCE & DIRECTION ESTIMATED ANNUAL ESTIMATED PEAK ATTFNDANCF (1980) DAY ATTENDANCE ACREAGE FROM SITE RECREATIONAL AREA 50,000 5,000 a Moto Sports Park 50 1 mile N 3,500 600 River Road Camping & Marina 30 2 miles E a yg 2.2 miles E NA NA Rock River i 2.5 miles NW NA 150 Mt. Morris Boat Club 5 l3 2,500 900 35 3 miles ENE Weld Memorial Park 80,000 12,000 190 3 miles N
' Byron Dragway 19,100 350
~ The Stronghold 460 3.5 miles WSW 632,148 6,808 207 3.5 miles SW Lowden Memorial State Park - NA 360 52 4.5 miles NNE Lake Louise NA 200 Oregon Country Club 94 4.5 miles SSW i i ('~ 300 6.5 miles NNE NA NA
$g, Camp Medill McCormick 1
Castle Rock rtate Park & 1,956 7.0 miles SW 42,637 968 Nature Preserve 8.0 miles NSW 29,600 250 White Pines Ranch 100 Fuller Memorial Forest NA 9.5 miles NE 12,000 600
! Preserve NA NA Hansens-Hideaway 160 9.8 miles WSW 457,472 14,176 white Pines State Park 385 10.5 miles WSW 18,000 1,200 28 10.5 miles WSW Lake LaDonna 2,000 200 Camp Lowden 230 10.5 miles SW 4
1 i Sources: Anderson (1981); Bent (1981) Collins (1981): Gaston (1981); } Glotfelty (1981); Keister (1981); Leak (1981); Lihle (1981): { overton (1981); Richardson (1981): Smith (1981); Var. Meter (1981); 3 Vincar (1981): Etnyre (1982). i
\s -
! "NA - not available. 2 i 1-
' 2.1-35 i
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a a l Byron ER-OLS AMENDMENT NO. 1 JULY 1981 l . TABLE 2.1-10 INDUSTRIES WITHIN 10 MILES OF THE BYRON STATION l LOCATION EMPLOYMENT PRODUCTS NAME OF FIRM Byron 2 lumber, hardware, building ! Barker Lumber Company I materials 1 Byrcn 7 stone aggregates l Farmco Inc.
! Kysor Industrial Corpor- Byron 200 automotive accessories ation Byron 185 metal finisning Quality Metal Furnishing Company foundry sand 1 j
Acme Resan Company Oregon 60 75 automotive parking brakes Atwood Vacuum Machine Oregon Company Carnation Milk Corpany Oregon 22 liquid diet product 1 Caron Spir.ning Company Oregon 42 knitting yarns Cook Manufacturing Oregon 40 machine parts Company O r e<jon lo store fixtures, display units Dye Fixture & Display Co. E.D. Etnyre 6 Company Oregon 270 road building machinery Marlin Marietta Aggre- Oregon 53 sand 1 , y gates Oregon 40 film for off-set printing Offset Preparation Service Inc. Oregon Ready-Mix Oregon 7 concrete Oregon Stcne Quarries Oregon 9 stone aggregates, asphalt 19 iron and bronze castings Paragon Foundries Company Oregon Republican Peporter Cregon 7 printing y Corporation Oregon 8 wood furniture Rock Wood Carvers Oregon 6 lumber, wood products, fence Sinnissippi Forest posts, X-mar trees and Sawmill greens Oregon 475 rotary mowers, rear blades, 1 W,_,od B rothe r s , Inc. and discs 1 front ends of racing cars Woodhaven I nd ua,t r ie s Oregon Stillman Valley Tool St illman Valley 11 gear manufacturing Mount Morris 500 printang Kable Printing Ccmpany 272 magazine distributor J Kaule scws Mount Morris Mount Morris 3 printing Rowland Printing Company Mount Morris 13 meat Rude's Custom Butchering 30 electric equipment Snyder Manufacturing Mount Morris l Company candies and syrups Sterling Quallty Mount Morris 2 Products Source: Telephone survey of individual industries by Marketing Department, Dixon y O District, Rock River Division, Commonwealth Edison Company, June 1981. I 2.1-36 j
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Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 1
daily maximum and minimum relative humidities at Rockford were about 87% and 55%. The monthly average diurnal relative humidity range is greatest in May and least in December.
2.3.3.2 Dew-Point Temperature The dew-point temperature is another measure of the amount of It is defined as the temperature water vapor in the atmosphere. to which air must ce cooled to produce saturation with respect to water vapor, with pressure and water vapor content remaining constant. Dew-point temperature data for the 30-foot Byroc ?+ation and 33-foot Carroll County Station levels are presented in Table 2.3-7. Monthly average dew-point temperatures at the Byron Station ranged from 8.40 F in December to 62.50 F in July; the FCarroll in County Station site monthly averagesThe rangeddew-point maximum from 12.00 temperatures December to 59.10 F in July. at the Byron Station and the Carroll County Station sites were 77.90 F and 71.40 F, respectively; the minimum dew-point l3 temperatures were -20.00 F and -16.4c F, respectively. Long-term dew-point temperature The data for annual Rockfordtemperatures dew-point and Argonneatare presented in Table 2.3-8.
/~N Rockford (38.50 F) and Argonne (38.70 F) are generally comparable
(_) with the short-term averages at the Byron Station (33.40 F) and the Carroll County Station site (35.40'F). Monthly average dew-point temperatures at Rockford ranged from 13.80 F in January to 60.60 F in July. The maximum dew-point temperature during the 10-year period was 790 F, and the minimum dew-point temperature was -310 F. 4 The annual averag daily maximum and minimum dew-point temperatures at Rockford (1966-1975) were 440 F and 340 F. The maximum average diurnal variation in dew-point temperature was 150 F in January, and the minimum average diurnal variation was 70 F in July and August. 2.3.3.3. Fog Fog is an aggregate of minute water dropletsAccording suspendedto in the atmosphere near the surface of the earth. international definition (American Meteorological Society 1970), fog reduces visibility to less than 1 kilometer (about 0.62 mile). Fog types are generally coded as fog, ground fog, and ice fog in observation records. Observing procedures of the National Weather Secvice define ground fog as that which hides less than 60% of the sky and does not extend to the base of any clouds that may lie above it. Ice fog is composed of suspended particles of ice. It usually occurs in high latitudes in calm clear weather 7s g) at temperatures below -200 F and increases in frequency as temperature decreases. l 2.3-7 l 4
Byron ER-OLS Fog forms when the ambient dry-bulb temperature and the dew-point temperature become equal or nearly equal. The processes by which these temperatures become the same and fog occurs either cool the air to its dew point or add moisture to the air until the dew point reaches the ambient dry-bulb temperature. This latter process results in the formation of evaporative fog and is of particular interest with respect to cooling facility operation at power generating stations. Cooling facility fog generally occurs when atmospheric conditions are conducive to natural fog formation. Natural processes such as radiational cooling at night or the advection of moist air over a cooler land surface are generally contributing factors. Thus, the description of natural fog occurrence is important to the understanding of the potential fogging problems at the Byron Station. Data on fog frequency and duration are presented for Rockford (1966-1975) in Table 2.3-9. Onsite data are not available to assess the fog characterictics at the Byron Station. Fog occurs c about 13% of the time, or 1097 hours per year, at Rockford. December has the greatest frequency of fog occurrence, with an { average of approximately fifty-five 3-hourly observations re-cording fog. Fog occurs least frequently during the warmer summer months. The 16 longest durations of fog occurrence exceeded 45 hours in duration. Table 2.3-10 presents fog distribution by the hour of the day at Rockford (1966-1975). Radiative cooling of the earth's surface at night, especially during the summer, produces a large occurrence of night-time fog. However, the Rockford observations are taken in a river valley, where moisture addition to the atmosphere from the river and wet valley areas is probable. The Byron Station is located on a plateau with a 145-foot higher elevation. Because of this difference in elevation, fog would be expected to occur less frequently at the Byron Station than at Rockford. 2.3.3.4 Precipitation Short-term precipitation data measured at the Byron Station site are compared with the same period-of record data from Rockford to show the representativeness of the Byton Station site data for the local region. Long-term data from Rockford and Argonne are also presented to show long-term trends for the general region. 2.3.3.4.1 Precipitation Measured as Water Equivalent Monthly precipitation totals at Byron and Rockford for the short-term period-of-record from January 1, 1974, through December 31, 1976, are compared in Table 2.3-11. The precipitation totals at both stations for each month during the period-of-record shown are generally similar, indicating that Byron Station site data are representative of the region. The heaviest monthly rainfall typically occurred during the spring; the maximum monthly rainfall for each location during the 3-year period was 7.39 2.3-8
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v \ Q i l l i TABLE 2.3-7 A COMPARISON OF SHORT-TERM DEW-POINT TEMPERATURES AT THE BYRON STATION AND THE CARROLL COUNTY STATION SITE (all Values in *F) CARROLL COUNTY STATION BYRON STATION AVERXCE MAXIMUM MINIMUM MAXIMUM MINIMUM YEAR MONTil YEAR AVERAGE 1976 15.4 32.0 - 2.2 1974 17.3 39.2 -18.3 January 1976 24.7 49.6 0.3 13/4 18.5 42.8 - 3.9 February March 1974 28.5 55.4 - 9.3 1976 37.0 58.6 8.2 kn 62.4 13.0 0 69.8 6.8 1976 33.7
,N April 1974 39.0 w 22.6 1976 40.9 62.8 17.8 gn May 1975 48.1 68.6 W I
N 1976 70.5 28.3
- June 1975 59.9 77.9 35.3 54.3 f 77.6 48.2 1976 59.1 71.4 38.1 b July 1975 62.5 a 1976 55.1 64.8 36.9 a a a August 28.8 1976 46.4 64.2 15.0 1976 47.2 66.6 September
- 3.5 1976 27.3 52.4 9.7 1976 32.0 57.6 October
-16.5 1976 19.1 39.8 - 4.0 1976 18.3 53.4 November
-20.0 1976 12.0 34.6 -16.4 ym 1976 8.4 39.7 OZ December ::: O 4
77.9 -20.0 35.* 71.4 -16.4 gh Year 33.4 eZ co 8 N Z O. g a Data not presented because of low data recovery *ite. w
TABLE 2.3-8 LONG-TERM DEW-POINT TEMFERATURES AT ROCKFORD (1966-1975) AND ARGONNE (1950-1964) (All Values n *F) ARGONNE AVERAGES ROCKFORD AVERAGE 5 POCKFORD EXTREMES DAILY DAILY MONTil MONTHLY MONTit LY MAXIMUM MIii!MEM MAXIMLM MINIMUM January 16.5 13.8 22 7 54 -31 February 19.8 16.5 23 10 52 -22 March 25.3 25.9 31 21 59 -6 April 36.0 36.C 41 31 68 7 DO N bJ May 46.0 44.6 50 40 70 18 y I 56.3 56.5 60 52 75 23 j# June b3 La 77 39 33 c) July 60.7 60.6 64 57 August 60.5 60.3 64 57 79 41 h3 m September 52.3 52.3 57 48 73 21 October 41.0 41.9 47 37 68 14 November 29.3 30.7 35 26 59 0 December 19.5 21.4 27 16 55 -24 Year 38.7 38.5 44 34 79 -31 l \ O O O . I
Byron ER-OLS AMENDMENT NO. 2 SEPTEMBER 1981 AMENDMENT NO. 3 () MARCH 1982 Two water wells were installed to provide water for t.he grouting operation. These wells are presently capped and are not in use. Well TW-2 is an 8 inch diameter well cased to 240 feet with an open borehole to 505 feet. Well TW-3 is an 8 inch diameter well cased to 241.5 feet with an open borehole to 500 feet. Pumr settings in Well 1 and Well 2 are at 240 feet and 241.5 feet respectively. Both wells produce water from the St. Peter Sandstone. An aquifer pumping test was performed during November 1978 tn l3 demonstrate the ability of the station water wells to provide makeup to the essential service water system during the 30-day period for safe shutdown. The aquifer pumping test consisted of 3 pumping water well W-1 at a continuous rate of approximately 840 gpm while monitoring groundwater levels in water well W-2 (Ironton and Galesville sandstone), in the grouting supply well TW-2 (St. Peter Sandstone), and in an observation well TW-4 installed in the Ironton and Galesville Sandstones approximately 300 feet from water well W-1 on the line connecting wells W-1, TW-2, and W-2. The aquifier pumping test consisted of a 22-hour pumping period followed by a recovery period of 1.5 hours. 3 The wells were modified after the pumping test to increase the aquifier transmissivity and the specific capacity. After the modifications were completed, the wells were retested in July 1980. The test demonstrated the ability of the modified station water wells to provide the required makeup to the essential service water system. Details of the tests and the well modifications are contained in Subsection 2.4.13.1.3 of the Byron Station FSAR. 2.4.2.2 Sources 2.4.2.2.1 Present Regional Groundwater Use There are 15 public water supply systems within 10 miles of the plant site, all of which use groundwater wells for their supplies. Table 2.4-11 lists the 15 public water supply systems 2 and gives details of each. The locations of the public pumping centers are shown on Figure 2.4-11. The five municipal systems obtain their supplies from the Cambrian-Ordovician Aquifer or the Mt. Simon Aquifer, which are dependable and capable of high yields. A piezometric surface map of the Cambrian-Ordovician Aquifer in northern Illinois, based on piezometric clevations measured in (~N October 1971, is presented in Figure 2.4-12 (Sasman et al. 1973). O 2.4-11 l
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 3 i O In the general region of the Byron Station site, the Rock River and the city of Rockford are the main groundwater discharge areas i that control the slope of the piezometric surface. The Byron Station site is located within a trough in the piezametric ' surface that is the result of discharge from the aquifer to the ! Rock River. l 1 I t i t i O '
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Byron ER-OLS Yearly changes in piezometric levels at public groundwater wells in the Cambrian-Ordovician Aquifer are shown in Table 2.4-11. These data indicate that there was little fluctuation for the period of record in the piezometric surface within a 10-mile radius of the Byron Station site. 2.4.2.2.2 Future Regional Groundwater Use According to 1966 projections, public, industrial, and domestic groundwater pumpage in Ogle County was to double in the next 10 to 25 years (Illinois State Water Survey 1966; Sasman and Baker 1966). Groundwater pumpage in Ogle County, however, actually decreased at an average rate of 240,000 gpd per year from 1965 to 1970. The record of groundwater pumpage in Ogle County from 1971 through 1976 is shown in Table 2.4-13. In this table the total annual groundwater pumpage is broken down into the seven principal users (municipal, subdivision, institutional, industrial, irrigation, domestic, livestock), and the portions of the total pumpage obtained from the gravel, dolomite, and sandstone aquifers are shown. During the period of record, the total annual groundwater pumpage has remained fairly constant, and the total pumpage in 1976 was slightly less than those in 1972, 1973, and 1974. This same trend is seen in the records of pumpage from the sandstone aquifers, one of which, the Cambrian-Ordovician Aquifer, will supply groundwater to the Byron Station. Due to the relatively low level of urbanization around the site area and the small amount of onsite groundwater use, it is unlikely that future increases in groundwater withdrawal in the area would have much effect on the groundwater supply at the site. 2.4.2.2.3 Present Site Groundwater Use Piezometers and observation wells were installed at the Byron Station site as part of the groundwater monitoring program. Table 2.4-14 lists the borings with piezometers, the depth and elevation at which they were installed, and the hydrogeologic unit in which they were installed. Table 2.4-14 also lists the water level elevations measured in the piezometers and observation wells. The locations of the piezometers and l observation wells are shown in Figures 2.4-13, 2.4-14, and 2.4-15. Groundwater levels recorded on the boring logs were observed while the borings were being drilled. On a regional basis, the Galena-Platteville dolomites are hydraulically continuous with the lower sandstone units of the Cambrian-Ordovician Aquifer (Walton and Csallany 1962). In the vicinity of the Byron Station site, however, groundwater in the' Galena-Platteville dolomites is perched on the low-permeability Harmony Hill Shale Member of the Glenwood Formation. A piezometric surface map of the site vicinity, as measured in the Galena-Platteville dolomites, is shown in Figure 2.4-10. Groundwater flows radially from the site, and the principal discharge boundaries are the Rock River to the west and northwest 2.4-12
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 2 of the site and Black Walnut Creek to the east and southeast of the site. Table 2.4-15 lists recorded active, domestic or agricultural, groundwater wells east of the Rock River within 2.25 miles of the site. Most of these wells are completed in the Galena-Platteville dolomites. Figure 2.4-16 illustrates the location of each well within 2.25 miles of the plant site. Domestic and agricultural wells west of the Rock River are not shown on Figure 2.4-16 because the river is a common discharge boundary for wells, east and west of the river, that are completed in the Galena-Platteville dolomites. Pump tests were performed on June 20 and July 2, 1974, in two domestic water supply wells that are completed in the Galena-Platteville dolomites. These two wells are located at the west edge of the site along Razorville Road. From the pump tests, aquifer parameters were derived based on July 1, 1974, piezometric levels. Based on estimated saturated thicknesses of 111 and 90 feet at the two wells, the hydraulic conductivities of the aquifer measured at the wells were 6.3 gpd/fta and 22.2 gpd/ft2 The effective porosity of this portion of the aquifer is estimated to range from 0.05 to 0.10. 2.4.2.2.4 Future Site Groundwater Use There are no anticipated changes in the present pattern of groundwater use in the site area. 2.4.2.2.5 Effects of Station Groundwater Use The projected effects of station groundwater withdrawals of approximately 470 gpm were evaluated using the Theis equations (Theis 1935) with assumed values of 17,000 gpd/ft and 3.5 x 10-* as the coefficients of transmissivity and storage (Hackett and Bergstrom 1956). The projected effects were reevaluated using 3 the values of 40,000 gpd/ft and 2.5 x 10-4 determined from the 1980 aquifer pumping test. Theoretical distance- and time-drawdown curves were constructed in order to determine the anticipated shape of the cone of depression and the radius of I influence of the Byron Station wells. These theoretical curves l indicate that the Byron Station groundwater withdrawals should l not impose measurable interference drawdowns on the nearest public water supply wells completed in the Cambrian-Ordovician or 3 Mt. Simon aquifer. In fact, the groundwater withdrawals at the Byron Station intercept groundwater that otherwise would naturally discharge from the aquifer into the Rock River. I Pumping from Byron Station water wells will cause little effect on domestic wells completed in the Galena-Platteville dolomites. As described in Subsection 2.4.2.2.3, the Galena-Platteville (")N
\_ dolomites in the site vicinity are hydraulically separated from the lower portion of the Cambrian-Ordovician Aquifer by the 2.4-13
i Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 Harmony Hill Shale Member of the Glenwood Formation. In h addition, the Byron Station water wells are cased through the Galena-Platteville dolomites and the underlying Ancell Group (St. 3 Peter Sandstone). Groundwater in the Galena-Platteville dolomites is perched on the Harmony Hill Shale Member, and initially, water levels in this aquifer will not be lowered by the pumping required for daily plant use from the lower portion of the Cambrian-Ordovician Aquifer and the Mt. Simon Aquifer. As l3 pumpage from the station water wells continues, minor vertical leakage may occur through the Harmony Hill Shale Member. If recharge by rainfall infiltration is not considered, water levels in domestic and agricultural wells in the site vicinity may be lowered slightly as a result of long-term pumping of groundwater from the Byron Station water wells. Measurements made during the 1980 aquifer pumping test verified that the offsite drawdown 3 effects in the Galena-Platteville dolomites and Ancell Group (St. Peter Sandstone) will be very minor. 2.4.2.2.6 Grouting Effects During construction, the bedrock foundations of the Category I structures were grouted. These structures i.ncluded the power block and the two essential service water cooling towers. Before the consolidation grouting, a grout curtain was placed around the perimeter of each of the foundations. The grout curtains and the consolidation grouting were extended to the top of the Harmony Hill Shale Member of the Glenwood Formation. The foundation grouting, therefore, significantly reduced rock mass permeability in the overlying Galena-Platteville dolomites. The consolidation grouting should not significantly affect perched groundwater levels in the Galena-Platteville delomites. The site groundwater monitoring program, described in Subsection 2.4.2.2.7, has shown no water-level decline in this aquifer since grouting was completed. 2.4.2.2.7 Monitorina A continuing site groundwater monitoring program began in December 1975. This monitoring program is being performed to define existing conditions as a base for future comparisons; to monitor the effects of construction; to check for changes in water levels, mineralization, and water quality due to either plant operation or groundwater use by others; and to provide ample warning time and a basis for remedial action to protect offsite groundwater users in case of detrimental changes in groundwater quality. The existing site groundwater monitoring program is not a part of any future radiological monitoring program. Six domestic and agricultural water wells are being monitored for monthly changes in groundwater chemistry, ss;l in three of the wells, monthly changes in piezometric levels are being recorded. Three of the water wells are owned by CECO and are located on the 2.4-14
~ Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 O inside perimeter of the Byron Station site boundaries (see Figure The other three wells are on the outside perimeter of 2.4-17). the site boundary. Data from the ongoing monitoring program at the site indicate that there have been no changes in groundwater chemistry or piezometric levels attributable to excavation, grouting, groundwater pumping, or other activities at the Byron Station. Groundwater chemistry and water level data gathered through December 1977 provide the bases for comparison with future daca collected during the monitoring program. These groundwater chemistry and water level data are provided in Table 2.4-16 and Table 2.4-17, respectively. In addition to the site groundwater monitoring program, a detailed site geotechnical investigation identified an area of groundwater contamination by toxic materials that existed before CECO purchased the land. An investigation of the nature and extent of the contamination was performed (Dames & Moore 1974, 1975, 1976). A groundwater and surface water monitoring program is presently being conducted by the CECO to monitor trends in levels of contamination (see Subsections 4.1.4.3 and 6.1.2.1). O c-i ( 2.4-15
TABLE 2.4-1 ROCK RIVER FLOW CHARACTERISTICS AT THE INTAKE LOWEST MINIMUM DAILY FLOW AVERAGE FLOW (cf s) MONTHLY MEAN FLOW (1954 - 1976) (1954 - 1976) IN 1958a (c f s) FLOW (cfs) YEAR MONTH October 3654 1403 701 1958 November 3991 2180 982 1958 December 3550 2333 899 1958 tn January 3878 1941 706 1959 Y N O u February 4373 1988 873 1957 g b 8560 4377 1669 1954,1963,1964 5 m March t~ April 9499 3179 2054 1958 May 6960 1416 1031 1958 June 4730 1894 941 1958 July 3708 1528 932 1958 August 2799 1018 853 1958 September 3200 1002 643 1958
^ Water year of the lowest yearly flow at Rockton for period 1954 through 1976.
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1 4 wtEs i 1. m - ' -
Byron ER-OLS 2.6 Regional Historic, Archaeological, Architectural, Scenic,, g' Cultural, and Natural Features This section reviews the findings of the historical study and the archaelogical surveys of both the Byron Nuclear Generating Station - Units 1 & 2 (Byron Station) site and the transmission line rights-of-way. 2.6.1 Plant Site I Tnere are no sites on the station property that are included or are eligible for inclusion in the " National Register of Historic Places" (Federal Register 1977a, 1977b), the " National Registry of Natural Landmarks" (Federal Register 1975; Resseguie 1977), or the other listings of locally significant sites. Although four historic sites were listed for Ogle County in the
" National Register of Historic Places" (see Table 2.6-1), none of these will be affected by the Byron Station. The " Historic American Buildings Survey" (Ison 1977) lists three structures in Ogle County (see Table 2.6-1), and again none of these will be affected by the Byron Station. The " Pictorial Archives of Early American Architecture" (Ison 1977) lists four buildings in Ogle County, none of which will be affected by Byron Station (see Table 2.6-1).
() Many areas of local historical interest, however, do exist in the area. Table 2.6-2 lists and briefly describes these historic sites and markers located within 10 miles of the site as supplied by information from various local sources (see references). In February 1974, Anthony T. Dean, State Historic Preservation Officer for Illinois, stated that no cultural or historical sites in the area would be affected by Byron Station. A copy of his comments is included in Appendix 2.6A. An archaeological survey of Byron Station was conducted in June 1973 by the University of Wisconsin - Milwaukee, a member institution of the Illinois Archaeological Survey. Seven previously unrecorded archaeological sites and one previously recorded site were encountered. In 1974 test excavations were performed to further evaluate the sites so that procedures could be developed that would preclude any potentially harmful effects. It was recommended that the sites along the Rock River in the river screenhouse area be fenced and constructicn crews be instructed to remain 50 feet from the fence in order to avoid impact during construction activities. Archaeological site Og-153, the only site near any construction activity, was fenced in the fall of 1976. In September 1974, the State Historic Preservation Officer of Illinois stated that no archaeological sites would be disturbed by the construction of the Byron
/"'T Station. A copy of his comments is included in Appendix 2.6A.
V 2.6-1
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 2.6.2 Transmission Line Richts-of-Way The historical sites of interest for the Byron East to Cherry Valley-Nelson transmission line right-of-way and the Byron South to Cherry Valley-Nelson transmission line right-of-way are the same as those listed in Subsection 2.6.1. The Byron North to Wempletown transmission line right-of-way crosses into Winnebago County. The " National Register of Historic Flaces" lists two sites in Winnebago County (see Table 2.6-3). These sites will not be affected by the Byron North to Wempletown right-of-way. There are no sites listed on the " National Registry of Natural Landmarks" for Winnebago County. Archaeological surveys were conducted on these transmission line rights-of-way out of Byron Station. The results of the surveys were submitted to the Illinois State Historic Preservation Offf.cer, and his assessment of transmission line impacts on 3 historic and cultural resources is contained in letters dated May 12 and July 16, 1981. Copies of these letters were submitted in response to NRC Ouestion 310.4, which is part of Amendment No. I to this En-OLS. The Byron North to Wempletown transmission line will be visible at the Rock River crossing. G 9 2.6-2
Byron.ER-OLS AMENDMENT NO. 1 JU LY 1981 A AMENDMENT NO. 2 SEPTEMBER 1981 AMENDMENT NO. 3 MARCH 1982 CONTENTS (Cont'd) CHAPTER _ VOLUME Appendix 6.lA - Formulas Used in Analyses of - Algal Data , 2 Chapter 7.0 - Environmental Effects of Accidents 2 Chapter 8.0 - Economic and Social Effects of Station Construction and ,
; Operation 2 Chapter 9.0 - Alternative Energy Sources and '
Sites 2 >
~
Chapter 10.0 - Station Design Alternativec 2
- Chapter 11.0 -
Summary Cost-Benefit Analysis 2 Chapter 12.0 - Environmental Approvals and Consultation - 2 Chapter 13.O' - References 2 Amendment < , s 3:NRC Review Questions and Responses No. 1 2 1 Amendment No.,2 - NRC Review' Questions and R'es'E>Bnses 2 2 s
\
Amendment
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I N No. 3 - NRC Review Quections\and Responses 2 3
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A f A s s a A
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Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 CHAPTER 3.0 - THE STATION TABLE OF CONTENTS PAGE 3.1 EXTERNAL APPEARANCE 3.1-1 3.1.1 Structures 3.1-1 3.1.2 Arrangement of Structures 3.1-1 3.1.3 Architectural Features and Aesthetic Considerations 3.1-2 3.1.4 Release Points 3.1-2 3.2 REACTOR AND STEAM-ELECTRIC SYSTEM 3.2-1 3.2.1 System Description 3.2-1 3.2.2 Fuel Description 3.2-1 3.2.3 Power Output 3.2-2 3.2.4 Relationship of Station Heat Rate to Ex-pected Variation of Turbine Backpressure 3.2-2 3.2.5 Proposed Station Operating Life 3.2-2 3.3 STATION WATER USE 3.3-1 () 3.3.1 Circulating Water System 3.3.2 Service Water Systems 3.3-1 3.3-2 3.3.2.1 Nonessential Service Water System 3.3-2 3.3.2.2 Essential Service Water System 3.3-3 3.3.3 Steam Cycle Makeup and Potable Water Supply Systems 3.3-3 3.3.4 Variations in Plant Water Use 3.3-3 3.4 HEAT DISSIPATION SYSTEM 3.4-1 3.4.1 Natural Draft Cooling Towers 3.4-1 3.4.2 Mechanical Draft Cooling Towers 3.4-2 3.4.3 Intake and Discharge Structures 3.4-2a 1 3 3.5 RADWASTE SYSTEMS AND SOURCE TERMS 3.5-1 3.5.1 Source Terms 3.5-1 1 3.5.1.1 Sources of Radioactivity and Calculation ) Models 3.5-1 ' 3.5.1.2 Tritium 3.5-3 3.5.1.3 Fuel Pool 3.5-5 3.5.1.4 Leakage Paths 3.5-6 3.5.2 Liquid Radwaste System 3.5-6 3.5.2.1 Objectives 3.5-6 3.5.2.2 Input to the Liquid Radwaste System 3.5-6 3.5.2.2.1 Steam Generator Blowdown 3.5-7 Os' 3.5.2.2.2 Chemical Drains 3.5-8 3.0-i
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 TABLE OF CONTENTS (Cont'd) PAGE 3.5.2.2.3 Regenerant Waste Drains 3.5-8 3.5.2.2.4 Turbine Building Floor Drains 3.5-9 3.5.2.2.5 Turbine Building Equipment Drains 3.5-9 3.S.2.2.6 Auxiliary Building Equipment Drains 3.5-9 3.5.2.2.7 Auxiliary Building Floor Drains 3.5-10 3.5.2.2.8 Laundry Drains 3.5-10 3.5.2.3 Liquid Radwaste Discharges 3.5-10 3.5.3 Gaseous Radwaste System 3.5-11 3.5.3.1 Objectives 3.5-11 3.5.3.2 Gaseous Sources 3.5-11 3.5.3.3 System Description of the Gaseous Radwaste System 3.5-12 3.5.3.3.1 Building Ventilation Systems (Auxiliary Building and Solid Radwaste Building) 3.5-13 3.5.3.3.2 Normal Containment Purges 3.5-14 3.5.3.3.3 Steam-Jet Air Ejector 3.5-14 3.5.3.4 Gaseous Releases 3.5-15 3.5.3.5 Ventilation Stacks 3.5-15 3.5.4 Solid Radwaste System 3.5-16 3.5.4.1 Objectives and Design Basis 3.5-16 3.5.4.2 System Description 3.5-16 3.5.4.2.1 Drum Preparation Station 3.5-17 3.5.4.2.2 Decanting Station 3.5-17 h 3.5.4.2.3 Drumming Station 3.5-17 3.5.4.2.4 Drum Handling Equipment 3.5-18 3.5.4.2.5 Smear Test and Label Station 3.5-18 3.5.4.2.6 Dry Waste Compactor 3.5-18 3.5.4.2.7 Volume Reduction System 3.5-18 3.5.4.2.8 Radwaste Drum Storage Areas 3.5-19 3.5.4.2.9 Control Room 3.5-19 3.5.4.3 Interconnections with Liquid Radwaste 3 Systems 3.5-19 3.5.4.4 Shipment 3.5-19 3.5.5 Process and Effluent Monitoring 3.5-20 3.5A DATA NEEDED FOR RADIOACTIVE SOURCE TERM CALCULATIONS FOR PRESSURIZED WATER REACTORS 3.5A-i i 3.6 CHEMICAL AND BIOCIDE SYSTEMS 3.6-1 1 3.6.1 Cooling Water Systems 3.6-1 3.6.1.1 Circulating Water System 3.6-1 3.6.1.2 Service Water System 3.6-2a 3 3.6.1.2.1 Nonessential Service Water 3.6-3 3.6.1.2.2 Ecsential Service Water 3.6-4 3.6.2 Makeup Water Treatment System 3.6-4 3.6.2.1 Regeneration Wastes 3.6-4 & W 3.6.2.2 Filter Backwash Effluent 3.6-5 3.0-1i
I l i Byron ER-OLS AMENDMENT NO. 1 l JULY 1981 AMENDMENT NO. 3 , MARCH 1982 l TABLE OF CONTENTS (Cont'd) PAGE 3.6.3 Waste Treatment 3.6-5
, 3.6.4 Potable Water System 3.6-5 3.6.5 Radwaste System 3.6-6 3.7 SANITARY AND OTHER WASTE SYSTEM 3.7-1 3.7.1 Sanitary Wastes 3.7-1 1
3.7.2 Other Waste Systems 3.7-1 3.8 REPORTING OF RADIOACTIVE MATERIAL MOVEMENT 3.8-1 3.9 TRANSMISSION FACILITIES 3.9-1 3.9.1 Location and Description of Rights-of-Way 3.9-1 3.9.1.1 Byron Station to the Wempletown Trans-mission Substation 3.9-1 3.9.1.2 Byron Station to the Cherry Valley y Transmission Substation 3.9-2 3.9.1.3 Byron Station to the Existing Cherry Os Valley to Nelson Right-of-Way (Byron South Right-of-Way) 3.9-2 3.9.2 Line Design Parameters 3.9-3 3.9.3 Existing Substations Affected 3.9-3 3.9.3.1 Wempletown Transmission Substation 3.9-3 3.9.3.2 Cherry Valley Transmission Substation 3.9-3 3.9.3.3 Nelson Transmission Substation 3.9-3 3.9.4 Radiated Electrical and Acoustical Noise 3.9-3 3.9.5 Induced or Conducted Ground Currents 3.9-4 3.9.6 Electrostatic Field Effects 3.9-4 3.9.7 Ozone Production 3.9-4 3.9.8 Environmental Impact 3.9-5 3.9.9 Environmental Considerations of Trans-mission Routing 3.9-6 3.9.9.1 Byron to Wempletown Right-of-Way 3.9-6 3.9.9.2 Byron Station to Cherry Valley Substation 3.9-7 l 3.9.9.3 Byron South Right-of-Way 3.9-7 l 3.9.9.4 Summary 3.9-8 l l O l 3.0-iii
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 CHAPTER 3.0 - THE STATION LIST OF TABLES l NUMBER TITLE PAGE 3.2-1 Net Turbine Heat Rate 3.2-3 3.3-1 Average Seasonal Variations in Cooling Tower System 3.3-4 3.3-2 Variations in Plant Water Use 3.3-5 ! 3.4-1 Estimated Variation in Discharge l Temperature of Blowdown 3.4-1 3.5-1 Parameters Used in the Calculation of the Inventory of Radionuclides in the Secondary Coolant 3.5-21 3.5-2 Tritium Source Terms and Release Paths per Unit at the Station 3.5-22 3.5-3 Expected Annual Average Releases of Radionuclides in Liquid Effluents 3.5-23 3.5-4 Expected Annual Average Release of Air-borne Radionuclides 3.5-24 3.5-5 Parameters Used in the Gale-PWR Computer Program 3.5-26 3.5-6 Gaseous Radwaste System Component Data 3.5-29 3.5-7 Additional Ventilation Releases from Plant by Isotope 3.5-30 3.5-8 Annual Weight, Volume, and Activity of Radwaste Shipped from both Units at the Station 3.5-31 3.6-1 Seasonal Analysis of Rock River Water 3.6-7 3.6-2 Average Blowdown Water Analysis 3.6-8 3.6-3 Estimated Average Quantities. Discharged to the Atmosphere from Drift of Two Natural-Draft Cooling Towers at the Byron Station 3.6-9 l 3.6-4 Estimated Maximum Effluent Analysis 3.6-10 i 3.6-5 Estimated Average Effluent Analysis 3.6-11 l 3.7-1 Illinois Emission Standards 3.7-3 l 3.9-1 Environmental Considerations of New 1 Transmission Corridors 3.9-9 9 3.0-iv
Byron ER-OLS () 3.3 PLANT WATER USE This section describes the expected uses of water at the Bryon Nuclear Generating Station - Units 1 & 2 (Byron Station). The plant systems that require water are the circulating water system, the service water systems, the steam cycle supply An initial makeupofsystem, water and the potable water supply system. the reactor is provided for the primary water makeup system,and the refueling water and auxiliary systems. systems,Since most of the water from these systems is recycled, only a small amount of makeup water is required to compensate for evaporative losses. A flow chart that details the predicted Chemical, quantitative uses is depicted in Figure 3.3-1. thermal, and radiologic sections. Circulating water and service water makeup for the continuous operation of the Byron Station is obtained from the Rock River. Data pertaining to flow parameters of the Rock River areThe quantity of ma discussed in Section 2.4. is dependent primarily upon the following factors:
- a. the amount of cooling tower blowdown necessary to prevent the total dissolved solids content from increasing to a level in excess of that desirable for operating purposes or that permitted by state of
/~} (_/ , Illinois effluent requirements; and
- b. the amount of water lost due to evaporation and drift across the cooling towers, which is expected to vary depending on meteorological conditions and thermal loading as explained in Subsection 3.3.1.
3.3.1 Circulatina Water System The station circulating water system is a closed-cycle cooling water system used to dissipate the heat gained from the con-densation of steam formed in the secondary cycle by the steam generators. The cooling system consists of one natural draft cooling tower per unit, which dissipates the excess process heat to the atmosphere. The condenser cooling water is pumped to At the cooling tower at a rate of approximately 1408 cfs per unit. 100% load factor, the temperature rise of the water passing through the condenser is about 240 F, and the we' er temperature is reduced by about this amount while passing thsough the cooling towers. This temperature reduction is accomplished through the evapor Lion of a portion of the water and through conductive and convective sensible heat transfer mechanisms. Calculations have been made of the anticipated volumetric con-the loss through sumption of water by the plant (i.e., An analysis was g3
)
evaporation and drift from the cooling towers). (
'~' made of the amount of river water makeup needed to replace these 3.3-1
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 , losses and the amount of cooling tower blowdown necessary to O1 I control the chemistry of the circulating water system. The monthly average evaporation rates for two natural draft cooling towers have been estimated to range between 37.0 and 54.6 cfs. The evaporation rates decrease in winter and increase in summer. The losses due to drift are approximately 0.06 cfs, or 0.002% of the circulating water flow. The blowdown necessary to maintain water chemistry was calculated using these evaporative and drift losses. Varying the blowdown between 20.0 and 36.9 cfs will maintain a total dissolved solids (TDS) level between 1375 3 and 1823 mg/ liter. The exact value depends on the river analysis and the evaporation rate. The higher blowdown occurs during the summer when evaporation rates are higher than other seasons. To compensate for the evaporation, drift, and blowdown, the makeup taken from the Rock River varies between 68.1 to 86.3 cfs. l3 Table 3.3-1 presents the seasonal variations of the cooling system. The average makeup is 76.9 cfs. These figures have been calculated based on operation at a 100% load factor. Under most circumstances, the two-unit Byron Station will be capable of operating at full load with cooling tower consumptive losses supplied by a net withdrawal rate no greater than 10% of the Rock River flow. During the simultaneous occurrence of abnormally adverse weather and low river flow, however, cooling tower consumptive demand at full load may exceed 10% ci the river flow. In this instance, the net withdrawal from the river will be maintained at a level acceptable to the Illinois Department of Conservation. If the consumptive demand at full load exceeds this level, the plant power level will be reduced until the river flow increases sufficiently to allow the withdrawal rate necessary for full power operation. 3.3.2 Service hater Systems Service water is used to cool plant and auxiliary equipment. There are two service water systems provided for the plant, the nonessential service water and the essential service water systems. 3.3.2.1 Nonessential Service Water System The nonessential service water cools equipment that is not safety-related and not essential for the safe shutdown of the reactor. The water is taken from the cold side of the cooling tower. After its use the nonessential service water returns to the natural draft cooling towers along with the condenser cooling water. The nonessential service water circulation rate is about 78 cfs per unit. Makeup and blowdown are sent to and taken from the cooling towers as was discussed in Subsection 3.3.1. gg 3.3-2
1 Byron ER-OLS () 3.3.2.2 Essential Service Water System The essential service water cools the equioment that is safety-
! related. The design provides for two identical, full-capacity systems for each unit. Each unit has two full-capacity pumps, each of which takes suction from a separate supply line. This system supplies water to the reactor containment fan coolers, the diesel generator coolers, the component cooling heat exchangers, and the other equipment necessary for the safe shutdown of the reactor. The total requirement for circulating water for the ; essential service water system is approximately 54 cfs per unit.
Two mechanical draft cooling towers are provided to cool the essential service water. The makeup water for the towers is from the Rock River. The blowdown from the mechanical draft towers is routed to the basins of the natural draft cooling towers. The maximum makeup under post-accident conditions is about 4 cfs and the blowdown 2 cfs. 3.3.3 Steam Cycle Makeup and Potable Water Supply Systems Deep wells are used to supply the water necessary for the makeup demineralizer and the potable water system. A discussion of the groundwater conditions may be found in Section 2.4. There are two deep wells with one pump unit per well. Each well is capable of producing 2.67 cfs; one is a spare. Both wells can be operated simultaneously, giving a total capacity of 5.34 cfs. (emg_) Deep well water is used for demineralized water, regeneration water, filter backwash water, and potable water. These demands require a average of 1.1 cfs to be pumped from the well. The details of the makeup system are presented in Subsection 3.6.3. Well capacity is such that makeup to the essential service water system could be supplied during a tornado or probable maximum flood condition (see Section 2.4), which could cause the river pumping system to be inoperable. The plant potable water treating system also provides water for sanitary purposes. The water is obtained from deep wells on the plant site. All the well water passes through three sand filters for iron and manganese removal into a 150,000-gallon filtered water storage tank. From this tank 15,000 gallons per day are drawn off for processing through the potable water system. The treatment consists of chlorination and softening of the water. The withdrawal of the water from the deep wells complies with the applicable federal, state, and local regulations. Further information on sanitary water and its disposal is contained in Section 3.7. 3.3.4 Variations in Plant Water Use Variations in plant water consumption, for 100% operation, 50% operation, hot standby, and cold shutdown conditions are given in j Table 3.3-2. l l ! 3.3-3 -, R
Byron ER-OLS AMENDMENT L3. 3 MARCH 1982 TABLE 3.3-1 AVERAGE SEASONAL VARIATIONS IN COOLING TOWER SYSTEM (at 100% load factor) WINTER SPRING SUMMER FALL AVERAGE Makeup (cfs) 68.1 72.7 86.3 80.5 76.9 Evaporation (cfs) 38.7 46.8 53.4 48.1 46.7 Drift (cfs) 0.06 0.06 0.06 0.06 0.06 Blowdown (c f s) 29.3 25.8 32.8 32.3 30.1 TDS of Blowdown (mg/ liter) 1823 1374 1415 1607 1555 3 O l til 3.3-4
AMENDMENT NO.3 1 4 ROCK RIVER (MEAN ANNUAL FLOW - 4580 CFS) MARCH 1982
% f N #
k MAKEUP 76 9 CFS
> BLOWDOWN MAKEUP 4 CFS 301 CFS lf BLOWDOWN jf EVAPORATION 46 7 CFS4 - 4 STEAM NATURAL ORAFT 2 CFS MECHANICAL DRAFT I'E ER^ COOLING TOWERS
- COOLING TOWERS
~
g D N DRIFT 0 06 CFS +- A f JL EVAPORATION y PL\NT 2 CFS WAbTE DRIFT 0 01 CFS lf if ONDENS8 NONESSENTIAL ESSENTIAL RADWASTE
+ SYSTEM COOLING SERVICE SERVICE 4 WATER 2815 CFS WATER 156 CFS WATER 107 CFS If II If SOLIDS TO )L RECYCLE APPROVED OFFSITE DISPOSAL BACKWASH 2 2 CFS lf 5-10 MIN EACH jf DAY f ) 0 33 0 33 V CONDENSATE CFS MAKEUP CFS FILT ERED INLETS INLETS SAND DEEP STORAGE h WATER h WATER h FILTERS WELLS TANK TREATMENT STORAGE INTERMITTENTLY INTERMITTENTLY y y NONRADIOACTIVE SEWAGE 0 22 CFS POTABLE WASTE
< TREATMENT 4 WATER WATER PLANT INTERMITTENT LY SYSTEM TREATMENT BUILDINGS I
I l l BTRON NUCLEAR GENERATING STATION UNITS 1 & 2 ENVIRONMEf4; AL REPORT - OPERATING LICENSE STAGE
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FIGURE 3.3-1 WATER USAGE FLOW DIAGRAM
Byron ER-OLS AMENDMENT NO. 3
; MARCH 1982 O 3.4 HEAT DISSIPATION SYSTEM 3.4.1 Natural Draft Cooling Towers At the Byron Nuclear Generating Station - Units 1 & 2 (Byron Station), natural draft towers were chosen for primary cooling and mechanical draft towers for essential service water cooling and for the ultimate heat sink. The use of cooling towers minimizes both the land area used for cooling purposes and the effects of heat dissipation. The operational effects of the cooling towers, with respect to meteorology, is discussed in Subsection 5.1.4.
The two natural draft towers are located as shown in the property diagram, Figure 2.1-4. Each tower consists of a 495-foot high concrete hyperbolic shell, a 605-foot diameter basin, and a 272-foot exit diameter. The towers are designed to dissipate approximately 15.2 x 10' Btu /hr of heat absorbed by the circulating water system during a 13.1-second time-of-travel across the main condensers of the two units. d The design parameters that significantly affect the temperature of the blowdown are those that affect the performance of the natural draft towers. Each tower circulates 662,000 gallons per () N-minute of cooling water, of which 35,000 gal / min is service water. At the design conditions of 890 F dry bulb temperature 3 and 760 F wet bulb temperature, the towers cool the water trom 1160 F to 920 F. In a natural draft tower the cooling water being circulated through the plant falls through a draft of air; heat is carried away mostly by evaporation and partly by sensible heat transfer. The rest of the water is collected at the bottom of the tower and returned to the cooling cycle. The flow of air through the tower is caused by a " chimney effect:" the density difference between the cool outside ambient air and the less dense inside air warmed
.by the water. At the design conditions, the ratio of the water flow to the air flow is approximately 2.35:1 by weight. This ratio decreases in cooler weather; i.e., more air will pass through the tower.
The evaporation rate for ute two natural draf t towers when the plant is operating at full load varies between seasonal averages i of 38.7 cubic feet per second (cfs) of water in the winter and 53.4 cfs in the summer. The maximum monthly evaporation has been calculated to be approximately 54.6 cfs. The maximum drift loss has been specified as 0.002% of the circulating water flow or 0.06 cfs. g To keep the total dissolved solids (TDS) concentration within the _j limits set by water pollution regulations and operating requirements, water has to be continuously withdrawn from the l tower basin. This water is called blowdown. For these purposes, l l l 3.4-1
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 an average blowdown rate of about 30.1 cfs is required. The quantity of blowdown is dependent upon the water chemistry considerations and the evaporation rate of the cooling tower. The evaporation rate at any one time is dependent on the heat load and the ambient conditions at that time. Blowdown from the natural draft towers is returned to the Rock River through a discharge structure (see Figure 3.4-1) at an average rate of 30.1 cfs and a maximum velocity of 4.3 feet per second. There are two modulating valves on the blowdown line so that blowdown can be stopped during shutdown or refueling. The TDS concentration of the blowdown averages about 1555 mg/ liter. l3 As a result of the discharge of the blowdown into the flowing Rock River, a thermal plume is established downstream whose detailed temperature profile depends on river conditions and the blowdown characteristics. The extent and effect of this plume are discussed in Section 5.1. A discussion of the blowdown temperature is included in Subsection 5.1.2. The total water loss attributable to evaporation, drift, and blowdown has to be replaced to maintain a constant cooling water flow. This quantity is called makeup and amounts to an average of approximately 68.1 cfs in the winter and 86.3 cfs in the summer for full load operation. Table 3.4-1 shows the median monthly temperatures for the blowdown with both units operating at 100% load factor. The predicted temperature ranges from 60.40 F in January to 87.00 F in July. 3.4.2 Mechanical Draft Cooling Towers In addition to the two natural draft towers, two mechanical draft towers, which cool the essential service water, have been built at the site. The mechanical draft towers are located as shown in Figure 2.1-4. Each tower consists of 4 cells. The overall dimensions of each tower are 50 feet high, 174 feet long, and 45 feet wide. Each tower is designed to cool 52,000 gal / min of water from 1380 F to 980 F under post-accident conditions concurrent with a 780 F wet-bulb temperature. The guaranteed water flow to each tower is 48,000 gal / min. The cooling range 3 under normal operating conditions, however, will be apprc,ximately 100 F. The evaporation rate for these towers is a maximum of 2 cfs, with a maximum blowdown of 1.56 cfs; drift losses are negligible. The maximum required makeup for these towers is therefore 3.56 cfs. O 3.4-2
4 Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 O 3.4.3 Intake and Discharge Structures Makeup is withdrawn from the Rock River through an intake structure as shown in Figure 3.4-2. The location of the intake i (river screen house) and discharge structures is shown on Figure 3.4-3. The intake structure operating floor is located at an elevation of 687 feet above mean sea level (MSL), which is above
- the 1973 flood (flood of record) elevation of 683.6 feet MSL.
1 1 i i i l i l
-)
! 3.4-2a
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 O t i
\~/ c. demineralizer regenerantion wastes,
- d. turbine building floor drains,
- e. turbine building equipment drains,
- f. auxiliary building floor drains, and
- g. laundry drains.
Figure 3.5-1 shows a simplified process flow diagram with input streams b to g combined and labeled as radioactive liquid wastes. Complete piping and instrumentation details appear in Appendix 3.5A as part of the response to Request 2 of Subsection 3.5A.4. The average and maximum daily flows are given in Table 11.2-6 of 3 the FSAR. These flow rates constitute the design basis for sizing the radwaste components. The expected isotopic content and the basis of each of the radwaste input streams is given in Table 11.1-6 of the FSAR. Total curie content for each collection tank may be obtained by multiplying the isotopic concentrations by the tank volume. b\
'~#
Table 11.2-5 of the FSAR lists the major components of the radwaste system and their d'esign parameters. Estimates of hold-up times are as follows:
- a. all collection tanks - filling rate of the tank to 60% capacity of the average daily flow,
- b. all monitor tanks - filling rate of the tank to 80%
capacity at the average daily flow,
- c. evaporators - 14 hours,
- d. demineralizers - few minutes, and
- e. filters - few minutes.
Decontamination factors for the equipment assumed in the release calculation are given in Table 11.2-7 of the FSAR. 3.5.2.2.1 Steam Generator Blowdown The purpose of the steam generator blowdown subsystem is to provide means for controlling the water chemistry in the steam generators. Normally, the steam generator blowdown is non-("S; radioactive, and a blowdown rate of 20 to 60 gallons per minute (,,' (gpm) (28,800 to 86,400 gal / day per unit) is sufficient. For I 3.5-7 i
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 purposes of conservatism, however, the design of the blowdown subsystem is based on a continuous 1 gpm primary to secondary h i f l ) i i n 4 i O 3.5-7a
- ._ .=. .- - .. - - _. - ~_ .
Byron ER-OLS l () leak for 14 days. During leak conditions, secondary water becomes radioactive and will reach an isotopic inventory equilibrium inversely proportional to the blowdown rate. The i higher the blowdown rate, the lower the radioactive content of the secondary water. Hence, with a gross radioactive leak, blowdown is increased to 135 gpm (184,400 gal / day) for the leaking unit. t The blowdown isotopic inventories listed in Table 11.1-6 of the FSAR correspond to 1/135th of the expected reactor coolant activity. Blowdown is cooled through one of two blowdown condensers. The two blowdown condensers are cross-tied to one'another to permit operating flexibility. The cooled blowdown liquid is filtered and demineralized. Each unit has two prefilters so that flow can be processed without interruption when one filter is being replaced. During normal non-radioactive operation, blowdown from each unit is processed separately through its own demineralizer. ) In the case of a 1-gpm radioactive leak, blowdown through the j leaking steam generator is increased while blowdown through the non-leaking unit is unchanged. ( 3.5.2.2.2 Chemical Drains 3 Generally, chemical drains consist of liquid with a high chemical
- content, such as laboratory drains. In addition, other' sources
) are drained from the drumming station, the spent resin storage tank, the spent resin sluicing header, and the spray additive tanks. i These drains are collected in a 6000-gallon chemical drain tank { for sampling. They are then processed on a batch basis through a filter and the 30-gpm radwaste evaporators. The evaporator distillate is also demineralized as necessary. 4
- j. Average isotopic activity levels for chemical drains are given in
- Table 11.1-6 of the FSAR. Substantial variations from the
- concentrations given are expected.
Estimated average daily flow input is 2100 gallons or less. The i maximum daily flow of 6000 gallon is expected to occur at the end
- of a fuc1 cycle when demineralizer resins are replaced and various chemical tanks are drained. The chemical _ drain system is chared by both units.
3.5.2.2.3 Regenerant Waste Drains 1 l - Input.to this subsystem consists of regeneration chemicals.and 4 5- backwash water from the regeneration of the recycle evaporator condensate demineralizer,-the radwaste demineralizers, and the 3.5-8
1 1 I Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 blowdown demineralizers. These wastes are pumped to a 10,000-gallon tank for collection and sampling. The recycle evaporator condensate demineralizer, which is shared by both units, is expected to be regenerated three times per calendar year, producing about 4000 gallons of wastes per regeneration. The radwaste mixed-bed demineralizers, which are shared by both units, are regenerated as often as required to maintain a decontamination factor of 10 for soluble ions. Each radwaste mixed bed de.nineralizer requires regeneration every 1 to 2 weeks depending on usage, and produces about 1850 gallons of waste per regeneration. Expected sources are given in Table 11.1-6 of the FSAR. 3 3.5.2.2.4 Turbine Building Floor Drains The turbine building floor drains are shared by two units. The expected flow rates are an average of 4,200 gal / day, with a maximum of 12,000 gal / day. The two turbine building floor drain tanks have a capacity of 12,000 gallons each. Turbine building floor drains, which are normally non-radioactive, may be released from the plant without treatment other than filtration after sampling. If sampling indicates that the wastes are not suitable for release, they will be processed through the radwaste evaporators and recycled. The expected sources are given in Table 11.1-6 of the FSAR. 3.5.2.2.5 Turbine Building Equioment Drains The turbine building equipment drains are shared by both units. The expected flow rates are an average of 4,200 gal / day, with a maximum of 12,00 gal / day. The two turbine building equipment drain tanks have a capacity of 12,000 gallons each. After sampling, the turbine building equipment drains are normally processed through one of the blowdown mixed bed demineralizers and recycled. Expected sources are given in Table 11.1-6 of the FSAR. 3.5.2.2.6 Auxiliary Building Equipment Drains The auxiliary building equipment drains collect an average of 5600 gal / day and a maximum of 16,000 gal / day. The expected sources are given in Table 11.1-6 of the FSAR. Since all equipment in the auxiliary building containing potentially radioactive liquid is periodically drained into this subsystem, the volume and activity on any given day varies according to the operations in progress, such as replacing filter elements, draining ion exchange vessels, and flushing and cleaning tanks and equipment. 3.5-9
I Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 I These equipment drains are collected in two 8000-gallon tanks, i which are shared by both units. After sampling, the wastes are i processed through filters and the radwaste evaporator. i i 2 4, i i l i i I ( I I 4 1 ~ 3.5-9a
Byron ER-OLS 3.5.2,2.7 Auxiliary Building Flooc Drains The auxiliary building floor drains collect an average of 5,600 gal / day and a maximum of 16,000 gal / day. The expected sources are given in Table 11.1-6 of the FSAR. These drains include pump baseplate drains in the auxiliary building, reactor coolant leakages, pump seal and stuffing box leakages, valve stem packing leakages, and other equipment overflows or spills. Inputs also include waste from operations such as washdown and equipment maintenance. These floor drains collect in two 8000-gallon tanks that are shared by both units. After sampling, the waste is filtered and evaporated. 3.5.2.2.8 Laundry Drains Laundry wastes are collected directly from the laundry facilities of the two units. The expected average daily flow for this subsystem is 1400 gallons, with a maximum daily flow of 4000 gallons for both units. The expected activities are given in Table 11.1-6 of the FSAR. The laundry wastes are collected in one 4000-gallon tank and two 2000-gallon tanks. After sampling, the waste is filtered and evaporated. Because of potentially high carry over due to the detergent, the laundry waste will be processed separately from other wastes. 3.5.2.3 Liquid Radwaste Discharaes All liquid wastes to be released are analyzed for gross beta, gamma, and tritium activity in one of the five 20,000-gallonThe liquid monitor tanks after thorough mixing by recirculation. is then pumped to the 30,000-gallon release tank where a sample is again analyzed for gross beta, gamma, and tritium activity. Based on this analysis, a discharge rate is determined so that, when mixed with cooling tower blowdown, the water leaving the plant has a radioactivity level less than the applicable MPC as stated in 10 CFR 20. A key-locked switch The may then be manually opened so that water can be discharged. key for the valve lock is controlled by administrative procedures. As a further backup, a radiation detector monitors the discharge line before the discharge is mixed with the cooling tower blowdown to the river. Upon detecting an abnormal level of radiation, a valve on the release tank line immediately ahead of the mixing point closes and an alarm signal is relayed to the control room. Records are maintained of all radioactive wastes discharged to the environs to verify that radioactive releases conform with the requirements of 10 CFR 20 and 10 CFR 50. Liquid radwaste releases were calculated using the PWR-GALE computer program and the parameters listed in Table 3.5-5. Expected annual activity releases to the discharge canal are given in Table 3.5-3. The radiological impact of these rele.'ses is discussed in Section 5.2. 3.5-10
Byron ER-OLS All radioactive noble gases entering the main ("'
\
condensers. condenser are assumed to be removed from the system by the SJAE. The SJAE exhaust exhausts through the plant vent. In the event of high radioiodine activity in the SJAE exhaust, off-gases are released through both HEPA filters and a charcoal filter system affording a DF of 10 for iodine. 3.5.3.4 Gaseous Releases Releases of radionuclides in gaseous effluents were calculated using the PWR-GALE computer program and the parameters listed in Table 3.5-5. Expected annual releases of radioactive noble gases and particulates are given in Table 3.5-7. Thc tadiological impact of these releases is discussed in Section 5.2. 3.5.3.5 Ventilation Stacks Two ventilation stacks exhaust air emissions to the atmosphere. Each rectangular stack has inside dimensions of 13 feet 3-3/8 inches by 5 feet 0 inches. The stacks terminate 200 feet above grade at an elevation of 1069 feet above sea level. Each stack (one for each unit) handles the exhaust air from the following:
- a. auxiliary building ventilation system exhaust; b
N/ b. solid radwaste ventilation system exhaust;
- c. normal containment purge system exhaust; and
- d. miscellaneous vents collected from various sources such as battery rooms, laboratory facilities, waste-gas decay tank vents, air ejector, and decontamination room.
The following is a list of the approximate ventilation exhaust rates through the vent stack. < a. auxiliary building ventilation exhaust air - 150,000 cfm;
- b. solid radwaste ventilation system - 15,000 cfm;
- c. normal containment purge system exhaust air - 40,000 cfm; and
- d. miscellaneous vents collected from various sources such as battery rooms, laboratory facilities, waste-gas decay tank vents, air ejector, and decontamination room - 8,140 cfm.
O 3.5-15
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 Total air capacity exhausted through the exhaust vent is approximately 214,000 cfm, which corresponds to 2,800 ft/ min face velocity. Under all plant operating conditions, a radiation detector in the exhaust vent continuously monitors the radioactivity level of the exhaust air before its release to the atmosphere. At high radioactivity levels, this detector sounds an alarm in the main control room and alerts the operator to initiate corrective action. Figure 3.5-3 depicts the general arrangement of the plant's roof and shows the location of the vent stacks. 3.5.4 Solid Radwaste System 3.5.4.1 Obiectives and Design Basis The Byron Station solid radwaste system is designed to receive, dewater, solidify with cement, seal in a 55-gallon drum, and temporarily store the ;ollowing wastes: demineralizer bead resins, evaporator concentrates, and spent filter cartridges. The system also receives, compacts, and temporarily stores radioactive dry wastes produced during station operation and maintenance. Evaporator concentrates and dry active waste (DAW) residue can also be solidified by polymer after being processed 3 by the volume reduction system. Closed-top drums approved by the U. S. Department of Transportation (DOT) are used for packaging solidified wastes, and DOT-approved open-top drums are used for packaging dry solid wastes. The expected annual weight, volume, and activity of solid radwaste shipped from the Byron Station appear in Table 3.5-8, which gives values both with and without 3 the use of a volume reduction system. Packaged radioactive solid wastes are shipped off the site and buried in accordance with applicable Nuclear Regulatory Commission (NRC) and DOT regulations. The system is designed specifically for a 40-year service life, maximum reliability, minimum maintenance, and minimum exposure to station personnel and the general public. The expected solid radwaste system output is 5760 to 6910 drums l per year if the volume reduction system is not operational and 3 900 to 940 drums if it is. 3.5.4.2 System Description Operation of the solid radwaste system is indicated in Figure 3.5-4 of the ER and Figure 11.4-7 of the FSAR. Table 11.4-1 of l3 the FSAR lists the process equipmen' and storage design capacities. A more detailed system description is given in the Byron Final Safety Analysis Report (FSAR) Subsections 11.4.2 and 3 11.4.3. The solid radwaste system is comprised of the following nine components: 3.5-16
l l Byron ER-OLS AMENDMENT NO. 3 l MARCH 1982 O a. drum preparation station,
- b. decanting station,
- c. drumming station,
- d. drum handling equipment,
- e. smear test and label station,
- f. dry waste compactor,
- g. volume reduction system, 3
- h. radwaste drum storage areas, and
- i. control station.
Each is discussed separately in the following subsections. 3.5.4.2.1 Drum Preparation Station This station consists of cement unloading, storing, feeding, weighing, and conveying equipment used to load 55-gallon drums. A mixing weight is added to the drum to ensure uniform mixing (~s\ -) when the drum is tumbled. The unit is designed for dust-free operation, with an exhaust-air filter assembly attached to the side of the fixing material storage tank to capture dust generated within the tank. . 3.5.4.2.2 Decanting Station This station consists of a stainless steel decanting tank that receives spent resins, a progressive cavity decanting pump that removes excess liquid, a piston-type metering pump that transports accurate quantities of waste from the decanting tank to the drum, and all associated valves ard instrumentation to provide remote manual operation of the unit. Processing equipment in contact with radioactive materials is locatedMost on the radioactive side of a thick machined-steel shield wall. drives, limit switches, and instrumentation are located on the l low radiation side of the shield wall to minimize the dose to i maintenance personnel. 3.5.4.2.3 Drumming Station This station consists of a drum processing-unit and a heat-traced, piston-type metering pump. The pump transports accurate quantities of waste from the concentrated waste tank to the drum. r3 The drum processing-unit is essentially a stainless steel box with an air-cylinder actuated hatch in the top. The following () remotely-performed operations occur within the drum processing-unit: cap removal, drum filling, cap reinsertion, tumbling of 3.5-17
l l Byron ER-OLS AMENDMENT NO. 3 i l MARCH 1982 the drum for mixing, and washing the exterior of the drum if re-quired. Two separate fill nozzles are provided, one for spent resins and one for concentrated waste. A scale and a radiation monitor provide drum weight and activity level readouts on the control console after removal from the drum processing-unit. 3.5.4.2.4 Drum Handling Equipment This equipment includes three remotely operated cranes with television cameras for visual surveillance, two drum transfer cars, and a filter-cartridge transfer vehicle. The cranes are used to transport preloaded drums to the drumming station, remove and position drums on a scale, transport and position sealed drums in either high- or low-level storage, and retrieve and transport them to trucks for offsite disposal. The drum transfer cars transport drums between the process units and the storage area. The filter-cartridge transfer vehicle transports drums containing spent filter cartridges from the filter area to a place where the drums may be placed on a drum transfer car. 3.5.4.2.5 Smear Test and Label Station This. station consists of a motor-operated turntable setdown position for drums behind a small shield wall equipped with access plugs and working tools to accomplish remote labeling, smear testing, and radiation monitoring of all external surfaces of sealed drums before offsite disposal. 3.5.4.2.6 Dry Waste Compactor The dry waste compactor compresses paper, fabrics, plastics, and other wastes into 55-gallon drums. A large-diameter, pneumatically-powered ram drives the platen down into the drum. During compaction, a safety shield encloses the loading areas above the drum and protects the operator from debris that might escape. An air filtration assembly maintains control of 1 contaminated particles during compactor operation. Radioactive dust is captured by means of a roughing filter and two HEPA , filters operating in parallel. The filtration system is ' interconnected to the plant radioactive vent system. The radioactivity of most of the dry waste is low enough to permit manual handling. 3.5.4.2.7 Volume Reduction System The major components of this system are a fluidized bed dryer, a dry waste processer, a gas-solids separator, a condenser, two 3 scrubbers, and an air filtration unit. The system eliminates the water from the evaporator concentrates and reduces combustible material to ash. The remaining salts and ash are solidified in polymer. The air exhausted from this system is passed through 3.5-18
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 O two HEPA and one charcoal filter before entering the auxiliary
\ /' 3 building filtered vent exhaust system.
3.5.4.2.8 Radwaste Drum Storage Areas Shielded areas are provided for the storage of low-activity and intermediate-activity waste drums and of compacted dry-waste drums according to the recuirements noted in Table 11.4-1 of the FSAR. Storage space is designed to accommodate approximately 20% of the normal yearly output of packaged waste (i.e. without Visual VRS) 3 or 1.3 years of output from the volume reduction system. surveillance for the low-activity and intermediate-activity waste storage areas is provided by the drum handling system television cameras. The intermediate-activity waste storage area capacity is sufficient to allow a decay of 60 days when used on a rotating basis. 3.5.4.2.9 Control Room 3 This room houses equipment for the remote visual monitoring and control of the solid radwaste building system. A liquid / solid interface control panel is provided for transferring waste to the solid radwaste system from the liquid radwaste system. ; 3.5.4.3 Interconnections With Liquid Radwaste Systems
-%) '- The solid radwaste system i's interconnected with the liquid radwaste systems via the spent resin and concentrated waste system comprised of the following tanks:
- a. concentrates holding tank, and
- b. spent resin tank.
3 Tank capacities are given in Table 11.2-5 of the FSAR. Spent resins are discharged to the decanting station, dewatered, and then routed to the drumming station for solidification. Concentrates are pumped from the concentrates holding tank directly to the drumming station. i ( 3.5.4.4 Shipment All wastes are shipped from the site by truck after solidification (compacting for dry compressible wastes). The empty drum storage area for shipping containers is shown on 3 Figure 11.4-3 of the FSAR. l l Intermediate-level wastes will be shipped with sufficient ! shielding to meet the regulations governing radioactive l shipments. m 3.5-19
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 1 3.5.5 Process and Effluent Monitoring The release points described in Subsection 3.1.4 are monitored for potentially radioactive effluents in the following manner:
- a. Continuous radiation monitoring of gaseous effluents is provided for each of the two auxiliary building vent stacks. No automatic control action occurs at high radioactivity levels, but alarms alert operating personnel to take corrective action.
- b. Potential radioactive release to the circulating water blowdown line is continuously monitored at the injection point from the radwaste system release tank into the blowdown line. If high radioactivity-level setpoints are reached, the monitor automatically closes the release pump discharge valve.
- c. Releases from the natural-draft cooling towers by way of the circulating-water System can occur only if multiple leakage paths exist between the primary- and circulating water systems. Radioactive leakage from l3 the primary to secondary system is continuously monitored in the steam generator blowdown system and steam-jet air ejector exhaust.
- d. Radiation release by the essential-service-water cooling towers is continuously monitored at the reactor containment fan-coolers service-water discharges and the component cooling-water heat ex-changers discharges. No automatic control action occurs at high radioactivity levels, but alarms alert operating personnel to take corrective action.
A detailed description of process and effluent radiation monitors is presented in Section 11.5 of the Byron Station FSAR. O 3.5-20
. . , _ _ . -.m . . _ .-_.m. ..__m _ . __m . _ _ , . __ ___ m._ _ ._ _ _ _. .m. .
_ __ ._ _ .._m.. O c TABLE 3.5-3 EXPECTED ANNUAL AVERAGE RELEASES OF RADIONUCLIDES J IN LIQUID EFFLUENTS J ANNUAL RELEASES M DISCHARGE CANAL BORON MISCEL- TCrrAL CORROSION COOLANT DETERGENT TURBINE LIQUID AILTUSTED NUCLIDE CONCEfrTRATIONF RECOVERY LANEOUS AND BUILDING WASTE TOTAL WASTES TOTAL SYSTEM WASTES SECONDARY I ACTIVATION HAIE-LIFE FRIMARY SECONDARY (curies) (Ci/yr) (ti/yr) (C1/yr) (days) (pCi/ml) (uC1/el) (curies) (curies) (curies) (curies) _ PRODUCTS
*9 -6 6.2 x10~
I ~3 -6 0.00 2.48x10' 7. 85x10 -6 6.16x10~~ 0.00
~3 ~3 Cr-51 2.78x10 2 1.90x10 ~4 2.51x10" 5.36x10~ 6.13x10 ' ~
- 1. 53x10 1.00x10 6.08x10" 9.21x10 O.00 6.05x10 ' 1.20x10~ 1.0x10~
Mn-54 3.03x10 3.10x10 ~3 1.05x10 ' ~ 6.89x10
-6 5.40x10 0 0.00 5.4x10 1.60x10~3 4.7/x10~~6 5.44x10~ O.00 2.11x10 -6 Fe-55 9.50x10 I 2.12x10~ 1.54x10 -5 4.42x10 3.47x10 ~4 0.00 3 5x10 ~3 Fe-59 4.50x10 I 1.00x10 -2 1.55x10~ 2.Bex10 ~5 3.29x10 -8 0.00 ~3 tIl g,gg 3,34,3g 6.81x10~-6 5.35x10~ 4.00x10 ~3 4.5x10 -3 co-58 7.13x10 3 1.60x10~ 2.15x10 4.67x10-6 5.34x10 -6 8.69x10 -6 s.70x10 8.8x10 ~$ M 0.00 2.72x10 -6 6.82x10~
Co-60 1.92x10 2.00x10~ 2.73x10"~ 5.97x10~ 6.81x10 2.32x10~
' O.00 1.14x10 2.96x10 2.32x10 0.00 2.3x10 Np-239 2.35x10 1.20x10 1.23x10 1.82x10 y o e
@ FISSION PRODUCTS I
-6 ~6 ~5 -5 2.11x10 2.69x10 '
~
O.00 2.24x10 2.24x10 6 1.76x10 0.00 1.sx10-Br-83 1.00x10"I . 4.80x10~ 1.26x10~~8 4.69x10 4.7x10 5 1.40x10 5.82x10 1.34x10 0.00 1.38x10 5.98x10 0.00 Rb-86 1.87x10 8.50x10~ 1.63x10 -4 1.28x10 ~3 0.00 1.3x10 ~3 (/) 1.01x10 1.16x10 0.00 6.13x10 Sr-89 5.20x10 3.50x10* 6.17x10~ 1.11x10~~ 2.53x10 *# 1.98x10 0.00 2.0x10 8.40x10 1.42x10'# 1.76x10' O.00 Mo-99 2.79x10, 1.19x10~ ~ 0.00 1.58x10,# 2.94x10 2.31x10 0.00 2.3x10~ 4.80x10, 2.18x10 1.35x10,7 1. 65x10 9 Tc-99m 2.50x10,g 1.40x10 0.00 1.4x10 -5 Te-127 3.92x10 0.50x10 1.31x10 8.4fx10 1.24x10 0.00 9.37x10 '7~ 1.78x10 '6 4.59x10
~
0.00 4.6x10 5 Te-129m 3.40x10 1.40x10j 1.87x10 3.99x10[6 4.56x10 0.00 1.85x10,, 5.85x10,6 Te-129 4.79x10,3 1.60x10,3 5.39x M ,7 2.56x10 -6 2.94x M -8 0.00 30 # ~5 I'.09x10 1 3.86xM -5 1.38r10 -6
* "" 4 1.09x10 0'00 0.00 3 *0*"
1.1x10
-4 1-130 5.17x10 2.10x10 1.53x10 2.95x10 1.18x10 0.00 2.07x10 ,'3 4.17x10 3.27x10~ 0.00 ,g 3.3x10 Te-131m 1.25x10 2.39x10 2.1Cx10[6 3.24x10[ i 2.50x10} 3.72xM -6 6.62xM -5 3
0.00 3.OxM -5 I* * -
- 6.20xM 8.0xM 1-131 8.05x10 0 2.70x M ,7 7. 6W- 8 0'.16x10 -4 Te-132 3.25x104 2.70x10,g 3ExM -6 '#* 6.02xM,7 0.M 2.%x W ,4 7.85x M ,54 6 ,3 0.00 6.2x(43
-5 3.47x10 -6 c.00 1.77x10 ~3 2.28x10 ~3 1.79x10 -2 0.00 1.8x10 -2 "g">g C.4 >
1-132 9.58x10~ 1.00x10~ 9.32x10 5.11x10~ 3.7x10 -2 gg 1.85x10 3.65x10 -6 0.00 2.80x10 4.66x10 3.66x10 -2 0.00 I-133 8.75x10 3.80x10 3.43x10~ ~ 1.30x10
-2 2.8x10 ~3 T CU M trj
- 1.86x10~ 4.25x10 0.00 3.99x10~ 1.50x10 1.91x10 '3 4.35x10'3 Cs-134 7.49x10 2.50x10" 4.01x10~ 5.33x10 ' 5.54x10~~4 0.00 4.3x10~
OZ *< Z 1-135 2.79x10 1.90x10 9.%x10 2.1Cx10~~ 5.1cx10"I ~b 0.00 6.9310 -2 Z U 1.30x10~ 1.78x10' 8. 59x10 I 1.92x10 O.00 1.75x10~ 8.79x10 6.89x10'I 0.00 -2 Cs-136 .1.30x10 3 1.08x10 2.40x10 3.5x10 1.10x10,4 1.80x10 2.67x10 3.06x10 0.00 2.65x10 1.37x10[3 g Cs-137 1.34x10[3 1.29x10 -6 0.00 1.0x10 ,5 OZ mZ 1.77x10 3 7.67x10 -6 1,26x10 2.87x10,9 0.00 2.48x10 -6 1.01x10,3 Ba-137m 1.60x10,g -6 0.00 2.98x10 6.94x10 5.44x10 0.00 5.4x10- mg gg All others 2.53x10 2.03x10 3.95x10 7.5(x10 , N ME
~3 -2 -I ~I 0
1.50x10~ 1.42x10~ 2.4Sx10 0.00 7.60x10 2.19x10 1.72x10 6.23x10'# 2.3x10 . . r ) 1.46x10 Tritium W N Release 300 Ci/yr H w e 4
TABLE 3.5-4 EXPECTED ANNUAL AVERAGE RELEASE OF AIRBORNE RADIONUCLIDES FRIMARY SECONDARY CASFOUS FFI,0/SE RATE (Ci/yr) COCLANT GX'LANT GAS STiIPPING BUII, DING VTNTILATION BLOWDOWN AIR EJECTCB ISOTOFE (uC1/g) ( Ci/g) SHUTIOWN CONTINUOUS REACTOR AUXILIARY TLTBINE VENT OTFCAS EXHAUST TOTAL Kr-83m 2.265x10' 6.255x10 0.0a 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 0 0 Kr-85m 1.184x10' 3.337x10' O.0 C.0 0.0 3.0x10 0.0 0.0 2.0x10 5.0x10 2 1 0 Kr-85 1.051x10~ 2.944x10' 5.1x10 I 5.7x10 7,4xlg 2.0x10 0.0 0.0 1.0x10 7.0x10 Kr-87 8.474x10" 1.726x10' O.0 0.0 0.0 1.0x10 0.0 0.0 0.0 1.Ox10 0 0 Kr-88 2.158x10" 5.928x10' O.0 0.0 0.0 5.0x10 0.0 0.0 3.0x10 8.0x10 Kr-89 5.399x10' 1.512x10 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 I 0 0 0 Xe-131m 1.035x10' 2.917x10' 4.0x10 1.5x10 1.7x10 2.0x10 0.0 0.0 1.0x10 3.9x10 0 0 Xe-134m 2.293x10' 6.461x10' O.0 0.0 7.0x10 5.0x10 0.0 0.0 3.0x10 1.5x10 1 -6 I 3 3.8x10 0.0 0.0 2.4x10 2.0x10 [ Xe-133 1.804x10 5.010x10 2.4x10 4.7x10 1.3x10 W Xe-135m 1.404x10' 3.887x10' O.0 0.0 0.0 0.0 0.0 C.0 0.0 0.0 M 0 I Xe-135 3.755x10' l.041x10' O.0 0.0 2.0x10 8.0x10 0.0 0.0 5.0x10 1.5x!O Xe-137 9.719x10~ 2.700x10' O.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 0 W Xe-138 4.751x10- 1.296x10' O0 0.0 0.0 1.0x10 0.0 0.0 0.0 1.0x10 TOTAL NOBLE GASES 2.8x10 1-131 2.795x10 4.215x10" 0.0 0.0 1.7x10' 4.4x10' 2.3x10' O.0 2.8x10' 5.1x10
-1 I-133 3.986x10 3.831x10' O.0 0.0 7.7x10 6.3x10' 2.1x10' O.0 4.0x10 7.0x10'l' TRITIUM GASEOUS RELEASE 1000 C1/yr QM l C3 t* m WZ O
H 3: eM l 00 Z l H >3 aThe figure 0.0 appearing in the table indicates that the release is less than 1.0 Ci/yr for noble gas, 0.0001 Ci/yr for 1. g l O H l O O O
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 O TABLE 3.5-5 (Cont'd) PARAMETER VALUE Equipment drains input (gpd) 2800.0 Fraction of primary coolant activity 0.005 3 Decontamination factors for equipment drains processing: Iodine 1 x 10 5 Cesium 2 x 104 Others 1 x 106 Equipment drains - Collection time (days) 2.30 Processing time (days) 0.15 Fraction discharged 0.10 Clean waste input (gpd) 2800.0 Fraction of primary coolant activity 0.002 3 Decontamination factors for clean waste processing: Iodine 1 x 10 5 (~% Cesium 2 x 104 x_) Others 1 x 106 Clean waste - Collection time (days) 2.30 Processing time (days) 0.15 Fraction discharged 0.10 Dirty wastes input (gpd) 2800.0 Fraction of primary coolant activity 0.0063 l 3 Decontamination factors for dirty waste processing: Iodine 1 x 105 Cesium- 2 x 104 Others 1 x 106 Dirty wastes - Collection time (days) 4.60 Processing time (days) 0.11 Fraction discharged 0.10 Blowdown fraction-processed 1.00 Decontamination factors for blowdown processing: Iodine 1 x 10 2 Cesium 1 x 101 () Others 1 x 102 3.5-27
Byron ER-OLS TABLE 3.5-5 (Cont'd) PARAMETER VALUE Dlowdown - Collection time (days) 0.03 Processing time (days) 0.03 Praction discharged 0.10 Condensate domineralizer regenerant flow (gpd) 0.00 Decontamination factors for regenerant processing: Iodine 1.0 Cesium 1.0 Others 1.0 Regenerant - Collection time (days) 0.00 Processing time (days) 0.00 Fraction discharged 0.00 Stripping continuity of full letdown flow non-con-tinuous Holdup time for :*enon (days) 45.0 Holdup time for krypton (days) 45.0 Fill time for gas decay tanks (days) 43.0 Waste gas system filter non-HEPA filter Auxiliary building vent system filter HEPA This system does not have a charcoal filter. filter Containment volume (106 ft3) 2.9 Containment atmosphere cleanup rate (103 cfm) 16.0 Containment shutdown purge line filter HEPA This system does not have a charcoal .iiter. filter Continuous low volume purge of the containment none Blowdown tank vent none Fraction of iodine released from the main condenser air ejector . 0.10 Reciprocal of the detergent waste prccessing decontamination factor 1.00 1
/ 9 3[5-28 .
w___-- _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ - _ _ _ - - n! .>
Byron ER-OLS d TABLE 3.5-6 GASEOUS RADWASTE SYSTEM COMPOpENT DATA WASTE GAS CO!! PRESSORS 4-LOOP PLANT Type Liquid pir, ton rotary Quantity 2 Design pressure 150 psig Design temperature 180' F Operating temperature 70-130' F Design suction pressure, 0.5 psig Na at 1400 F Design discharge pressure 110 psig Design flow of N2 40 cfm GAS DECAY TANKS Type Vertical Quantity (Shared by the two units) 6 Design pressure 150 psig Design temperature 180' F Volume (each) 600 ft3 (~}/ N_ , Construction material Carbon steel A 3.5-29
Byron ER-OLS AMENDMENT NO. 3 MAPCII 1982 TABLE 3.5-7 ADDITIONAL VENTILATION RELEASES FROM PLANT BY IcOTOPE ISOTOPE RELEASE RATE (Ci/yr) 3 Containment Purge Release (Two Units) I-131 0.015 Kr-85 240.0 Xe-133 980.0 11-3 68.0 Auxiliary Building Ventilation Release (Two Units) I-131 0.032 Steam Jet Air Ejector Release a (One Unit) Kr-85 463.0 Kr-85m 111.0 Kr-87 63.2 Kr-88 195.0 Xe-131m 100.0 Xc-133 14,800.0 Xc-133m 163.2 l Xe-135 332.0 Ye-135m 10.5 Xe-138 36.9 I-131 0.0012 H-3 132.0 aResulting from primary to secondary coolant leakage in one unit for 14 equivalent full power days with 1% failed fuel and leakage rate of 1 gal / min. This condition is not ex-pected actually to occur, bett is used for the purpose of h design basis calculations. 3.5-30
Byron ER-OLS AMENDMENT NO. 3 MARCl! 1982 TABLE 3.5-7 (Cont'd) ISOTOPE RELEASE RATE (Ci/Yr) Volume Reduction System Release (Two Units) Gases:
-1 Xe-131m 5.1 x 10 Xe-133m 1.2 Xe-133 2.1 x 10 t
-3 I-131 2.8 x 10 I-132 3.7 x 10-
-3 I-133 2.1 x 10 II- 3 2.6 x 10 Particulates: 3 Cu-51 5.3 x 10 Fe-55 7.0 x 10-Co-58 6.0 x 10-
-8 Co-60 9.2 x 10 Ni-63 7.0 x 10" Y-91 1.5 x 10-Mo-99 3.5 x 10-
-9 Te-99m 2.1 x 10 Te-132 1.5 x 10-
-5 Cs-134 1.1 x 10 Cs-136 1.9 x 10" Cs-137 7.4 x 10 O
v 3.5-30a
TABLE 3.5-8 ANNUAL WEIGHT, VOLUME, AND ACTIVITY OF RADWASTE SHIPPED FROM BOTH UNITS AT THE STATION CONTAIN E M WEIGHT SHIPPED VOLLHE bt4IPPED ACTIVITg TYPE CF WASTE Ilt /yri (ft3/yr) CATFGOPY* FHIPPIN; CONTAINEP PFh YTAR (Ci/yr) Bead Resins C 241,900 3,100 rc Do- 17C 413 18,750 55-gallon drum Dispcsable Filter 131,800 1,425 SC DOT 17H 190 177 Elements 55-gallon drum Evaporatos Concentr$'.es Wathout VP f rcr. 3t6,300 from 34,350 SC DOT 17C from 4,580 490 g to 3,777,900 to 38,550 55-gallon drum to 5,140 g With VR from 213,150 from 2,205 SP DOT 17C from 294 490 55-gallon drum to 326 O W to 236,350 to 2,445 D w Dry Waste Without VP 173,500 9,700 C DOT 17H 1,160 1m % 55-gallon drum activity I H O With Vt 5,075 55 SP DOT-17C 7 Low ["8 55-gallon drum activaty (/) Fre and HEPA 43,800 7,300 N 100 ft3 boxes 73 Low Filters plus arttwity other Noncompa-tible and/or Noncombustible Waste
- Rey to radwaste ca te,jory:
SC - Solidified with cement before sh4pme.it. SP - Solidified with polymer before shipment. *,p Q L G Liquid waste: none shipped. Caseous wasta? none shipped. Q c y trj MM C - Compacted: re;s, paper, compressible waste. gggg N - Not compacted or solidified. g g b Activity at t.me of drumming except as noted, ZWZ p tf] c [rj c Z CD Z The spent resin activity (bead resins) is calculated at the time the resin is transfered to the spent resin tank. This CD d H d activity will be less if the resin is stored for significant period of time. h3 Z Z d vR - volume seduction. 9 ,O W H H W O O O
1 j AMEflDf4EflT fl0. 3 i MARCH 1982 l STEAM R ADIO ACTIVE GENERATOR LIQUID WASTES BLOWDOWN f COLLECTION f BLOWDOWN SUMPS OR CONDENSER TANKS (2)
- - - - > ' f l
l RADWASTE EVAP. l l l v 7- y , MONITOR l MIXED l TANK BED l DEMIN. SLURRY
! CONCENTRATES !
~~~
TANK l O Y DRUMMING L ""M L + REDUCTION VOLUME SYSTEM l If l f~~~~ l MONITOR RELEASE TANK TANK VACUUM If DEGASIFIER If COOLING TOWER CATCH B A SIN CONDENSATE OR BLOWDOWN LINE STORAGE TANK PRIM ARY W ATER FLOW PATTERN STORAGE. BYRON NUCLEAR GENERAilNC STAil0N UN115 1 &2 NORM AL ENVIRONMENT AL REPORT -OPERATING LICENSE STAGE O - - - - - - ALTERNATE FIGURE 3.5-1 LIQUID RADWASTE FLOW DIAGRAM
Byron ER-OLS
/')
APPENDIX 3.5A - DATA NEEDED FOR RADIOACTIVE SOURCE TERM (_/ CALCULATIONS FOR PRESSURIZED WATER REACTORS 3.5A.1 GENERAL Request:
- 1. The maximum core thermal power (MWt) evaluated for safety considerations in the SAR.
Response
The maximum core thermal power is 3565 MWt. Request:
- 2. Core Properties:
- a. The total mass (Ib) cf uranium and plutonium in an equilibrium core (metal weight).
- b. The percent enrichment of uranium in reload fuel, and
- c. The percent of fissile plutonium in reload fuel.
O
\' Response:
- a. The total mass of uranium and plutonium in an equilibrium core is 196,000 lbs.
- b. The percent enrichment of uranium in reload fuel is 3.11%
by weight if there is no plutonium in the reload fuel.
- c. If there is fissile plutonium in the reload fuel, it comprises 3% by weight.
Request:
- 3. If methods and parameters used in estimating the source terms in the primary coolant are different from those given in Regulatory Guide 1.112, " Calculation of Releases of Radioactive Materials in Gaseous and Liquid Effluents from Light-Water-Cooled Power Reactors," describe in detail the methods and parameters used. Include the following information:
- a. Station capacity factor,
- b. Fraction of fuel releasing radioactivity in the primary r'N coolant (indicate the type of fuel cladding),
( 3.5A-1
Byron ER-OLS AMENDMENT NO. 3 l MARCH 1982
- c. Concentration of fission, activation, and corrosion products in the primary and secondary coolant (pCi/g).
Provide the bases for the values used.
Response
The source-term model used in the calculation of the Byron Nuclear Generating Station - Units 1 & 2 (Byron Station) radioactive source terms is based on, the NRC's NUREG-0017,
" Calculations of Releases of Radioactive Materials in Gaseous and l Liquid Effluents from Pressurized Water Reactors" (PWR-GALE l computer program), published in April 1976.
Request:
- 4. The quantity of tritium released in liquid and gaseous effluents (Ci/yr per reactor).
Response
( The liquid tritium release rate is 300 Ci/yr per reactor. The 3 gaseous tritium release rate is 1100 Ci/yr per reactor. 3.5A.2 PRIMARY SYSTEM f Request:
- 1. The total mass (1b) of coolant in the primary system, h excluding the pressurizer and primary coolant purification system at full power.
Response
The total mass (lb) of coolant in the primary system excluding the pressurizer and primary coolant purification system at full power is 530,000 lb. Request:
- 2. The average primary system letdown rate (gpm) to the primary coolant purification system.
Response
The average primary system letdown rate (gpm) to the primary coolant purification system is 75 gpm. Request:
- 3. The average flow rate (gpm) through the primary coolant purification system cation demineralizers. (Note: The letdown rate should include the frcction of time the cation demineralizers are in service.)
ll 3.5A-2 I
Byron ER-OLS (} Response: The average flow rate (gpm) through the primary coolant purifi-cation system cation demineralizers is 7.5 gpm. (The demineralizers are in service 10% of the time, during which the flow rate through them is 75 gpm.) Request:
- 4. The average shim bleed flow (gpm).
Response
The average shim bleed flow is approximately 1.5 gpm. 3.5A.3 SECONDARY SYSTEM Request:
- 1. The number and type of steam generators and the carryover factor used in the apolicant's evaluation for iodine and nonvolatiles.
Response
There are four U-tube recirculating type steam generators with a carryover fraction as specified in NUREG-0017, April 1976, of O- 0.001 for non-volatiles and 0.01 for iodines. Request:
- 2. The total steam flow (lb/hr) in the secondary system.
Response
The total steam flow in the secondary system is 1.51 x 10 ' lb/hr. Request:
- 3. The mass of steam in each steam generator (1b) at full power.
Response
There are approximately 9000 lb of steam in each steam generator at full power. Request:
- 4. The mass of liquid in each steam generator (1b) at full power.
O 3.5A-3 l l
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982
Response
There are approximately 117,000 lb of liquid in each steam generator at full power. Request:
- 5. The total mass of coolant in the secondary system (Ib) at full power. For recirculating U-tube steam generators, do not include the coolant in the condenser hotwell.
Response
The total mass of coolant in the secondary system is 2.02 x 106 lb at full power. Request:
- 6. The primary to secondary system leakage rate (lb/ day) used in the evaluation.
Response
l The primary to secondary system leakage rate is 100 lb/ day. 3 Request:
- 7. Description of the steam generator blowdown and blowdown purification systems. The average steam generator blowdown rate (lb/hr) used in the applicant's evaluation. The parameters used for steam generator blowdown rate (1b/hr).
Response
l The purpose of the steam generator blowdown subsystem is to pro-f vide the means for controlling the water chemistry in the steam j generators. Normally, the steam generator blowdown is non-i radioactive, and a blowdown rate of 60 gpm (86,400 gal / day per f unit) is sufficient. For purposes of conservatism, however, the l design of the blowdown subsystem is based on a continuous 1 gpm l primary to secondary leak for 14 days. During leak conditions, secondary water becomes radioactive and will reach an isotopic inventory equilibrium inversely proportional to the blowdown rate. The higher the blowdown rate, the lower the radioactive content of the secondary water. With a gross radioactive leak, therefore, blowdown is increased to 135 gpm (194,400 gal / day per unit). Blowdown is cooled through two blowdown condensers, one per unit, that are cross-tied. The cooled blowdown liquid is filtered and then demineralized. 3.5A-4
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 (~N ' \l Each unit has two prefilters so that flow can be processed without interruption when one filter is being replaced. In the case of a 1-gpm radioactive leak, blowdown through the leaking steam generator is increased while blowdown through the non-leaking unit is decreased correspondingly. The average steam generator blowdown rate is 30,000 lb/hr. 3 Request:
- 8. The fraction of the steam generator feedwater processed through the condensate demineralizers and the deco.,tamination factors (DF) used in the evaluation for the condensate demineralizer system.
Response
Byron Station does not have condensate demineralizers. Request:
- 9. Condensate demineralizers:
, s a. Average flow rate (lb/hr),
- b. Demineralizer type (deep bed or powered resin),
- c. Number and size (ft3) of demineralizers, 1
- d. Regeneration frequency, l
- e. Indicate whether ultrasonic resin cleaning is used and J
the waste liquid volume associated with its use, and
- f. Regenerant volume (gal / event) and activity.
Response
Condensate demineralizers are not used at the Byron Station. 3.5A.4 LIQUID WASTE PROCESSING SYSTEM Recaest:
- 1. For each liquid waste processing system (including the shim bleed, steam generator blowdown, and detergent waste processing systems) provide in tabular form the following information:
s a. Sources, flow rates (gpd), and expected activities s (fraction of primary coolant activity, PCA) for all inputs to each system, 3.5A-5
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982
- b. Holdup times associated with collection, processing and discharge of all liquid streams, llh
- c. Capacities of all tanks (gal) and processing equipment (gpd) considered in calculating holdup times,
- d. Decontamination factors for each processing step,
- e. Fraction of each processing stream expected to be discharged over the life of the station,
- f. For demineralizer regeneration provide: time between regenerations, regenerant volumes and activities, treatment of regenerants, and fraction of regenerant discharged (includa parameters used in making these determinations), and
- g. Liquid source term by radionuclide in Ci/yr for normal operation, including anticipated operational occurrences.
Response
A. Shim Bleed Waste Stream
- a. Source: Boron recovery stream taken from letdown purification flow.
3l h Flow rate: average shim bleed flow is 2160 gpd; Radioisotope activities: Calculated in on PWR-GALE (NRC 1976).
- b. Hold-up times and Processing Equipment (all equipment can be shared by both units)
Process and collection time of 73 hours was used for decay purposes,
- c. Capacities
- 1. Boron recycle hold-up tank 125,000 gal eact
- 2. Boron recycle monitor tank 20,000 gal each
- d. Decontamination Factors:
O 3.5A-6
Byron FR-OLS () c. Capacities (all equipment is shared by both units). Turbine Building Equipment 12,000 gal each Drain Tanks (2) Turbine Building Equipment 216,000 gpd Drain Filter (1) Blowdown Demineralizers (4) 259,200 gpd each 4
- d. Decontamination Factors:
Element Filters Demineralizers I 1 1 x 102 Cs, Rb 1 1 x 102 Others 1 1 x 102
- e. Fraction of processed waste stream assumed released to environment after processing - 10%.
- f. Not applicable.
- g. See Table 3.5-3.
s D. Turbine Building Floor Drains Waste Stream g l
- a. Sources:
turbine building floor drain sumps, release tank, essential service water sumps, condensate pit sumps, and tendon tunnel sumps. Flow Rate: 6000 gpd (maximum), 2100 gpd (annual average) per unit. Radioisotope activities: Calculated in PWR-GALE (NRC 1976).
- b. Hold-up Times and Processing Equipment (all equipment is shared by both units).
Turbine Building Floor Drain 1.3 hours (minimum) Tank Turbine Building Floor Drain negligible Filter l n 3.5A-9 1 i
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982
- c. Capacities (all equipment is shared by both units).
Turbine Building Floor Drain 12,000 gal each Tanks (2) Turbine Building Floor Drain 216,000 gpd l Filter (1)
- d. Decontamination Factors:
Element Filters Demineralizers I 1 1 x 102 Cs, Rb i 1 x 102 Others 1 1 x 102
- e. Fraction of processed waste stream assumed released to environment after processing - 10%.
- f. Not applicable.
- g. See Table 3.5-3.
E. Chemical Drains Waste Stream
- a. Sources: fuel handling building decontamination sump, sample system (secondary), sample system (primary),
laboratory drains, drumming station drum processing unit drain, boron recycle system, and primary water storage tank. Flow rates: 3000 gpd (maximum), 1050 gpd (annual average) per unit. Radioisotope activities: 8/1000 PCA 3
- b. Hold-up Times and Processing Equipment l
(all equipment shared by both units) Chemical Drain Tank I hour 1 Chemical Drain Filter negligible Radwaste Evaporators 1.5 hours Radwaste Demineralizers negligible Radwaste Monitor Tanks I hour (minimum)
- c. Capacities (all equipment is shared by both units) lh 3.5A-10
Byron ER-OLS () Chemical Drain Tank (1) 6,000 gal 216,000 gpd Chemical Drain Filter (1) Radwaste Evaporators (3) 43,200 gpd each Radwaste Demineralizers (3) 64,800 gpd each Radwaste Monitor Tanks (2) 20,000 gal each (Radwaste Evaporators, Demineralizers, and Monitor Tanks are also used to process other waste streams.)
- d. Decontamination Factors:
Demineralizers Evaporators Element Filters 1 1 x 102 1 x 103 I Cs 1 1 x 102 1 x 1.0* 1 x 101 1 x 10' Rb 1 1 x 102 1 x 10' Others 1
- e. Fraction of process waste stream assumed released to environment after processing - 10%.
- f. Not applicable.
- g. See Table 3.5-3. :
F. Laundry Wastes Waste Stream
- a. Sources: laundry washing machine drains and personal shower drains. I Flow rate: 2000 gpd (maximum), 700 gpd (annual average) per unit.
Radioisotope activities: Calculated in PWR-GALE (NRC 1976).
- b. Hold-up Times and Processing Equipment (all equipment shared by both units).
Laundry Drain Tank 1.1 hours (minimum) Laundry Drain Filter negligible Permeate Storage Tank 1.3 hours (minimum) h 1.5 hours Radwaste Evaporator Radwaste Demineralizers negligible 3
Radwaste Monitor Tanks I hour (minimum) l 3.5A-ll
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982
- c. Capacities (all equipment is shared by both units) llh Laundry Drain Tank (1) 4,000 gal Laundry Drain Storage Tanks (2) 2,000 gal. each Laundry Drain Filter (1) 216,000 gpd Radwaste Evaporators (3) 43,200 gpd each Radwaste Demineralizers (3) 64,800 gpd each Radwaste Monitor Tanks (2) 20,000 gal each (Radwaste Evaporators, Demineralizers, and Monitor Tanks are also used to process other waste streams.)
- d. Not applicable,
- e. Fraction of process waste stream assumed discharged to the environment after processing - 100%.
- f. Not applicable,
- g. See Table 3.5-3.
G. Auxiliary Building Equipment Drains Waste Stream
- a. Sources: low conductivity regeneration waste drains, reactor coolant drains, and auxiliary building equipment drain collection sumps.
Flow rate: 8000 gpd (maximum), 2800 gpd (annual average) per unit. Radioisotope Activities: 5/1000 PCA f3
- b. Hold-up Times and Processing Equipment (all equipment is shared by both units).
Auxiliary Building Equipment 2.2 hours (minimum) Drain Tank Auxiliary Building Equipment negligible Drain Filter Radwaste Evaporators 1.5 hours Radwaste Demineralizers negligible Radwaste Monitor Tanks I hour (minimum)
- c. Capacities (all equipment is shared by both units). llh 3.5A-12
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 O Auxiliary Building Equipment 8,000 gal each Drain Tanks (2) Auxiliary Building Equipment 216,000 gpd Drain Filter (1) Radwaste Evaporators (3) 43,200 gpd each Radwaste Demineralizers (3) 64,800 gpd each F Radwaste Monitor Tanks (2) 20,000 gal each (Radwaste Evaporators, Demineralizers, and Monitor Tanks are also used to process other waste streams.)
- d. Decontamination Factors:
Element Filters Demineralizers Evaporators I 1 1 x 102 1 x 103 Cs 1 1 x 102 1 x 10* Rb 1 1 x 101 1 x 10* Others 1 1 x 102 1 x 10*
- e. Fraction of process waste stream assumed discharged to the environment after processing - 10%.
- f. Not applicable.
- g. See Table 3.5-3.
H. Auxiliary Buildino Floor Drains Waste Stream
- a. Sources: auxiliary building sumpe, fuel handling building sumps, reactor cavity sumps, and containment floor drain sumps.
Flow rate: 8000 gpd (maximum), 2800 gpd (annual average) Radioisotope activities: 2/1000 PCA 3
- b. Hold-up Times and Processing Equipment (all equipment can be shared by both units).
Auxiliary Building Floor 2.2 hours (minimum) Drain Tank Auxiliary Building Floor negligible Drain Filter 3.5A-13 ! l
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 Radwaste Evaporators 1.5 hours lh Radwaste Demineralizers negligible Radwaste Monitor Tanks 1 hour (minimum)
- c. Capacities (all equipment is shared by both units).
Auxiliary Building Floor 8,000 gal each Drain Tanks (2) Auxiliary Building Floor 216,000 gpd Drain Filter (1) Radwaste Evaporators (3) 43,200 gpd each Radwaste Demineralizers (3) 64,800 gpd each Radwaste Monitor Tanks (2) 20,000 gal each
- d. Decontamination Factors:
Element Filters Demineralizers Evaporators I i 1 x 102 1 x 103 Cs 1 1 x 101 1 x 104 Rb 1 1 x 101 1 x 10' Others 1 1 x 102 1 x 10'
- e. Fraction of process waste stream assumed discharged to environment after processing - 10%.
- f. Not applicable.
( g. See Table 3.5-3. I. Regeneration Wastes Waste Stream
- a. Sources: drumming station decanting tank overflow, spent I
resin sluicing drain, recycle evaporator condensate demineralizer, radwaste mixed bed demineralizer, and blowdown mixed bed demineralizer. Flow rate: 5000 gpd (maximum); 1750 gpd (annual average) per unit. Radioisotope activities: 6/1000 PCA 3 0 3.5A-14
4 I Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 1 ! b. Hold-up Times and Processing Equipment (all equipment shared by both units). 1.7 hours (minimum) I Regeneration Waste Drain Tank Regeneration Waste Drain Filter negligible Radwaste Evaporators 1.5 hours i Radwaste Demineralizers negligible i i Radwaste Monitor Tank I hour (minimum) i 1 i i ! 1 i ( N i 4 i I i i ! P i I i ; 4 :
.i i l r
i i i
+
i I L 3.5A-14a l t
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 O reduce airborne concentration of this isotope to approximately The containment internal recirculation system 1 x 10-20 Ci/cm3 will operate approximately 18 hours before purging. The containment is purged at a rate of 40,000 cfm before the admission of workers for refueling, maintenance, or repair of equipment. The design purge frequency is 10 purges / year per unit. The expected purge frequency is approximately 6 purges / year per unit. The containment is purged continuously, however, at a rate of 3000 cfm. 3.5A.7 SOLID WASTE PROCESSING SYSTEMS Request:
- 1. In tabular form, provide the following information concerning all inputs to the solid waste processing system: source, volume (ft3/yr per reactor), and activity (Ci/yr per reactor)
. of principal radionuclides, along with bases for valves used.
Response
Information concerning inputs to the solid waste processing system are given in Table 3.5-8. Request:
- 2. Provide information on onsite storage provisions (location and capacity) and expected onsite storage times for all solid wastes prior to shipment.
Response
Solid wastes will be stored in the Radwaste Building before shipment (see B/B FSAR Figure 11.4-3). Storage space is designed to accommodate approximately 25% of the normal yearly output of packaged waste. This amount was selected to allow for some decay of drummed material, startups, trucking strikes, unavailability of burial sites, and other contingencies. Information on the solid waste storage area is given in the following list. For other information refer to Section 11.4 of the B/B FSAR. Number of Design Capacity Storage Area Storage Areas Per Storage Area Low Level 1 570 drums Intermediate level 1 640 drums 70 drums 3 Dry compacted waste 1 () Dry uncompacted waste Empty drum 1 2 90 ft3 100 drums (total) 3 l 3.5A-19 l l
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 Request:
- 3. Provide piping and instrumentation diagrams (P& ids) for the solid radwaste system.
Response
The P&ID drawings of the solid radwaste system are shown on 3 B/B FSAR Figures 11.4-5 and 11.4-6. l O O 3.5A-20
b Byron ER-OLS AMENDMENT NO. 3 HARCH 1982 , /m 3.6 CHEMICAL AND BIOCIDE SYSTEMS ! The primary source of cooling tower makeup water for the Byron ! Nuclear Generating Station - Units 1 & 2 (Byron Station) is the Rock River. Table 3.6-1 The shows the expected seasonal composition river water is used as makeup to the of the river water. cooling towers to replace the water lost from the towers through evaporation, drift, and blowdown. The rest of the water required, as indicated in Subsection 3.3.3, Groundwater is pumped from deep wells drilled Afteron the plant suitable site. this treatment, is discussed in Section 2.5. water is the source of both potable and sanitary water, of makeup water for the steam supply system, and of water for other miscellaneous uses. Figure 3.3-1 is a flow chart of water use. 3.6.1 Coolino Water Systems 3.6.1.1 Circulatino Water System As discussed in Subsection 3.3.1, each steam turbine unit has a closed-cycle recirculating cooling water system to remove the heat released during condensation of the turbine exhaust steam. This system is. connected to the nonessential service water system I'h as discussed in Subsection 3.3.2.1. V Sulfuric acid is added to this system to control the pH and to prevent scaling in the condenser. The acid neutralizes the alkalinity present in the makeup to the cooling tower to a pH of between 7.0 and 7.5. This neutralization will require an average feed rate of about 3.9 gal / min of sulfuric acid (H,SO 4) based on the average makeup flow rate. Aminomethylene phosphonate (AMP) or 1-Hydroxyethylidene-1, 1-Diphosphonic acid (HEDP) will also be 3 The use of AMP or HEDP should reduce the used for scale control. used (based on industry experience) bechase it quantity of H,SO 4 allows the system to operate at a higher pH. Sulfuric acid will be added in a quantity sufficient to maintain a 1.5 ppm concentration. Polyacrylate, a low It molecular-weight polymer, will be added in a quantity will be used as a dispersant. sufficient to maintain a 2.0 ppm concentration. Biological growth and slime buildup in the main condensers are controlled through the use of mechanical cleaning, which greatly reduces the quantity of hypochlorite needed in the plant. The Amertap system at the Byron Station uses two types of small, - sponge-rubber balls sized to the inside diameter of the condenser tubes, a plain, sponge-rubber ball and During a similar operation, ball balls these with an are abrasive band bonded to it. injected into the circulating water piping at the inlet to the e condenser. The balls, with a submerged density nearly equal to ( 'y) the density of water, are dispersed in the circulating water
' stream and forced through the condenser tubes by the pressure of the flowing water. As the balls pass through the tubes, they 3.6-1
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCH 1982 wipe them clean. A system of baffles and screens in the circulating piping at the outlet of the condenser collects the balls as they flow out of the condenser. The balls are removed from the circulating water stream and reinjected at the condenser inlet or stored for later use. It is also necessary to add small amounts of chlorine derivatives to the circulating water system to control algal growth. Hypoc.2orite is injected intermittently into the circulating-water line before the main condensers but after the blowdown take-off point. The chlorine dosage is controlled to satisfy the chlorine demand of the cooling water and provide a free residual chlorine concentration of 0.1 ppm. The circulating water system, service water system, and essential service water system will be 1 operated so that total chlorine in the blowdown will be within federal and state of Illinois effluent standards. There is a natural buildup of dissolved solids in the system that must be limited by blowing down a small percentage of the circulating water. This buildup occurs because the water evaporated from the cooling towers is relatively pure. Dissolved solids in the evaporated water are left behind in the system. Some of the water in the system is then replaced with makeup river water with a lower dissolved solids content. This prevents the total dissolved solids (TDS) concentration from reaching unacceptable levels. The dissolved solids content of the water in this system is maintained at a level that will allow conformance to the l3 applicable State of Illinois effluent requirements. Table 3.6-2 shows an estimated analysis of the blowdown based on the use of an average blowdown of 30.1 cubic feet per second (cfs), which yields an average TDS of 1555 mg/ liter. The blowdown contains l3 the same constituents as the river, but in higher concentrations due to evaporation. The chemical analysis of the blowdown depends on seasonal variations in the concentration of dissolved solids in the Rock River water. The drift from the cooling towers contains the same dissolved solids concentration as the blowdown. An estimate of the solids concentration entrained in the drift was made based on a total dissolved solids concentration of 1555 mg/ liter. The results of l3 this calculation can be found in Table 3.6-3. In addition, the salt deposition rates for different distances from the natural draft cooling towers at Byron Station were estimated. A description of the calculations and assumptions used and a sample calculation are given in Subsection 5.1.4. O 1 1 3.6-2 L
i Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 O 3.6.1.2 Service Water System f As discussed in Subsection 3.3.2, there are essential and nonessential service water systems at the Byron Station. Both of the systems are hypochlorinated to prevent biological growths in the cooling equipment. The technique of chlorination used is
" shock" chlorination. With this method, sodium hypochlorite (NaOCl) is added for approximately half-hour periods about three times a day. It is assumed that about 5 ppm of chlorine is added and the residual chlorine at the outlet of the service water is controlled at 0.1 ppm.
a 1 O O 'T I 3.6-2a l - - - - - - _ .-__ __ _ _. ___ _ _ _ , _ _, _
O O O l TABLE 3.6-1 SEASONAL ANALYSES OF ROCK RIVER WATER , (All Values Except pH in mg/ liter) WINTER SPRING SUMMER FALL AVERAGE MAXIMUM" Calcium (as CACO3) 184 165 174 157 170 233 Magnesium (as CACO 3 0 Sodium 22 13 18 21 19 30 to Alkalinity (as CACO 3) 286 136 236 261 245 308 )o
- s ta Sulfate 49 43 30 42 41 63 g i
- n
" Chloride 36 26 26 29 29 43 $
t< Nitrate 3 2 2 2 2 4 Total Dissolved Solids 484 391 362 422 415 658 Silica 5.4 2.0 3.4 1.9 3.2 6.2 3: %. pH average 7.4 >g range 6.4-8.7 $z E v tn 1 $$ Source: 1975-1980 onsite water quality data based on seasonal grab samples from Espey 2 Huston ,o
'd "This is the maximum recorded value of each substance, all maximums did not occur simultaneously.
Byron ER-OLS AMENDMENT NO. 3 tiARCH 1982 TABLE 3.6-2 AVERAGE BLOWDOWN WATER ANALYSIS O (All Values in mg/ liter) Calcium (as CACO3) 434 Magnesium (as CACO 3) 0 Sodium 48 Sulfate 602 3 Chloride 74 Alkalinity (as CACO 3) 143 Nitrate 5 Total Dissolved Solids 1555 0 O 3.6-8
- _ _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ___ _ _ _ __ _ _ _ _ _ _ _ _ _ _ _ __ _ l
1 Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 i () TABLE 3.6-3 ESTIMATED AVERAGE QUANTITIES DISCHARGED TO THE : ! ATMOSPHERE FROM DRIFT OF TWO NATURAL-DRAFT COOLING TOWERS AT i j THE BYRON STATION (All Values in lb/ day) I Calcium 56 Magnesium 29 Sodium 16 Sulfate 194 3 Chloride 24 Nitrate 2 l Total Dissolved Solids 502 { i ? f J i l 1 I Note: The " drift" is the spray off the cooling towers-that will contain the dissolved solids of the ) s) circulating water. 3.6-9
l l Byron EI-OLS AMENDMENT NO. 3 MARCH 1982 TABLE 3.6-4 h ESTIMATED MAXI!!UM EFFLUENT ANALYSIS (All Values in mg/ liter as Substance) DISCHARGE BLONDOWN" TO RIVERD Calcium 188 188 Magnesium 97 97 Sodium 56 56 Sulfate 745' 745 3 Chloride 92 92 Alkalinity (as CACO 3) 114 114 Nitrate 8 8 Total Dissolved Solids 1854 1854 Silica le 14 a liighest of the four seasonal average river analyses was used (see Table 3.6-1). b In this analysis, the radwaste, sanitary waste, and waste treatment building waste discharges to the blowdown were considered negligible. O 3.6-10
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i MARCII 1982
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Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCH 1982 i O CHAPTER 4.0 - ENVIRONMENTAL EFFECTS OF SITE PREPARATION, STATION CONSTRUCTION, AND TRANSMISSION FACILITIES CONSfRUCTION TABLE OF CONTENTS PAGE 4.1 SITE PREPARATION AND STATION CONSTRUCTION 4.1-1 4.1.1 Construction Schedule 4.1-1 4.1.2 Land Use 4.1-1 4.1.3 Water Use 4.1-4 4.1.4 Montitoring Program 4.1-5 4.1.4.1 Terrestrial Studies 4.1-5 4.1.4.1.1 Summary of 1974 Sampling Results 4.1-5 4.1.4.1.2 Summary of 1975-1976 Sampling Results 4.1-7 4.1.4.1.3 Summary of 1976-1977 Sampling Results 4.1-8 c.l.4.1.4 Summary of 1977-1981 Bird Impaction 3 Surveys 4.1-9 4.1.4.2 Aquatic Studies 4.1-9 4.1.4.2.1 Summary of 1974 Sampling Results 4.1-9 4.1.4.2.2 Summary of 1975-1976 Sampling Results 4.1-12 4.1.4.2.3 Summary of 1976-1977 Sampling Results 4.1-15 1 r 4.1.4.3 Special Surface Water and Groundwater Studies 4.1-18 4.2 TRANSMISSION FACILITIES CONSTRUCTION 4.2-1 4.2.1 Access Roads 4.2-1 4.2.2 Clearing Methods 4.2-1 4.2.3 Installation Procedures 4.2-1 4.2.4 Consideration of Erosion Problems 4.?-1 4.2.5 Effects on Agricultural Productivity 4.2-2 4.2.6 Plans for Wildlife Protection 4.2-2 4.2.7 Plans for Dicposal of Debris 4.2-2 4.2.8 Restoration Plans 4.2-2 4.2.9 Environmental Impact 4.2-3 4.3 RESOURCES COMMITTED 4.3-1 4.3.1 Land Resources 4.3-1 4.3.2 Water Resources 4.3-1 4.3.3 Materials Used 4.3-1 4.4 RADIOACTIVITY 4.4-1
- 4.5- CONSTRUCTION IMPACT CONTROL PROGRAM 4.5-1
~
4.5.1 Background 4.5-1 ((m)T 4.5.2 Responsibilities 4.5-1 4.0-1 1
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 TABLE OF CONTENTS (Cont'd) h PAGE 4.5.3 Control Measures 4.5-2 4.5.3.1 Eresion 4.5-2 4.5.3.2 Dust 4.5-2 4.5.3.3 Noise 4.5-2 4.5.3.4 Transportation Access 4.5-2 4.5.3.5 Dredge Materials 4.5-3 4.5.3.6 Aquatic and Terrestrial Ecology 4.5-3 4.5.3.7 Oils and Chemical Wastes 4.5-3 4.5A CONSTRUCTION IMPACT CONTROL LETTER 4.5A-i O O 4.0-ii
L i 2 Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 , MARCH 1982 ()s u-l CHAPTER 4.0 - ENVIRONMENTAL EFFECTS OF SITE PREPARATION, PLANT j CONSTRUCTION, AND TRANSMISSION FACILITIES CONSTRUCTION f , 4.1 SITE PREPARATION AND STATION CONSTRUCTION 4.1.1 Construction Schedule A Nuclear Regulatory Commission (NRC) construction permit for the Byron Nuclear Generating Station - Units 1 & 2 (Byron Station) was issued on December 31, 1975. Completion dates for Units 1 and 2 have been set for February 1984 and February 1985, 1 (3 respectively. The specific conditions for environmental protection attached to the construction permits are listed in , Section 4.5. The effects of site preparation and construction activities on land and water use are described in the following subsections.
- 4.1.2 Land Use Site preparations for the Byron Station affect 399 acres for actual plant building activities (Espey, Huston 5 Associates
[EH&A] 1976a, 1977a). The land involved is flat (0.5% slope) and at an elevation of about B70 feet above mean sea level (MSL). i The 399 acres are composed mostly of cultivated land. During the life of the station, the use of this land will be changed from its current use. After construction is completed, about 150 acres of land will be occupied by permanent physical structures, 1 ! and the remaining area will be landscaped or planted as needed. Wildlife populations within the affected area will be displaced. l Since most of the land in the affected area is agricultural, t however, no disturbance of major animal populations is expected to occur. The results of the Byron Station Construction P.iase Terrestrial Monitoring Program through the end of 1977 have confirmed that there has been no disturbance (see Subsection
- 4.1.4.1). Most animals and birds reside in areas other thsn
- cornfields, using the cornfields only to feed. There will still
.I ;. an abundance of cornfields in the vicinity for such purposes.
'The immediate plant site and the. corridor are part of the larger
, site area of approximately 1782 acres. All land, excluding the l3 fenced in ates surrounding the major plant structures of approximately 150 acres, will be used to its highest potential 1 for cropland, pasture land, wood land, or natural areas. Because of the highway system adjoining the site, only short access roads directly into the site were required. A railroad ! spur approximately 3.5 miles long was built from the Chicago & 7 Northwestern Railroad line northeast of'the site. All : i \_- l. 4.1 -l ' ,
., - , n m v -, e ,m , ,- ---,,,e--, ,- , - -
Byron ER-OLS construction spoil was removed, and all the land except for the 30-foot right-of-way has been allowed to return to a natural state (i.e., old field type of ecosystem). lll The initial site preparation work has two stages. The first stage consists of stripping, excavating, andThe backfilling the second stage areas occupied by structures and roadways. consists of developing the site with all necessary facilities to support construction such as offices, railroad tracks, warehouses, wells, sanitary facilities, and power lines. The actual station construction began while these activities were in progress. To accommodate the construction force, an onsite parking area was constructed, and a sewage treatment facility was provided. After construction is completed, this parking area will be graded and seeded. The designated construction areas, access ways, and laydown areas were cleared to permit the construction of the permanent station structures and facilities. In order to minimize erosion, a construction drainage system was incorporated into the site development plan. Temporary gravel roads and permanent roads were installed with site grading and drainage facilities to permit all-weather use of the site for movement and storage of materials and equipment during construction. Areas only temporarily disturbed by construction were stabilized by native vegetation. In all instances, erosion control measures around the cristruction area were planned and scheduled as part cf construction operation. To the extent possible, mechanical disturbances during the construction of any of the associated facilities were limited to the immediate construction site. In construction laydown areas, temporary diversions were constructed to intercept and divert runoff. Existing steep slopes subject to erosion were graded and seeded to retard runoff. Dust control measures, such as using watered or bituminously coated roads, were continuously employed during the construction period (see Subsection 4.5.3.2). The blowdown and intake water system connects the plant with the Rock River to the west. It is an enclosed pipe systemItthat traverses agricultural land for most of its length. passes through woodland, however, at its western end. The area disturbed during construction of the pipeline corridor includes about 61 acres of land composed of the following major vegetational types: O 4.1-2
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 () endangered faunal species were observed on the site or are expected to reside there. Comparisons of the survey results for Years 1 and 2 show no detectable faunal changes except for the preemption of some additional habitat because of station site expansion, and the planting of several acres of former cropland and pasture in wildlife-food species. Comparisons of seasonal bird faunas showed high similarities between the data for Years 1 and 2, especially with regard to the more dominant species. Common mammalian species detected onsite were generally the same during the 2 years. For both mammals and birds, some yearly variation appeared in the relative abundances of common species. This variation, however, was the result of sampling methodology and normal variation. None of the variations observed can be reasonably attributed to station construction activities. No adverse impacts of construction activities on the fauna of the site were detectable. 4.1.4.1.4 Summary of 1977-1981 Bird Impaction Surveys The avifaunal survey to document any migratory bird fatalities that may result from direct collision with the meteorological tower, cooling towers, or containment and turbine buildings began r3 in August 1977. During the 1977 to 1979 survey periods, no dead (,/ or injured birds were observed. During the 1980 survey, nine dead birds were documented during the fall migratory season (October). There were five golden-crowned kinglets, one long- 3 billed marsh wren, one white-throated sparrow, one tennessee warbler, and one warbler that could not be more completely identified due to its condition. All of these birds were collected from around the bases of the natural draft cooling tower structores. During the 1981 survey period, no impaction mortalities were reported. The results as briefly describ?d here were reported to the U. S. Fish and Wildlife Service and the Illinois Department of Conservation. 4.1.4.2 Aquatic Studies Aquatic monitoring sampling locations are shown in Figure 4.1-5. 4.1.4.2.1 Summary of 1974 Samplina Results These data are derived from the " Sixth Quarterly Report" of EAI. Water Chemistry: Changes observed in the chemistry of the Rock River and its tributary streams from September 1973 throuf October 1974 resulted mainly from seasonal changes in temperature, precipitation, and river discharge rates. The section of the ()
-- Rock River adjacent to the Byror. Station and the tributary 4.1-9
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 streams draining this area appeared to be in a state of moderate eutrophication. Concentrations of all chemical parameters were within Illinois standards with the exception of phosphorus and, in one instance, copper. Nitrate and phosphate were consistently above levels reported capable of producing nuisance algal blooms. The chemistries of the river and tributary streams were similar on most dates sampled at all nine stream stations except W-3 and W-1. The intermittent nature of the streams appeared to be the major factor affecting the observed differences. Bacteria: Total bacteria, fecal coliform, and fecal streptococcus counts for the five Rock River stations fluctuated seasonally with the highest counts occurring in April during peak runoff and the lowest counts occurring in October 1974. Similar fluctuations in total coliform counts were observed, but the highest counts occurred in January rather than April. Stream stations had a more varied response to seasonal changes than the river stations. b I f I O(_; l 1 f 4.1-9a
Byron ER-OLS Seasonal fluctuations in fecal streptococcus numbers corresponded closely with total bacteria and fecal coliform bacteria counts at the river stations and fecal coliform counts at the stream stations. Fecal coliform to fecal streptococcus ratios (FC:FS) varied appreciably on a seasonal basis. Ratios for the five Rock River stations were indicative of contributions from domestic wastes. Ratios greater than 4.0, which occurred in September and October 1973, were indicative of recent pollution by domestic wastes. Ratios between 0.6 and 4.0, which occurred during the remaining sampling dates, were also indicative of domestic wastes. Phytoplankton: Phytoplankton was sampled at two river stations from September 8, 1973, through October 8, 1974. A total of 118 taxa were identified during the study. Taxa included 59 diatoms, 43 green algae, 9 blue-greens, 4 euglenoids, 2 pyrrophytes, and I cryptophyte. Numerically, diatoms dominated the community throughout the study, ranging from 76.38% on October 8, 1974 to 100% on January 28, 1974. Dominant forms occurring during the course of the study included Cyclotella meneghiniana, Melosira ambiaua, M. oranulata, M. granulata var. angustissima, Stephanodiscus hantzschii, S. minutus, S. subtilus, and Nitzschia palea. These forhis are commonly found in eutrophic waters. Zooplankton: Zooplankton samples were collected on six occasions from September 1973 through October 1974. Samples were taken September 11 and October 16, 1973, from river stations R-1 through R-5 and from tributary stream stations S-4, S-5, and S-6. Samples collected during the remaining periods (January 28, April 30, July 30, and October 8, 1974) were taken from R-2 and R-5 only. Total zooplankton numbers throughout the study (at river stations) ranged from a low of 2 organisms per liter from station R-2 on January 28, 1974, to a high of nearly 350 per liter from station R-2 on April 30, 1974. Taxonomic composition of zooplankton collected during the study included 3 copepod and 7 cladocerau species, 14 genera of protozoans, and 18 rotifer genera. Rotifers were the numerically dominant taxa in Rock River samples on five of six occasions and in one of two periods of stream sampling. Most commonly occurring forms included juvenile copepod stages (nauplii and copepodites), cladoceraus Bosmina and Chydorus, and rotifer genera Brachionus, Keratella, and Synchaeta. O 4.1-10
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3
-w MARCH 1982 v
4.3 RESOURCES COMMITTED The construction of the Byron Nuclear Generating Station - Units 1 & 2 (Byron Station) involves permanent and temporary uses of land, water, and material resources. This section describes the resources committed during plant construction. 4.3.1 Land Resources In the development of the 1782-acre site, 4 acres of woodland and l3 399 acres of agricultural land on the Byron Station site were disturbed because of plant building activities. Approximately y 150 acres of land encompassing the major plant structures were fenced. The remaining site area will be used to its highest potential for cropland, pastureland, woodland, or natural areas. The construction of permanent facilities on the site has eliminated some wildlife habitat, resulting in shifts of wildlife popoulations to other areas. l1 The land that will be traversed by the transmission lines for Byron Station is mainly farmland. Except for the area occupied by the tower foundations, there will be no commitment of farmland (~S resources during the period of transmission line use. Any (-) farmland disturbed by construction activities will be restored. 4.3.2 Water Resources No permanent effects on water resources is expected at the Byron Station site. The construction of the river intake and discharge structures will permanently alter approximately 250-feet of shoreline on the east bank of the 'ock River. No other permanent aquatic disruptions are expected during the construction of the station. 4.3.3 Materials Used The materials used for the Byron Station are of two types: those used for the construction of buildings; and fuel. Construction materials include structural and reinforcing steel, portland cement, electrical cables, paints, coverings, and fixtures. Although these will be permanently committed during the lifetime of the plant, some of them can be at least partially reclaimed if the plant is eventually dismantled. The highly contaminated items will not be reusable. The discussion of fuel consumption and of other resources committed during plant operation is included in Section 5.7. The decommissioning and dismantling of the plant is described in Section 5.8. (~ v) i 4.3-1 I
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 occurrence as shown in Figures 5.1-2 through 5.1-5 can be taken ( ~)' as highly conservative estimates of hours of shadowing. It must be considered that visible plumes will also occur at night and in cloudy weather when no shadowing will exist. During the summer growing season, sunlight may be reduced from about 5 to about 25 hours per season for offiste areas within 3 miles of the Byron Station site. Visible plumes aloft will not interfere with operations at area airports. Expected annual frequencies are 36 hours per year at Greater Rockford Airport 14 milst northeast of the Byron Station I and 17 hours per year at the Davis and Stukenberg private airports 5 and 7 miles west-northwest of the site. These hours include times of natural clouds. Plumes will be at altitudes of at least 300 meters (1000 feet) above the ground and narrow in horizontal extent. 5.1.4.1.2 Mechanical Draft Coolina Towers As indicated in Table 5.1-7, under normal operating conditions the mechanical draft cooling towers will dissipate a very small quantity of heat in comparison to the natural draft cooling towers (0.24 x 10' Btu /hr versus 15.8 x 10' Btu /hr, or less than 2% of the heat). The visible plumes and atmospheric impacts due to the operation of the mechanical draft towers will therefore be small compared with those of the natural draft towers. Because (~%s ( ,/ of their small size, the impacts from the mechanical draft towers have been assessed based on analyses performed previously f + mechanical draft towers and experience with mechanical draft towers in similar climates. Visible plumes are expected to range from near-zero length and height in summer to about 500 meters in length and 200 meters in height during extremely cold weather. It is estimated that visible plumes will exceed 100 meters in length 10% to 15% of the time. 5.1.4.2 Impacts of Drift 5.1.4.2.1 Natural Draft Coolina Towers A small fraction of the circulating water from the Byron cooling system will be discharged directly to the atmosphere as drift droplets. The drift rate for Byron natural draft cooling towers is 0.002% of the circulating water flow, or approximately 13 gal / min per tower at full load. By discharging drift the cooling towers will also release into the atmosphere dissolved solids contained in the drift droplets. The estimated average 3 concentration of dissolved solids in drift water is 1555 mg/ liter. The dissolved solids are primarily calcium and magnesium sulfates, plus a smaller amount of sodium chloride, silica, and phosphate. The maximum emission rate of drift solids, for 0.002% total drift with dissolved solids at a maximum of 18.54 mg/ liter, will be approximately 580 lb/ day, which is 3 \-- less than the 3650 lb/ day estimated in the Byron Station Final 5.1-13
i t Byron ER-OLS AMENDMENT NO. 3 l I MARCH 1982 i l Environment Statement - Construction Permit stage. The 3 l distribution of drift droplet sizes is an important determinant l l for the location and magnitude of drift 1 l I i i l I ( i l i l l i ! i i l 5-1.13a l
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 disposition. The distribution assumed for the following analysis h is given in Table 5.1-10. 5.1.4.2.1.1 Solids Deposition The predicted geographical distribution of the annual solids deposition rate for the two natural draft towers operating at 65% station capacity factor is shown in Figure 5.1-6. The figure shows the annual average deposition rate in pounds per acre-month as a function of direction and distance from the cooling towers. The maximum average deposition rate is 3.3 lb/ acre-month, which l3 is predicted to occur 700 meters (0.43 mile) east of the towers. The deposition rate decreases in all directions away from this point, which represents the fallout location of the largest drift droplets under meteorological conditions of stable stratification and light wind. The heaviest deposition is predicted to the north and east of the towers because of the prevailing wind directions. In general, the deposition rate will be 0.75 to 3.75 lb/ acre-month within 1 3 mile of the towers and will decrease to about 0.15 lb/ acre-month 3 miles away. The data in Figure 5.1-6 are annual averages, based on an assumed load factor of 65% and annual distribution of meteorological parameters. Short-term deposition rates will be higher when the wind is blowing toward a particular receptor and the plant is operating at capacity. The maximum local rate could be about 4.5 l3 lb/ acre-day within 0.5 mile of the towers. This rate of deposition will only persist for the time (usually several hours or less) that the wind remains in one direction and stable stratification, high humidity, and low wind speeds persist. Predicted drift deposition is expected to have very little impact on lands, waters, and vegetation surrounding the Byron Station. Typical background dissolved solids depositionRainfall by rainfall ranges analyses from 2 to 15 lb/ acre-mo in continental areas. from the Chicago area indicate background deposition rates of 5 to 15 lb/ acre-mo; data from central New York State yield rates of 4 to 8 lb/ acre-mo (Likens 1972). Roffman et al. (1973) in a summary of data on salt deposition near seacoasts show deposition rates ranging from 2 to over 180 lb/ acre-mo. A study of salt damage to corn and soybeans (Mulchi and Armbruster 1975) indicated the first evidence of any damage with salt applications of 7 lb/ acre-mo above background for 8 weeks. Thus, the maximum expected deposition from Byron Station's natural draft cooling towers is below typical background and well below rates believed to produce any adverse effects. O 5.1-14
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 TABLE 5.1-6 O NATURAL DRAFT COOLING TOWER DESIGN SPECIFICATIONS AND OPERATING PARAMETERS PARAMETER VALUE d Tower Dimensions Basin diameter 605 ft Shell top diameter 272 ft Height 495 ft Heat Load Design 7.9 x 109 Btu /hr Station Capacity Factor Annual average 60% to 65% Seasonal average Spring 50% to 55% Summer 70% to 75% Fall 50% to 55% Winter 70% to 75% , Design Temperatures Wet bulb 76.0' F () Approach Range 16.0* F. 24.0 F Circulating Water Design flow 662,000 gpm Evaporation . [ Maximum rate (approx.) 14,000 gpm Drift Rate 0.002% of the circu-lating water flow Maximum total dissolved solids content 1,854 ppm l3 4 gs ( 8 All values ar for each of the two towers. 5.1-25
Byron ER-OLS TABLE 5.1-7 MECHANICAL DRAFT COOLING TOWER DESIGN SPECIFICATIONS AND OPERATING PARAMTERS PARAMETER VALUE" Tower Dimensions Length 174 ft Width 45 ft Height 50 ft Tower Configuration Number of cells 4 cells Cell stack diameter 33 ft Heat Load Design 1.04 x 109 Btu /hr Normal operationb 0.24 x 109 Btu /hr Design Temperatures Wet bulb 78.0 F Approach 20.0 F Range Design 40.0 F Normal operation b 10.0 F Circulating Water Flow Design 52,000 gpm Normal operationb 48,000 gpm Evaporation Design maximum (approx.) 2,000 gpm Normal operation (approx. ) 500 hpm Drift s Guaranteed Rate 0.01% of the circu-lating water flow Estimated Actual Rate 0.005% of the circu-l lating water flow 1 1 8 All values are for each of the two towers. b Under normal operating conditions, the towers will be individually operated on a regular alternating basis to cool the essential service water 10 F. During winter the 24,000 gym of water per unit, or a total of 48,000 gpmc will be cooled by both towers operating simultaneously to prevent the towers and the tower basin from freezing. 5.1-26
/ l AMENDMENT NO.1
\ JULY 1981 BYRON o ,
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! ANNUAL AVERAGE
- isorttin snowiss auqual nyttatt Str0$lil0N DRIFT DEPOSITION ISOPLETHS rart au roenes Pts aart.nonis
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 () Additional exposure pathways include direct exposure from contaminated ground and vegetation and exposure from ingestion of contaminated vegetables and meats. The gaseous effluent concentrations were calculated for each 22.50 sector within 50 miles of the Byron Station based on 3 years of meteorological data gathered at the site. Resultant skin, thyroid, inhalation, and whole-body dose rates were calculated for the predicted population in each sector for the year 2000 and for the hypothetical individual exposed continuously to the gaseous effluents at the site boundary where minimum effluent dilution has occurred. The inhalation dose to such a " maximum" individual was also calculated. The resultant exposure rates are conservative estimates since occupancy factors and the shielding afforded by structures such as houses were ignored. 5.2.1.2.2 Aquatic Pathways The aquatic pathways of radiation exposure to persons will be essentially the same as those described for biota other than man in Subsection 5.2.1.1.2. The two important exposure pathways for persons are the following:
- a. internal exposure from ingestion of water or contaminated food chain components; and
(~J) \
- b. external exposure from the surface of contaminated water or sediment.
There are no municipal water intakes on the Rock River within 50 miles downstream from the Byron Station. Two known fields of irrigated corn, however, are located within 50 miles downstream from the effluent discharge. The closest is a 177-acre field on the east side of the river with its irrigation intake 4.7 n.iles 3 doanstream from the station discharge. The other irrigated field is a 93-acre field on the west side of the river with the irrigation intake 6.7 miles below the station discharge. Corn grown in these fields is used as feed grain and is marketed at both Spring Valley and Hennepin, Illinois. The exposure pathway to persons from grain irrigated with water containing very dilute concentrations of radionuclides would be by way of the ingestion of meat from livestock that were fed the irrigated feed grain. Doses that occur through this pathway are described in Subsection 5.2.4.1. Although some commercial fishing is conducted on the Rock River, only a few commercial licenses have been issued. Markets for the fish caught in the Rock River are primarily in Chicago and southward along the Mississippi River. O 5.2-3
. . _ _ .. __ _ _ _ _ _m.. _ . _ . , _ . _ . ._ -... _ _ _ _ _ _ _ . _ _ . _ _ _ __
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 , The Rock River is a popular recreational area. There are sport fishing and recreational boating activities up and The down the river small from the Byron Station (see Subsection 2.1.2.3). 4 2 r 1 r t O 4 0 4 i 4 i I l O I 5.2-3a 4
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Byron ER-OLS amount of radiation escaping from the river's surface could l result in low-level exposure to individuals fishing or boating. Activities such as swimming or water-skiing would be expected to result in slightly higher, although still insignificant, radiatica doses. External dose rates were estimated for an individual boating or swimming at the discharge point. The exposure rate from contaminated shoreline sediments was also calculated. A drinking-water dose was estimated, although consumption of water near the discharge is not anticipated. Evaluation of each pathway was based on maximized conditions; no credit was taken for dilution of the effluents by mixing in the river. All interactions were assumed to occur with the radionuclide concentrations that will occur at the point of discharge. 5.2.2 Radioactivity in Environment This subsection describes quantitatively the distribution in the environment of the small releases of radioactivity from the Byron Station. These releases are included in the liquid and gaseous effluents discharged from the station. 5.2.2.1 Surface Water Models The models used to predict the fate of radionuclides released into surface waters estimated the physical effects using conservative assumptions. The radionuclides released in the blowdown from the Byron Station cooling tower will be rapidly diluted in the Rock River. The average annual blowdown rate is 30 cubic feet per second (cfs) compared with the average annual river flow rate of 4580 cfs. Dilution of station effluents by ambient river water occurs immediately after release of blowdown to the river. A dilution factor of 153 times for the blowdown was calculated from the mean yearly river flow. Also, a reduction in radionuclide concentrations will occur due to radioactive decay between the time of effluent release and the time of exposure; however, credit for this reduction in concentration was not taken in the calculation of doses in order to obtain the most conservative dose estimate. The concentration of isotopes in the Rock River and the bioaccumulation factors for fish, crustaceans, mollusks, and aquatic plants are listed in Table 5.2-1. The radionuclide concentration estimates given in this table assume no dilution of effluents nor any radioactive decay. It is not likely, however, that any of the fish, invertebrates, or aquatic plants studied will be present at the point of the blowdown long enough for the radionuclide equilibrium to be established, or that all animals that feed on these organisms will obtain their food entirely from g 5.2-4
Byron ER-OLS 5.2.4.4 Annual Population Doses (~}
%) The population dose due to caseous effluents to all individuals living within a 50-mile radius of the Byron Station was calculated using population data projected to the year 2000. The estimated dose from gaseous effluents for the year 2000 population within a 50-mile radius of the site appears in Table 5.2-10. This table shows whole-body, skin, and thyroid doses resulting from exposure from immersion, inhalation, and ground deposition.
The population dose caused by direct radiation to all individuals living within a 50-mile radius of the Byron Station was also calculated using population data projected for the year 2000; it is given in Table 5.2-11. The population dose resulting from natural background radiation to all individuals living within a 50-mile radius of the Byron Station is given in Table 5.2-11. This dose was calculated assuming a dose to individuals of 135 mrem /yr and was based on population data projected for the year 2000. 5.2.5 Summary of Annual Radiation Doses The estimated radiation doses to the regional population from all station-related sources are summarized in Table 5.2-11. QJ l l l
'l s_;
5.2-9
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCH 1982 TABLE 5.2-1 CONCENTRATION OF RADIONUCLIDES IN THE DISCHARGE AND THE CORRESPONDING BIOACCUMULATION FACTORS CONCENTRATION RELEASED AT DISCHARGE ACTIVITYa POINTa AQUATIC BICACCUMULATION FAC'IY)RS ISOTOPE (Ci/yr) (pC1/ liter) FEII CRUSTACEAji . MOLLUSK ALGAE H-3 3.0 x 10 2 1.2 x 10 4 9.0 x 10-1 9.0 x 10-1 9.0 x 10-1 9.0 x 10-1 Cr-51 6.2 x 10-5 2. 4 x 10
-3 2.0 x 10 1 2.0 x 103 2.0 x 103 4.0 x 103 1 Mn-54 1.0 x 10 3 3. 9 x 10- 2 4.0 x 10 2 9.0 x 104 9.0 x 104 1.0 x 104 Fe-55 5.4 x 10-5 1.1 x 10-3 1.0 x 102 3.2 x 103 3.2 x 103 1.0 x 103 Fe-59 3.5 x 10-5 1.4 x 10-3 1.0 x 102 3.2 x 103 3.2 x 103 1.0 x 103 3 Co-58 4.5 x 10-3 1.7 x 10 3 5.0 x 10 1 2.0 x 102 2.0 x 102 2.0 x 107 5.0 x 101 2.0 x 102 2 2.0 x 10 2 1 Co-60 3.3 x 10-3 3.4 x 10 1 2.0 x 10 2
Br-83+d 1.0 x 10-5 7.o x 10-4 4.2 x 10 2 3.3 x 102 3.3 x 102 5.0 x 10 Rb-86 4.7 x 10-5 1.8 x 10 -3 2.0 x 103 1.0 x 103 1.0 x 10 3 1.0 x 103 3 Sre59 1.3 x 10*5 5.0 x 10-4 3.0 x 101 1.0 x 102 1,9 x 102 5.0 x 102 Mo-9)+d 2.0 x 10-3 7.7 x 10 -2 1.0 x 10 1 1.0 x 101 1.0 x 10 1 1.0 x 10 3
-2 1 1 1 Mo-99d 2.e x 10 -3 7.7 x 10 1.0 x 10 1.0 x 10 1.0 x 10 1.0 / 10 0 0 1 T:. 99m 2.3 x 10 -3 8.9 x 10-2 1.5 x 10 0 5.0 x 10 5.0 x 10 4.0 x 10
-4 2 2 Te-127 1.4 x 10
-6 5.4 x 10 4.0 x 10 7.5 x 10 1
7.5 x 10 1 1.0 x 10 Te-129m+d 4.6 x 10 -5 1.8 x 10
-3 4.0 x 10 2
7.5 x 10 1 7.5 x 10 1 1.0 x 10 2
-S -3 2 1 2 Te-129 1.0 x 10 1.2 x 10 4.0 x 10 7.5 x 10 7.5 x 10 1.0 x 10 Te-131m 3. 3 x 10
-5 1.3 x 10
-3 4.0 x 10 2
7.5 x 10 1 7.5 x 10 1 1.0 x 10 2
-2 2 1 1 Tc-132 6. 2 x 10-4 2.4 x 10 4.0 x 10 7.5 x 10 7.5 x 10 1.0 x 10 l
2 2 3 Te-132d 6. 2 x 10
-4 2.4 x 10 -2 4. 0 x 10 7.5 x 10 1 7.; x 10 1.0 x 10
-4 4.3 x 10- 1 0 0 4.0 x 10 1
1-130 3.1 x 10 1. 5 x 10 5.0 x 10 5.0 x 10 0 1 1 0 1 l 1-131 8.0 x 10-2 3.1 x 10 1.5 x 10 5.0 x 10 5.0 x 10 4.0 x 10
-2 1 0 0 1 I-J 32 1.9 x iO-I 7.0 x 10 1.5 x 10 5.0 x 10 5.0 x 10 4.0 x 10
-2 0 1 0 0 1 I-133 3.7 x '. 0 1.4 x 10 1.5 x 10 5.0 x 10 5.0 x 10 4.0 x 10
-3 -1 l 0 0 1 3 1-135 4. 3 x 10 1.7 x 10 1. 5 x 10 5.0 x 10 5.0 x 10 4.0 x 10 2 2 Cs-134 2.8 x 10- 1.1 x 10 0 2.0 x 10 3
1.0 x 10 1.0 x 10 5.0 x 10
- 6. 9 x 10 -3 2 2 Cs-136 2. 7 x 10 2.0 x 10 1.0 x 10 2 1.0 x 10 5.0 x 10 3
-2 3 3 2 2 2 CS-137 3.5 x 10 1.4 x 10 2.0 x 10 1.0 x 10 1.0 x 10 5.0 x 10
-5 -4 I 2 2 2 Np-239 2.3 x 10 8.9 x 10 1.0 x 10 4.0 x 10 4.0 x 10 3.0 x 10 a values based on 1-unit operation.
5.2-10
r i Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCH 1982 TABLE 5.2-6 RADIONUCLIDE CONCENTRATION AND INTERNAL DOSE RATES TO BIOTA OTHER THAN MAN ORGANISM ISOf0FE' CONCENTRATION (pCi/ liter DOSE (mrad /yri b Fish Cs-134 1.1 x 100 1.1 x 101 Cs-136 2.7 x 10*1 2.7 x 100 Cs-137 1.4 x 100 1. 3 'm 101 l3 Total Dose 2.9 x 101 mrad /yr Crustacean H-3 1.2 x 104 1.1 x 10 0 l3 Mn-54 3. 9 x 10- 2 3.3 x 100 Cs-134 1.1 x 100 5.2 x 10-1 Cs-137 1.4 x 100 6.7 x 10*1 Total Dose 6. 4 x 100 mrad /yr Mollusk H-3 1.2 x 104 1.1 x 100 3 Mn-54 3.9 x 10-2 3.3 x 100 Cs-134 1.1 x 100 5.2 x 10*1 Cs+137 1.4 x 100 6.7 x 10-1 Total Dose 6.4 x 100 mrad /yr Algae H-3 3 1.2 x 104 1.1 x 100 Mo-99+d 7.7 x 10-2 6.1 x 10*1 Cs-134 1.1 x 100 2.6 x 100 i
% co-136 2.7 x 10-1 6.8 x 10-1 13 8
Cs-137 1.4 x 100 3.4 x 100 Total Dose 1.U x 101 mrad /yr 1 l3 Duck (aquatic plant diet) Co-134 1 1 x 100 7.2 x 101 Cs-137 1.4 x 100 6.4 x 101 Total Dose 1.4 x 102 mrad /yr Raccoon (fish diet) Cs-134 1.1 x 100 1.4 x 102 Cs-137 1.4 x 100' 1.3 x 102 Total Dome 2.8 x 102 mrad /yr. Raccoon Ia (crustacean diet) H-3 Mn-54 1.2 x 104 3.9 x 10-2 9.8 x 10'1 1,7 x loo lJ es-134 1.1 x 100 7,2 x 100 Cs-137 1.4 x 100 6.4 x 100 Total Dose 1.7 x 101 mrad /yr Raccoon fmollusk diet) H-3 1. 2 x 104 9.8 x 10 ~1 Mn-54 3,9 x 10-2 1.7 x 100 Co-134 1.1 x 100 7.2 x 100 Cs-137 1.4 x 1:0 6.4 x 100 Total Dose 1.7 x 101 mrad /yr 8 1sotopes contributing 5% or more to the total dose. gj b Values based on 1-unit operation. 5.2-15
TABLE 5.2-7 PATHWAYS DOSES FROM LIOUID EFFLUENTS WHOLE BODY SKIN THYPOID BONE GI-TRACTa PATHWAY (mrem /yr) (mrem /yr) (mrem /yr) (mrem /yr) (mrem /yr) Consumption of -2 Fish 4.54 x 10-1 - 1.03 x 10-1 3. 4 8 x 10-1 1.87 x 10 3 1 Shoreline -3 -3 -3 Activities 7.80 x 10 -3 9.11 x 10 7.80 x 10 7.80 x 10-3 7.80 x 10 to Swimming and _4 % m - Boating 2.47 x 10_4 3.21 x 10_4 2.47 x 10 2.47 x 10_4 2.47 x 10_4 o n w 0 Drinking Water 7.36 x 10-1 - 3.49 x 10 7.01 x 10-2 6. 6 2 x 10-1 1 3$ h 1 Appendix I @ m 10 CFR 50 1 1 1 1 Design Objectives 3.0 x 10 0 1.0 x 10 1.0 x 10 1.0 x 10 1.0 x 10
=p4>
>I C%
N tr3 t* to Notds: All activities are assumed to take place in the discharge canal. No credit is @ $ *$ taken for dilution of effluents in the Rock River. Values based on 1-unit g g [g ez mz operat. ton. ma Hd a Gastro-Intestinal Tract. z y O O e -
- Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 i TABLE 5.3-1 4
i ' ESTIMATED AVERAGE BLOWDOWN ANALYSIS I I i l AMOUNT ! CONSTITUENT (mg/ liter) i ' Calcium 174 i 4 f j Magnesium 89 i f i Sodium 48 ; 3 Sulfate 602. .
- 3
I Chloride 74 l Alkalinity (as CACO 3) 143' Nitrate 5 i TDS 1555 i
, SiO2 8 l i
9 1 I i t 4 i $ T 5 t ) , 4 P i I i : < i l " ; I i l ! I f 'i 5.3 ! i
TisBLE 5.3-2 AVERAGE CHEMICAL DISCHARGES OF TIIE BYRON STATION (All values except pII in mg/ liter) AVERAGE AMBIENT DISCHARGE APPLICABLE ILLINOIS STANDARDS RIVERa TO RIVEE b EFFLUENT WATER QUALITY Alkalinity 308 143 None None (as CACO 3) Calcium 233 174 None None Chloride 43 74 None 500 to Magnesium 180 89 None None y o D Nitrates 4 5 None None P M w S pH (range) 6.4 - 8.7 Within 5 - 10 6.5 - 9.0 3 7 Standards @ en Silica 6.2 8 None None Sodium 30 48 None None Sulcates 63 602 None 500 Total Dissolved h$ Solids 658 1555 3500c 1000 gg
*?
-E mz
$dz aSee Table 3.6-1 for assumption used. ,o b See Table 3.6-5 for assumption used. 3 cApplicable limit for recycling or other pollution abatement practices.
O O e
O O O TABLE 5.3-3 EXPECTED MAXIMUM CHEMICAL DISCHARGES OF THE BYRON STATION (All values except pH in mg/litar) AVERAGE AMBIENT DISCHARGE APPLICABLE ILLINOIS STANDARDS RIVERa TO RIVERb EFFLUENT WATER QUALITY Alkalinity 308 114 None None (as CACO3 ) Calcium 233 188 None None Chloride 43 92 None 500 tn to
- Magnesium 180 97 None None %
i o
" Nitrates 4 8 None None #
to pH (range) 6.4 - 8.7 Within 5 - 10 6.5 - 9.0 3 Y , Standards @ en i Silica 6.2 14 None None Sodium 30 56 None None = Sulfates 63 745 None 500 Total Dissolved 5 to Solids 658 1854 3500c 1000 @@ ek e :2: [ aSee Table 3.6-1 for assumption used. $ b See Table 3.6-4 for assumption used, w 3 c Applicable limit for recycling or other pollution abatement practices. .i i
l l Byron ER-OLS l l
- O '^"'" ' 6-PREDICTED NOISE LEVELS DUE TO RELIEF VALVES OPERATION SOUND LEVEL LOCATION (dBA) 1 77 2 83 3 86 4 53 O
l 1 O l S.6-5
Byron ER-OLS AMENDMENT NO. 3 t1 ARCH 1982 TABLE 5.6-3 COMPARISON OF PREOPERATIONAL AND PLANT-OPERATIONAL CONTINUOUS NOISE LEVELS WITH U.S. EPA GUIDELINES NOISE DUE TO PREOPERATIONAL PLANT OPERATION U.S. EPA LOCATION NOISE LEVEL (Predicted Level) GUIDELINE 1 Ldd = 45 Ldn = 48 Ldn 1 55 2 Ldn = 4 5 Ldn = 53 Ldn 1 55 3 Ldn = 54 Ldn = 54 Ldn 1 55 l3 4 Ldn = 56 Ldn = 35 Ldn 1 55 e i I l Source: U.S. Environmental Protection Agency (U.S. EPA 1974). aT he Ldn or day-night sound level represents the Leg with a 10 dB nighttime penalty (see Subsection 2.7.2). 5.6-6
t I i l Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 { j TABLE 5.6 4 COMPARISON OF PREOPERATIONAL AND PLANT OPERATIONAL CONTINUOUS NOISE LEVELS WITH HUD GUIDELINES i PREOPERATIONAL NOISE LEVEL NOISE DUE TO 3 (L33_3a) PLANT OPERATION HUD l LOCATION DAY NIGHT (Predicted Level) GUIDELINE 1 38.2 35.5 L33.3 = 42 L33.3 1 65 l 2 38.2 35.5 L33.3 = 47 L33.3 1 65 3 46.5 47.8 L33.3 = 48 L33.3 1 65 l3 4 47.5 41.7 L33.3 = 29 L33.3 1 65 O i a i a 1 Source: Department of Housing and Urban Development.(HUD 1971).
; aThe'L33.3 is the maximum noise level for 8 hours per 24 hours i w (see Subsection 2.7.3.3).
4 5.6-7
. - , . . ~ ,_. __ _ --- .- - . - - - , . . _ . . ~ . _
AMENDMENT NO. 3 AMENDMENT N0. 1 MARCH 1982 JULY 1981 Marrill Rd. t V E E c *
* .5 V o To o Black Walnut Rd.
Natural f p,'.f ? . t*.*.e ? ? ? ? ??? *.t ? ? ? ????.e ? ? ??.tt e ? ? ???.*.a.a . Draft Cooling) g E
.o . .: : :. m j llll ijjj TOWERS g 3 :::: ::::
s f..rM*.:i' .M.V.?f; $
!!5erman dhur'ck..i[d.': .
E
- .,..v ........- ::::: ... :.::
- i.:
.u. i; P..l.a.. n t..:.:. .:::..::::.
r.:: i.:!:. . . u. Ebenezer
-4 s-
- i y::
a::: :l:i:.
'"m ...,
~. ' :i::E Church 5 ;- ..
- p. 5
~~
.in;isi sii l ~P/lechanical'
- Draft is* * '~o House
.$hi.:p!! Cooling Tower j
+ ::::fal i
g ,,, g ,,
- 05 ...................5i
.,1 ,''''
m , ,,..E
.: w iisehsetidi&asiiiee!
. ..:::i*' Razorville Rd.
% *'Houses i d:: .
fi:' E:i E::
..::!/.:::Y
- P
- :i:i e
- P
!:! <8i:
t :: :::= 2 River
. .........!a:i:
. .:. . w.v t.
Screen House !!!! 7; ,
$[ !!} Vine Dr. E c
- i: ::: S li:i
):
!!!! j!
- !: ::: Cemetery
*::: i:;
}
, :lyy..p __ River Rd._
!fi:
I h.L IfRON NUCLEAR GENERATING STATION
................... ..Si te B o u n da ry UNITS 1 &2
'"~""'"""'"~~'"""""*"'
O. O"oise arediciioa 'ocatioa (./ 3000 o FIGURE 5.6-1 3 coo SCALE IN FEET NOISE PREDICTION LOCATIONS i
' Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT Nr. 3 MARCH 1982 O
CHAPTER 8.0 - ECONOMIC AND SOCIAL EFFECTS OF STATION OPERATION The Byron Nuclear Generatlag Station - Units 1 & 2 (Byron Station) will create approximately 504 permanent new jobs at the 1 station site and an estimated annual payroll of $12.4 n.illion in 1981 dollars when the station is in commercial operation in 1985. Land use at the Byron Station before construction was basically agricultural. Of the approximately 1782 acres in the site area, 3 approximately 1390 acres were cropland. The acres removed from production represent only 0.08% of the total cropland in Ogle I County. The land use of the plant area has been changed from 1 j agricultural to industrial. There has, however, been little impact on surrounding agricultural production. With regard to adjacent land use, a commercial motorcycle trail is located adjacent to the site (see Section 4.1). Permanent new residents attracted as a result of the Byron Station project will be dispersed throughout the surrounding communities (see Section 8.4) so that there will ne little effect on local services. The increased tax revenue attributable to the Byron Station project is estimated to be $11 million in 1985 from 1 property taxes (see Section 8.2). Taxing districts within which
% the station is located should receive more tax dollars than s required to provide the additional services for the new 4
residents. There are no historical sites on the Byron site (see Section 2.6) or recreational uses other than that of the adjacent commercial 1 motorcycle trail and the Rock River. There will be no effect on recreational and commercial uses of the Rock River (see Section 2.1),
/~N V
8.0-1
-. - -. - _ - ._ - _ - _-.-_-.- _~ _ - . - . _ -
i ' Byron ER-OLS AMENDMENT NO. 1 JULY 1981 1 () CHAPTER 12.0 - ENVIRONMENTAL APPROVALS AND CONSULTATIONS The licenses, permits, and other approvals required by federal, state, and local authorities for the construction and operation l of the Byron Nuclear Generating Station - Units 1 &2 (Byron Station) are listed in Table 12.0-1. This table indicates the l
' issuing government agency, the statutory basis of agency's authority, the activity for which approval is required, the category of environmental impact, and the status of each permit.
l The table is based on the design of the Byron Station, the project schedule, and the statutes and regulations applicable as 1 of July 1981. Should it become necessary in the future to apply f j y for other approvals or permits, Commonwealth Edison Company will take action. Table 12.0-2 lists the state and local authorities contacted in connection with the Byron Station. I I l I I l i l v i { i O t ( 12.0-1
r-- - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ TABLE 12.0-1 AUTIIORIZATIONS REQUIRED FOR CONSTRUCTION AND OPERATION OF THE BYRON STATION ET A Ti% rF FTFFIT CATFGCP' OF FE EM :T Fpgt{II Ii f it'LY 1981) F*N . Y *T Aga TT ATt'TE ALT!P F ITY PUFPcFF ASTNCY OFSckIPTICN G r ar.t ed 12-31-75 Aar, Larol, Wat e r - Constructicr. Atomic Energy Act Const ru.~t l' nits 1 & 2 U.S. Nuclear G Regulatory Permit o f 1%4 ar.d Feg a la-Commission tion 10 CFR 5) Nde t r i e i 12-1-79 Aar, Larf. Water - U.S. Nuclear Oterattnq Atomic Energy Art Operate t' nits 1 & 2 0F Rega lat or y Fermit of 1954 and Fegula-Coreission tion 10 CFP 50 m.s' + 1 1 a l w prior Gra: te! In tart - Radioloalcal - OF { U.S. Nuclear Materials 10 CFh 70 Possess stecial nuclear 7 .- 79 to og+ rat ing license kequlator/ License other tart to te CcerJnis sion at Ilied for 12,'F 1 g M Possecs by-product materials prior t. ranted 10- E-RC Pad i a l cvj l .ca t - CF O H U.S. Nuclear By-Frodact lu CFR 30 D to operattnq licensa peq u1 st ory License Comrni ss ion o 33 USC 5 403, 404, Construct intake and discharge Grarted 5-lF-77 Water - CY 3 7 U.S. Army Construction 565, 1344 structures O Corgs of Fermit t* Engar.eers UI Construct barge unloading dock Grar.ted 6-25-75 Wa t e r - CF U.S. Airy Construction 33 USC i 403, 404, Corps of Fernit 565, 1344 Engineers Granted 2-22-71 Land - Ilanning Federal Avia- Approval Civil Aeronautics Approval of 370-foct meteorcloqical act of 1938 as tower tion A&nints-tration amended Sections 205 and 1101 Granted 5-7-73 Lard - Planning Federal Avia- Artroval Civil Aeronautics Approval of cooling tcwers p 3CQ >3l tion Adminis- Act of 1938 as *O M t* [TJ tration amended Sections OZNZ 205 and 1101 ZO O Civil Aeronautics Notice of proposed use of construction Granted 10-20-79 Lar.d - Flar.n t r.q g AFproval 1 CceZ qCD p 8Z Federal Avia-Act of 19 3'3 as crane tion Adminis-tration amended Sections fJ 205 and 1101 Z Z O O ACE = Construction Ef fect; CE = Operational Ef fect. W H G G e
T G G e TABLE 12.0-1 (Cont'd) ST7TUS OF PERMIT CATEGORY CF PERMIT RFC431 FED DESCRIPTICN STATUTE AUTHORITY PUFPCSE (JUI.Y 1941) PW. IMPACTa 1 AGENCY IvPCA section 402 Discharge treated plant waste Granted 5-19-76 Water - CE and OE U.S. Environ- NFCES Perinit mental Protec-tion Agency Construct and operate Units 1 & 2 Granted 7-11-73 Land - Planning Illinois Com- Cert. of Ill. Public merce Commis- Convenience Utilities Act, sion & Necessity Ill. Rev. Stat. 1971, Ch. 111-213 5 50 et seq. Byron East transmission line right-of- Granted 3-10-76 Land - Planning g Illinois Com- Cert. of Ill. Public Convenience Utilities Act, way Section 50 Cert. g merce Commit-sion & Necessity Ill. Rev. Stat. issued 7-28-76 P1 1971, Ch. 111-213 Section 55 Cert. O H U N 5 50 et seq. issued 3-10-76 M O Cert. of Ill. Public Byron South transmission line right-of- Granted 3-15-78 Land - Planning y g Illinois Com-Utilities Act, way section 55 Cert. I W merce Corsnis- Convenience O
& Necessity Ill. Rev. Stat. issued 3-15-78 sion 1971, Ch. 111-213 section 50 Cert. M i 50 st M. issued 4-12-78 Illinois Cow- Cert. of Ill. Public Byron - Wespletown transmission line Grar.ted ble-79 Land - Planning Convenience Utilities Act, right-of-way Cert. issued merce Commis-e sion & Necessity Ill. Rev. Stat. }
1971, Ch. 111-213 5 50 et seq. Ill. Public Hequisition of parcels for spur-track Oranted 8-14-74 Land - Planning Illinois Com- Cert. of merce Commis- Convenience Utilities Act, right-of-way sion & Necessity Ill. Rev. Stat. 1971, Ch. 111-213
$ 50 et seq.
Illinois Com- Cert. of Ill. Public Widening Nelson Cherry Valley right-of- Granted 7-12-78 Land - flanning merce Commis- Convenience Utilities Act, way Section 55 Cert. pg sion & Necessity Ill. Rev. o.at. issued 7-12-78 gZ 1971, Ch. 111-213 Section 50 Cert. O I 50 et seq. issued 10-25-79 W%
@M 03 Z H *-3 Z
O e ace = Construction Effects OE = Operational Effect. T a M -
TABLE 12.0-1 (Cont'd) 1 1 PERMIT FIQUIFED STATLS CF ff'FFIT CATEGORY OF ( ( Jt'LY 1991) FNV. IMP A('T 8 _ ACENCY DESCRIPTION S TATt""k. AtTH% ITY Pt U n' 31-( Illinois Ccm- Sapplomont al Ill. Public Construct s; ur-track a: loss five road- Crar.ted 9-24-75 Land - Planning merce Commis- Order Utilities Act, ways sion Ill. Fev. Sta' 1971, Ch. 111-213 5 50 et seg. Illinois Dept. Construction Ill. Conm rce Act Construct intine and discharge struc- Granted 4-7-77 Water - CE of Transporta- Permit June IC, 1911: t ures tion, Div. of (Ill. hev. Stat. Waterways 1969, Ch. 19, 52 et seq.) Illinois Dept. Construction Ill . Cor:merce Act construct targe unloading dock Grarted 1-20-75 Water - CE , of Transivarta- Permit June 10, 1911 tion, Liv. of (Ill. Rev. Stat. Waterways 1969, Ch. 19, 52 g et seq.) Q U M Registration of nuclear materials Granted 5-6-81 Raitological - OE Illinois Dept. Registration Ill. Public Health
& Safety Radiation 3 to O of Nuclear I safety Installation Regi-A stration Law, O July 5, 1957 (111. 1 p Rev. Stat. 1979, (/1 Ch. Illh 1 194-200)
Illinois Dept. Permit Ill. Act of 1941, Drill wells at site for potable water 2 permits, both Water - CE of Mines 6 (Ill. Rev. Stat. granted 9-19-74 i Minerals 1969, Ch. 104, 62 et seq.) Illinois Dert. Permit Ill. Rev. Stat. To construct 370-foot meteorological Granted 3-6-73 Land - Planning of Transporta- 1971; Ch. 127 tower 3pgp tion, Div. of et seq- N 3 C 3: Aeronautics MMEM O Z 64 Z Illinois Dett. Permit Ill. Rev. Stat. To construct cooling towars Granted 5-16-73 Land - Planning %U U of Transporta- 1971, Ch. 127 g tion, Div. of et seq. egmg Aeronautics 03 8 g 8 , N I Z Z O. .O ACE = Construction Effectr OE = Operational Effect. L*) H O O O
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 2 SEPTEMBER 1981 (c) AMENDMENT NO. 3 MARCH 1982
, 1977a, Census of Acriculture - 1974, Area Reports, Part 12, Illinois, U. S. Government Printing Office, Washington, D. C.
, 1977b, Census of Acriculture - 1974, Area Reports, Part 14, Iowa, U. S. Government Printing Office, Washington, D. C.
, 1977c, Census of Agriculture - 1974, Area Reports, Part 46, Wisconsin, U.S. Government Printing Office, Washington, D. C. )
, 1981, 1980 Census of Population and Housing, U.S.
1 Government Printing Office, Washington, D.C.
, 1981b, 1978 Census of Agriculture, U.S. Government Printing Office, Washington, D.C. 2 Clapper, R. L., 1977, Amoco Pipeline Company, Chief Engineer, Letter of April 27 to C. W. Comerford, Sargent & Lundy Cultural Resource Analyst.
Collins, C., 1981, manager, The Stronghold, Oregon, Illinois, Telephone Conversation of June 9 with R. Kunshek, Terrestrial 1 Biologist, Commonwealth Edison.
)
Comerford, C. W., 1977, Visual survey in June of the area within 10 miles of the Byron site. Commonwealth Edison Company, 1977a, "316(b) Demonstration, Byron Generating Station Makeup Water Intake System," Commonwealth Edison Company, Chicago, Illinois.
, 1977b, Industrial survey performed in June and July by A.
H. Mekeal and W. Schuttler, Commonwealth Edison Company. Eden, S., 1977, Ogle County Agricultural Extension Office, Personal Communication on June 24 with C. W. Comerford, Sargent & Lundy Cultural Resource Analyst. Etnyre, G. M., 1982, Mt. Morris Boat Club, Oregon, Illinois, Telephone Conversation of January 11 with R. Kunshek, Terrestrial 3 Biologist, Commonwealth Edison. Federal Aviation Administration, 1976a, " Airport Master Records: Yost International," Federal Aviation Administration (FAA) Form 5010-1, U. S. Department of Transporation, Des Plaines, Illinois. Federal Aviation Administration, 1976b, " Airport Master Records: s Lunn Seaplane Base," FAA Form 5010-1, U. S. Department of l l [J
) Transportation, Des Plaines, Illinois.
l 13.0-3 I
Byron ER-OLS AMENDMENT NO. 3 i MARCH 1982 Federal Aviation Administration, 1976c, " Airport Master Records: Duane E. Davis Airport," FAA Form 5010-1, U. S. Department of Transportation, Des Plaines, Illinois. } i i i i 'l O l l 1 O 13.0-3a
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 2 SEPTEMBER 1981 O Federal Aviation Administration, 1976d, " Airport Master Records: Stukenberg Airport," FAA Form 5010-1, U. S. Department of Transportation, Des Plaines, Illinois. Glaston, L., 1981, owner, Lake LaDonna Family Campground, Oregon, Illinois, Telephone Conversation on June 9 with R. Kunshek, Terrestrial Biologist, Commonwealth Edison. Glasser, R., 1981, School Director, Village of Progress, Inc., Oregon, Illinois, Telephone Conversatin on June 24 with R. y Kunshek, Tetresu isl Biologist, Commonwealth Edison. Glotfelty, J., 1981, President, Oregon Country Club, Oregon, Illinois, Telephone Conversation On June-10 with R. Kunshek, Terrestrial Biologist, Commonwealth Edison. Hayes, R., 1977, Lowden Memorial State Park, Site Superintendent, Telephone Conversations on June 14, October 31, and November 8 with C. W. Comerford, Sargent & Lundy Cultural Resource Analyst. Hines, M. P., 1977, U. S. Army Corps of Engineers, Rock Island District, Chief, Permits and Statlstics Branch, Letter of February 7 to D. H. Kim, Sargent & Lundy Water Resources and Site Development Engineer. Huebner, L.G., 1981, Director of Nuclear Sciences, Hazleton Environmental Sciences, Northbrook, Illinois, Letter of August 10 j to C. L. McDonough, Director of Environmental Assessment, Commonwealth Edison Company. Illinoir suoperative Crop Reporting Service, Illinois Department of Agriculture, and U. S. Department of Agriculture, 1976,
" Illinois Agricultural Statistics, Annual Summary 1976," Bull.
76-1, Illinois Cooperative Crop Reporting Service, Springfield, Illinois.
, 1980, " Illinois Agricultural Statistics, Annual Summary 2 1980," Bull. 80-1, Illinois Cooperative Crop Reporting Service, Springfield, Illinois.
Illinois Department of Conservation, 1976a, " Land and Historic Sites Attendance," Springfield, Illinois.
, 1976b, " Analysis of Sales, 1975 Series, Fishing, Hunting, and Trapping Licenses," Springfield, Illinois.
197'a, "Public Hunting Areas in Illinois," Springfield, Illinois.
, 1977b, "1977 Illinois Hunting Information," Springfield, Illinois.
13.0-4
1 i Byron ER-OLS NIENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3
^
OUESTION 291.1 Provide a "best estimate" of biomass of fish harvested annually for human consumption via the recreational fishery on the Rock River in the vicinity of the Byron Site.
RESPONSE
Based on five years of creel survey data for the period 1975-1980, approximately 12 to 19 pounds of fish per acre are harvested annually via recreational fishing 50 miles upstream and 50 miles downstream of the Byron Site. This 100-mile reach of the Rock River contains approximately 8165 surface acres. l3 O O Q291.1-1
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MAP.CH 1982 QUESTION 320.1 Identify the latest scheduled commercial operating dates for Byron 1 and Byron 2.
RESPONSE
The current scheduled commercial services dates for Byron Unit 1 and Byron Unit 2 are February 1984 and February 1985 l3 respectively. i I l t . Q320.1-1
. ___. . ._..=-- . --. _ _..-. _ _ __ . ._ _ _ _..=-.- _ _ - . _ . .. ..____
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 l AMENDMENT NO. 3 ! QUESTION 320.4 i Quantify, if possible, the expected effect of Byron 1 and 2
- on base load consumption of coal and oil.
j
RESPONSE
] . The attached Tables 0320.4-1, 0320.4-2,and 0320.4-3 present - the estimated tons of coal, barrels of oil, and therms of . natural gas saved for each year from 1984 through 1990 inclusive with Byron Units 1 and 2 being placed in operation 3 in February 1984 and February 1985, respectively. The tables present the savings for both the forecasted load 1 growth (2% per year) and the no load growth scenarios. 1 O 9 1 a O Q320.4-1 , l
)
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCH 1982 TABLE Q320.4-1 ESTIMATED TONS OF COAL SAVED ANNUALLY WITH BYRON UNITS 1 AND 2 (In 1000's) FORECAST LOAD GROWTil (2 1 NO LOAD GEOWTil (0%) YEAR AND WITilOUT WITil COAL WITHOUT WITH COAL TYPE OF COAL BYRON BYPON SAVING BYRON BYRON SAVING 1984 Low S 11,862 10,335 1,527 10,943 9,194 1,749 111gh S 2,685 2,566 119 2,638 2,504 134 TOTAL 14,547 12,901 1,646 13,581 11,698 1,883 1985 Low S 11,520 8,171 3,349 10,016 6,681 3,335 High S 3,422 3,041 381 3,335 2,856 479 TOTAL 14,942 11,212 3,730 13,351 9,537 3,814 1986 Low S 10,244 6,937 3,307 8,230 5,031 3,199 High S 2,898 2,403 495 2,728 2,155 573 TOTAL 13,142 9,340 3,802 10,958 7,186 3,772 3 1987 Low S 10,128 6,421 3,707 7,557 4,413 3,144 Ifigh S 2,966 2,522 444 2,755 2,214 541 TOTAL 13,094 8,943 4,151 10,312 6,627 3,685 1988 Low s 9,043 5,806 3,237 6,085 3,618 2,467 High S 3,035 2,533 502 2,620 2,070__ 550 TOTAL 12,078 8,339 3,739 8,705 5,688 3,017 1989 Low S 10,450 7,008 3,442 6,836 4,118 2,718 liigh 5 3,034 2,625 409 2,634 2,179 455 TOTAL 13,484 9,633 3,851 9,470 6,297 3,173 1990 Low S 11,617 8,054 3,563 7,040 4,462 2,578 liigh S 2,865 2,509 356 2,486 2,021 465 TOTAL 14,482 10,563 3,919 9,526 6,483 3,043 Q320.4-2
I i l Byron ER-OLS AMENDMENT NO. 1 ! JULY 1981 l AMENDMENT NO. 3 MA H 1982 TABLE Q320.4-2 l l ESTIMATED BARRELS OF OIL SAVED ANNUALLY WITH BYRON UNITS 1 AND 2 (In 1000's) FORECAST IDAD GROWTH (2%) NO LOAD GROWTH (0%) YEAR AND WITHOUT WITH OIL WITHOUT WITH OIL TYPE OF OIL BYRON BYRON SAVING BYRON BYRON SAVING I 1984 No. 2 370 201 169 186 96 90 l No. 6 6,415 4,957 1,458 4,893 4,043 850 TOTAL 6,785 5,158 1,627 5,079 4,139 ,940 t 1985 No. 2 192 57 135 66 17 49 No. 6 5,702 3,694 ,2,008 3,662 2,489 1,173 TOTAL 5,894 3,751 2,143 3,728 2,506 1,222 1986 No. 2 113 25 88 26 4 22 ( No. 6 5,002 2,661 2,341 2,842 1,438 1,404 TOTAL 5,115 2,686 2,429 2,868 1,442 1,426
.3 1987 No. 2 217 37 180 35 4 31 No. 6 6,039 3,090 2,949 3,567 1,499~ 2,068 d
TOTAL 6,256 3,127 3,129 3,602 1,503 2,099 1988 No. 2 107 22 85 10 1 9 No. 6 5,127 2,888 2,239 2,327 882 1,445 TOTAL 5,234 2,910 2,324 2,337 883 1,454 1989 No. 2 262 52 210 20 2 18 No. 6 6,355 4,002 2,353 2,847 1,346 1,501 TOTAL 6,617. 4,054 2,563 2,867 1,348 1,519 1990 No. 2 457 109 348 25 3 22 ! No. 6 7,469 5,076 2,393 3,693 1,665 2,028 i TOTAL 7,926 5,185 2,741 3,718 1,668 2,050 O V Q320.4-3
I Byron ER-OLS AMENDMENT NO. 3 l MARCH 1982 l TABLE Q320.4-3 ESTIMATED THERMS OF GAS SAVED ANNUALLY WITH BYRON UNITS 1 AND 2 (In 1000's) FORECAST IDAD GRONTII (2%) NO LOAD GROWTH (0%) YEAR WITHOUT WITII GAS WITliOUT WITH GAS BYRON BYRON SAVING BYRON BYRON SAVING 1984 59,363 49,511 9,852 49,001 43,172 5,829 TOTAL 59,363 49,511 9,852 49,001 43,172 5,829 1985 41,271 28,208 13,063 29,076 23,746 5,330 TOTAL 41,271 28,208 13,063 29,076 23,746 5,330 1986 21,904 8,804 13,100 9,217 5,441 3,776 3,776 3 TOTAL 21,904 8,804 13,100 9,217 5,441 O 1987 33,630 6,982 26,643 6,883 1,033 5,850 TOTAL 33,630 6,982 26,648 6,883 1,033 5,850 1988 16,881 3,928 12,953 1,917 299 1,618 TOTAL 16,881 3,928 12,953 1,917 299 1,618 1989 37,776 8,938 28,838 3,976 515 3,461 TOTAL 37,776 8,938 28,838 3,976 515 3,461 1990 63,777 17,970 45,807 5,010 775 4,235 TOTAL 63,777 17,970 45,807 5,010 775 4,235 9 Q320.4-4
l Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 , QUESTION 320.5 Provide the most recent estimates of the capital cost j for Byron 1&2, separating the cost by unit. Indicate j the proportion of the estimated capital costs which have been spent. i
RESPONSE
The estimated direct capital costs for each unit at the Byron Station with percentage spent are as follows: 1 Direct Capital Percentage Costa Spentb Unit 1 $1,098,806,000 79 Unit 2 $ 709,148,000 63 3
, TOTAL $1,807,954,000 73 -
C:)
]
I a i a Exclusive of land. () b Percentage through December 1981. Q320.5-1
l ii Byron ER-OLS AMENDMENT NO. 1 JULY 1981 QUESTION 320.6 - For the first year of commercial operation for each unit l provide estimates of the total generating costs and of each l component of the costs (fixed charges, fuel, O&M, other) both in mills /kWh and in dollars.
) RESPONSE Tables Q320.6-1 and Q320.6-2 provide the estimated total generating cost for Byron Station Unit 1 and Unit 2 for the first 12 months of commercial operation for each unit.
l
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1 l' I i i O b f i l I { I i l 4 l 6 I Q320.6-1 l
s Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCH 1982 TABLE Q320.6-1 ESTIMATED TOTAL GENERATING COST FOR BYRON STATION UNIT 1 FOR FIRST 12 MONTHS OF COMMERCIAL OPERATION DOLLARS" MILLS PER COST COMPONENT _ (thousands) KILOWATTHOUR" Fuel 64,580 10.97 Operating & Maintenance 39,236 6.67 Carrying Charges 456,560 77.56 3 Other 21,737 3.69 Total Generating Cost $582,113 98.89 O Note: Values are based on commercial operation starting February 1984. 3
" Costs are in 1984 dollars and are based on 60% capacity factor (generating 5,886,720 kWh per year). Coct includes carrying charges on fuel investment.
Q320.6-2
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCII 1982 [-,) TABLE Q320.6-2
\~J ESTIMATED TOTAL GENERATING COST FOR BYRON STATION UNIT 2 FOR FIRST 12 MONTIIS OF COMMERICAL OPERATION DOLLARS" MILLS PER COST COMPONENT (thousands) KILOWATTIIOUR" Fuel 67,760 11.51 Operating & Maintenance 42,766 7.27 Carrying Charges 3 307,695 52.27 l Other 18,785 3.19 Total Generating Cost $437,006 74.24 ' m,)
Note: Valu2s are based on commercial operation starting February 1985. 3 r l (~N ^ Costs are in 1985 dollars and are based on 60% capacity l (_) factor (generating 5,886,720 kWh per year). l Q320.6-3 l
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCil 1982 (3; QUESTION 320.8 Provide the following: A production cost analysis which shows the difference in system production costs associated with the availability vs. unavailability of the proposed nuclear addition. Note, the resulting cost differential should be limited solely to the variable or incremental costs associated with generating electricity from the proposed nuclear addition and the sources of replacement energy. If, in your analysis, other factors influence the cost differential, explain in detail.
- a. The analysis should provide results on an annual basis l covering the period from initial operation of the first unit through five full years of operation ci the last unit.
l
- b. The analysis should assume electrical energy demand i grows at (1) the system's latest official forecasted '
growth rate, and (2) zero growth from latest actual annual energy demand.
- c. All underlying assumptions should be explicitly identified and explained.
()
,~
- d. For each year (and for each growth rate scenario) the following results should be clcarly stated: (1) system production costs with the proposed nuclear addition available as scheduled; (2) system production costs without the proposed nuclear addition available; (3) the capacity factor assumed for the nuclear addition; (4) the average fuel cost and variable O & M for the nuclear addition and the sources of replacement energy (by fuel type) - both expressed in mills per kWh; and (5) the proportion of replacement energy assumed to be provided by coal, oil, gas, etc.
RESPONSE
The incremental system power production costs in 1981 dollars with and without Byron Units 1 and 2 are provided in Table 0320.8-1 for the forecast load growth (2% per year) and l3 the no load growth scenarios. The bases for these estimated costs are included in Table Q320.8-2 and in the following list of estimated fuel costs, which include variable operating and maintenance costs: O t !
\_ '
Q320.8-1
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 MARCll 1982 1981 COST TYPE OF FUEL (mills /kWh) Nuclear 7.0 Coal High Sulfur 19 Low Sulfur 2G 3 i Oil No. 6 68 Peaker 144 Peaker Gas 75 Purchase-Economy 40.2 O O Q320.8-2 L
O O O TABLE Q320.8-1 l INCREMENTAL SYSTEM PRODUCTION COSTS WITH AND WITHOUT THE AVAILABILITY OF BYRON _ UNITS 1 AND 2 (All Costs Are In 1981 Dollars) i AVAILABILITY OF RN SWIM a 1988 1989 1990 1984 1985 1986 1987 PRODUCTION COSTS WITH 2% ANNUAL LOAD GROWTH (Thousands of Dollars) Not available 1,431,147 1,381,579 1,272,047 1,350,225 1,270,850 1,415,806 1,468,924 $" 0 1,016,970 1,003,066 1,126,965 1,189,182 0 1,274,617 1,123,324 993,365 d Available M co Annual Cost 156,530 258,225 278,682 333,255 267,784 288,921 279,742 y o b of Delay b PRODUCTION COSTS WITH NO LOAD GROWTH (Thousands of Dollars) , 1,167,575 1,038,519 914,457 971,885 983,395 Not available 1,274,045 1,017,651 1,148,120 958,063 798,681 783,208 722,151 770,761 782,145hbbb Available R R E; E Annual Cost 125,925 20% J12 218,970 255,311 192,306 201,124 201,250 y R of Delay HMeN eZmZ mdeR Z Z O O aByron Units.1 and 2 are scheduled for February 1984 and February 1985, respectively. w e j w
Byron ER-OLS AMENDMENT NO. 1 JULY 1981 AMENDMENT NO. 3 fiARCH 1982 TABLE Q320.8-2 BASIS FOR INCREMENTAL COSTS PROVIDED IN TABLE Q320.8-1 NORMAL ANNUAL LOAD GROWTH AT 2% 1984 1985 1987 1988 1989 1990 _1986 Capacity Factors (%) Byron Unit 1 48 53 58 74 58 58 58 Byron Unit 2 10 47 53 55 58 58 58 Replacement Power (GWh) 4,764 9,825 10,900 12,673 11,403 11,316 11,376 (without Byron Station) Replacement Energy by Fuels (%) Coal - High Sulfur 5 7 9 7 8 7 6 Coal - Low Sulfur 57 61 54 52 51 54 55 Oil - #6 17 11 12 13 11 12 12 Oil - Peakers 2 1 1 2 1 2 3 Purchase - Economy 11 8 8 8 7 6 7 Nuclear 8 12 16 18 22 19 17 3 NO LOAD GROWTH 1984 1985 1986 __ 1987 1988 1984 1990 Capacity Factors (%) Byron Unit 1 47 53 58 72 55 54 55 Byron Unit 2 10 46 52 53 55 54 54 Replacement Power (GWh) 4,752 9,724 10,737 12,202 10,784 10,629 10,665 (without Byron Station) Replacement Energy by Fuels (%) Coal - High Sulfur 6 9 10 8 10 8 8 Coal - Low Sulfur 65 61 53 46 41 46 43 Oil - #6 10 7 7 10 7 8 11 Oil - Peakers 1 0 0 0 0 0 0 Purchase - Economy 8 7 7 8 7 7 8 Nuclear 10 16 23 28 35 31 30 9 Q320.8-4 (
)
4 Byron ER-OLE AMENDMENT NO. 3 + MARCH 1982 I NRC REQUEST FOR ADDITIONAL INFORMATION j QUESTIONS AND RESPONSES 4 This section contains the NRC requests for additional infor-mation based on B. J. Youngblood's letter of October 23, 1981, ! to L. O. DelGeorge. Each question is followed by its response. 4 l l l I l j i 5 i i ! i !O d 4 a i e i i i ! Q.O-i 1.- i m _ , _ - _ _ . - - , , . - . . , _ _ , _ _ - , , - . . . . , . _ . , _ . - , . , , - . _ . - , , , , _ , - , , , . _ , , , , , , , . ~ , . - - , . ~ , , ,
Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 l QUESTION 371.9 Definition (from Executive Order 11988 Floodplain Management) Floodplain: The lowland and relatively flat areas adjoining inland and coastal waters including flood-prone areas of off-i shore islands, including at a minimum that area subject to a 3 one percent or greater chance of flooding in any given year.
- 1. Provide descriptions of the floodplains of all water bodies, including intermittent water courses, within or adjacent to the site. On a suitable scale map provide delineations of those areas that will be flooded during the one-percent chance flood in the absence of plant effects (i.e., preconstruction floodplain).
l
- 2. Provide details of the methods used to determine the floodplains in response to 1. above. Include your assumptions of and bases for the pertinent parameters used in the computation of the one-percent flood flow
. and water elevation. If studies approved by Flood
- Insurance Administration (FIA), Housing and Urban Development (HUD) or the Corps of Engineers are avail-able for the site of adjoining area, the details of analyses need not be supplied. You can instead provide the reports from which you obtained the floodplain infor-mation.
(}
- 3. Identify, locate on a map, and describe all structures 4 and topographic alterations in the floodplains.
- 4. Discuss the hydrologic effects of all items identified in 3. above. Discuss the potential for altered flood flows and levels, both upstream and downstream. Include the potential effect of debris accumulating on the plant structures. Additionally, discuss the effects of debris generated from the site on downstream facilities, l S. Provide the details of your analysis used in response to 4. above. The level of detail is similar to that identified in Item 2. above.
RESPONSE
The Byron Station is located in the Rock River Basin. A detailed description of the Rock River drainage basin and its tributaries is given in the Byron Station ER-OLS subsection 2.4.1.2 and in Figures 2.4-1 and 2.4-2. 'O e i 0371.9-1 i
Byron ER-OLS AMENDMENT NO. 3 MARCl! 1982 Figure Q371.9-1 shows the flood-prone area of the Rock River in the vicinity of Byron Station. This figure was reproduced from United States Geological Survey flood-prone area map for Oregon, Illinois, Quadrangle (1975). Figure Q371.9-2 shows the flood hazard area of Rock River and its tributaries in the vicinity of Bryon Station due to 1% chance flood. This flood hazard area was delineated by the Federal Emergency Management Agency, Department of Housing and Urban Development (1978). Figures Q371.9-1 and 0371.9-2 show the preconstruction flooded areas. The plant area and the river screen house, which are located in or near the floodplains of the Rock River, are also shown in Figures Q371.9-1 and Q371.9-2. It is evident from these figures that the plant area does not alter the floodplain of Rock River or its tributaries in the vicinity so as to affect their flood-prone areas. The plant area is on or near a ridge area. The river screen house, located on Rock River approximately 5 miles upstream of Oregon Dam, encroaches on the Rock River floodplain as shown in Figures Q371.9-1 and Q371.9-2. The effect of river screen house, on the 1% chance flood level in the Rock River at the location of the river screen house, was evaluated by backwater analysis. The details of input data to the backwater analysis are the same as those described in Subsection 2.4.3.8 of the Byron Station FSAR. The 1-in-100 h year discharge at the river screen house is 62,600 cfs (see FSAR Table 2.4-6). The 1% chance flood level at the streen house under natural conditions is 684.2 feet, and the corres-ponding level with the river screen house in place is also 684.2 feet. The absence of change shows that the river screen house has no effect on the 1% chance flood level in the vicin-ity of the screen house. Figure Q371.9-3 shows the river cross section at the screen house with and without the screen house. At an elevation 684.2 feet, the cross-sectional area under natural conditions is 22,384 square feet. Thus, the river screen house reduced the cross-sectional area of the river under 1% chance flood condition by only 2.8%. This reduction in area is in the left overbank section, and hence, it does not have any significant effect on the water levels upstream or downstream of the screen house. It is clear from the preceding discussion that the Byron Station and, in particular, the river screen house do not alter either flood flows or flood levels, either upstream or downstream of the screen house. No debris is or will be generated or disposed of into the waterways from the Byron Station facilities. Debris accumu-lation at the plant structures is not expected, and hence, there would be no potential effect on flood-prone areas. Q371.9-2
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BYRON NUCLEAR GENE R ATING STATION UNITS 1 &2
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AMENDMENT N0. 3 MARCH 1982 j e lE 1 I I l l I I I I l I ) LEVEL EL. 684.2 FT. I I n s
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Byron ER-OLS AMENDMENT NO. 3 MARCH 1982 QUESTION 371.10 Calculate the radiological consequences of a liquid pathway release from a postulated core melt accident. The analysis should assume, unless otherwise justified, that there has been a penetration of the reactor basemat by the molten core mass, and that a substantial portion of radioactively contaminated sump water was released to the ground. Doses should be compared to those calculated for the Liquid Pathway Generic Study (NUREG-0440, 1978) land-based river site. Pro-vide a senmary of your analysis procedures and the values of parameters used (such as permeabilities, gradients, populations affected, water use) . It is suggested that meetings with the staff of the Hydrological Engineering Sec-tion be arranged so that we may share with you the body of information necessary to perform this analysis.
RESPONSE
In accordance with the NRC's Statement of Interim Policy as published in the Federal Register, June 13, 1980, (45 FR 40101 6/13/1980), the NRC Staff included a severe accident analysis in their Draft Environmental Statement related to the operation of Byron Station Units 1 and 2 (NUREG-0 84 8, November 19 81) . O The aforementioned Interim Policy also states " Environmental Reports submitted by applicants for construction permits and operating licenses on and after July 1, 1980, should include a discussion of the environmental risks associated with accidents that follows the guidance herein." Since the Byron ER-OLS was docketed November 1978, which is before the July 1, 1980,date stated in the policy, such an analysis is not required. Commonwealth Edison Company (CECO) has, however, reviewed the NRC Staff's severe accident analysis, which included consideration of consequences of a liquid pathway release from a postulated core melt accident contained in the aforementioned DES, and offers the following comments thereon: The analysis of the consequences of severe accidents contained in the DES is based upon the updated Reactor Safety Study. CECO fully agrees with the NRC Staff's conclusions that the level of risk assoc-iated with operation of the Byron Station is very small and thus acceptable. However, CECO would point out that recent industry efforts to define and and quantify accident ricks demonstrate that the use of the Reactor Safety Study may well be some-what overly conservative. CECO therefore believes that it would be appropriate for the NRC Staff to recognize that the risks associated.with potential
-O.
accidents at the Byron Station are most likely even smaller than those identified in the DES. 0371.10-1 <}}