C/.-2 ■'/ Projected Annual Resource Requirements At the National and Regional Level For the Department of Commerce Energy Forecast 1985 & 2000 U.S. DEPARTMENT OF COMMERCE Office of Ocean, Resource and Scientific Policy Coordination Digitized by the Internet Archive in 2012 with funding from LYRASIS Members and Sloan Foundation http://archive.org/details/projectedannualrOObech I Its I s Projected Annual Resource Requirements At the National and Regional Level For the Department of Commerce Energy Forecast 1985 & 2000 Prepared by: Research and Engineering Bechtel National, Inc. San Francisco, Calif. 94119 (Under Contract #A06-A01-78-00-1321) For: U.S. DEPARTMENT OF COMMERCE Office of Ocean, Resource and Scientific Policy Coordination For sale by the Superintendent of Documents, U.S. Government Printing Office Washington, D.C. 20402 Stock No. 003-000-00548-8 FOREWORD This report presents an analysis of the national and regional resource requirements associated with future energy development in the United States as projected in the U.S. Department of Commerce forecast, Forecast of Likely U.S. Energy Supply /Demand Balances for 1985 and 2000 and Implica- tions for U.S. Energy Policy (20 January 1977, NTIS No. PB 266 240). This analysis, using Bechtel's Energy Supply Planning Model (ESPM) , was under- taken to assist the Department or Commerce in assessing the economic re- sources required to meet the energy needs of industry and commerce through the year 2000. It has been carried out as part of a program conducted by Bechtel for the U.S. Government aimed at identifying resource requirements, impacts, and potential constraints associated with various candidate energy policies. The Commerce energy forecast offers several advantages in making such an assessment. In the first place, it is carried out to the year 2000. Until recently, most forecasts have concentrated on 1985 and 1990 as target years. It provides detailed breakdowns of both fuel sources and consump- tion sectors, and it presents what is considered to be the "most likely" U.S. energy supply/demand balance for the years in question, i.e., single values rather than a menu of possible outcomes based on multiple scenarios. It is also of interest that the Commerce energy forecast is among the low- est among existing forecasts for these target years in terms of projected energy growth rates and consumption levels. U.S. energy consumption ex- pressed in quadrillion Btu's (quads) is projected to be 87 quads in 1985 and 116 quads in the year 2000. In addition, the Department of Commerce has issued a companion forecast which disaggregates the U.S. wide energy values contained in the national forecast among the individual states for the same two target years (Pre- liminary Forecast of Likely U.S. Energy Consumption/Production Balances for 1985 and 2000 by States, 1 November 1978, NTIS No. PB 287 486). Regional capital and other resource requirements were calculated accord- ing to the Bechtel ESPM regions using state energy production/consumption estimates provided in the Commerce state-by-state study. The analysis presented in this report was performed by Bechtel's Research and Engineering organization under DOC contract No. A06-A01-78-00-1321. Ms. Andrea L. Watson of Bechtel is the principal author of the report and had primary responsibility for applications of the Energy Supply in Planning Model, the analytical framework for the study. Mr. Ralph G.J. Zimmermann provided technical guidance in use of the ESPM and support in translating the DOC energy forecast into input formats compatible with the ESPM structure. Dr. J. Michael Gallagher was the Bechtel project manager responsible for client liaison and coordination. The program was executed under the overview of Mr. Harold E. Shaw, Bechtel 's Energy Systems Group Manager. Mr. A. Michael Maher and Mr. Joseph F. Gustaferro of the Department of Commerce (Office of Ocean, Resource, and Scientific Policy Coordination) provided technical guidance for the study and served as contracting officer's technical representatives throughout the project. ames W. Curlin eputy Assistant Secretary for Policy IV CONTENTS Section FOREWORD 1 SUMMARY 2 OVERVIEW OF THE MODEL AND DATA BASE The Model The Data Base 3 DESCRIPTION OF SCENARIO 4 FACILITY REQUIREMENTS Coal Production Oil and Gas Production Nuclear Fuel Cycle Other Technologies Electric Power Plants 5 RESOURCE REQUIREMENTS Capital Labor Materials and Equipment Natural Resources Operations and Maintenance Costs APPENDIX A - TABLES APPENDIX B - BRIEF DEFINITIONS OF THE 101 FACILITIES APPENDIX C - WATER CONSUMPTION REQUIREMENTS FOR ESPM ENERGY-RELATED FACILITIES Page iii 1-1 2-1 2-2 2-4 3-1 4-1 4-1 4-6 4-7 4-7 4-8 5-1 5-1 5-8 5-14 5-19 5-21 A-l B-l C-l FIGURES Figure Page 3-1 Model Regions 3-7 5-1 Projected Share of Cumulative Capital Requirements 5-3 5-2 Projected Annual Capital Requirements by Energy Sector 5-4 5-3 Projected Cumulative Capital Requirements by Region 5-6 5-4 Projected Annual Capital Requirements by Region 5-7 5-5 Projected Annual Labor Requirements for Energy-Related Facilities 5-10 5-6 Projected Labor Requirements by Region 5-13 5-7 Projected Annual Operations and Maintenance Costs by Region 5-28 vxi TABLES Table Page 3-1 Projected Energy Supply Requirements 3-3 3-2 Projected Fuel Requirements for Electricity 3-4 3-3 Projected Electric Generating Capacity (GWe) 3-5 4-1 Projected Schedule of Selected Energy Facility Additions 4-2 4-2 Projected Energy Facility Additions by Region 4-4 5-1 Total Construction Labor Requirements for the Design, Construction, and Startup of Energy-Related Facilities by Sector 5-11 5-2 Total Labor Requirements for the Operation and Maintenance of Energy-Related Facilities by Sector 5-12 5-3 Total Construction Labor Requirements for the Design, Construction, and Startup of Energy-Related Facilities by Skill 5-15 5-4 Total Labor Requirements for the Operation and Maintenance of Energy-Related Facilities by Skill 5-16 5-5 Selected Material and Equipment Item Requirements for the Design, Construction, and Startup of Energy-Related Facilities 5-17 5-6 Projected Requirements for Selected Material and Equipment Items by Region 5-20 5-7 Projected Land and Water Requirements by Region 5-22 5-8 Fixed Land Requirements for the Operation and Maintenance of Energy-Related Facilities 5-23 5-9 Incremental Land Requirements for the Operation and Maintenance of Energy-Related Facilities 5-24 5-10 Water Consumption Requirements for the Operation and Maintenance of Energy-Related Facilities 5-25 5-11 Annual Costs for the Operation and Maintenance of Energy-Related Facilities 5-27 IX APPENDIX A TABLES Table A-l Projected Energy Supply Requirements (in physical units) A-2 Capital Requirements (Million Dollars, January 1978) for the Design, Construction, and Startup of Energy-Related Facilities — Summary A- 3 Total Capital Costs (Million Dollars, January 1978) for the Design, Construction, and Startup of Energy-Related Facilities — Summary by Sector A-4 Total Capital Costs (Million Dollars, January 1978) for the Design, Construction, and Startup of Energy-Related Facilities — Annual Schedule by Sector A- 5 Total Capital Costs (Million Dollars, January 1978) for the Design, Construction, and Startup of Energy-Related Facilities — Summary by Region A-6 Total Capital Costs (Million Dollars, January 1978) for the Design, Construction, and Startup of Energy-Related Facilities — Annual Schedule by Region A- 7 Total Capital Costs (Million Dollars, January 1978) for the Design, Construction, and Startup of Energy-Related Facilities — By Region and Sector A-8 Total Construction Labor Requirements (Person-Years) for the Design, Construction, and Startup of Energy-Related Facilities — Annual Schedule A- 9 Total Construction Labor Requirements (Person-Years) for the Design, Construction, and Startup of Energy-Related Facilities — By Region A- 10 Total Labor Requirements (Person-Years) for the Operation and Maintenance of Energy-Related Facilities — Annual Schedule A-ll Total Labor Requirements (Person-Years) for the Operation and Maintenance of Energy-Related Facilities — By Region A-12 Labor Requirements (Person-Years) for the Design, Constructon, and Startup of Energy-Related Facilities — By Region and Skill XI Table A- 13 Labor Requirements (Person- Years) for the Operation arid Maintenance of Energy-Related Facilities — By Region and Skill A-14 Water Consumption Requirements for the Operation and Maintenance of Energy-Related Facilities — By Sector xn Section 1 SUMMARY This report describes the resource implications at the national and regional level for a "likely" energy supply and consumption forecast for 1985 and 2000 by the Department of Commerce. Total energy resource consumption is projected by Commerce to increase at an average annual rate of 1.8 percent for the 1977-2000 period. Electric energy consumption is projected to grow at 4.2 percent per year. U.S. energy consumption, expressed in quad- rillion Btu's (quads) is projected at 87 quads in 1985 and 116 quads in the year 2000. Projected energy supply and consumption levels from the Department of Commerce were simulated using the Energy Supply Planning Model, which calculated the direct resource requirements for capital, labor, materials and equipment, land and water, and operations and maintenance costs to construct, operate, and maintain energy-related facilities at the national and regional level. The Energy Supply Planning Model was developed by Bechtel for the National Science Foundation, the Energy Research and Devel- opment Administration, and the Department of Energy. Results of the analysis indicate projected cumulative capital requirements of 1.6 trillion January 1978 dollars during the 1977-2000 forecast period. The largest requirements by energy sector are for electric power generation facilities (53 percent), coal-fired power plants in particular. Total an- nual energy-related capital requirements are projected to grow at an aver- age rate of 2.6 percent per year during the forecast period, from an annual level of $50 billion in 1977 to about $87 billion by 2000. Capital require- ments grow at a higher rate than the projected rate of growth of primary energy consumption. However, capital requirements do not increase as fast as the assumed annual rate of 2.9 percent for overall economic growth. 1-1 Labor requirements increase at an even higher rate of 3.2 percent, with the largest increase, in relative terms, for manual skills, suggesting a move toward more labor-intensive forms of energy supply. One result shown by this study is that, although the country is projected to become more and more dependent upon Western energy resources, both capital and labor requirements are projected to move from Western to Eastern regions — in the year 2000. This reflects the projected decline in oil and gas production, coupled with the more rapid increase in electric energy consumption in the more heavily populated Eastern regions. Such a trend could have a favorable impact on the economic outlook of the industrialized regions in the Eastern United States. 1-2 Section 2 OVERVIEW OF THE MODEL AND DATA BASE The Energy Supply Planning Model (ESPM) incorporates an engineering approach to energy and resources planning. The model provides a system- atic means of calculating, based on any user-specified energy development strategy, the total resources required directly to build and operate the energy supply facilities needed to implement the strategy. The model is specifically designed for the analysis of energy scenarios at the na- tional and regional levels, whether they are generated by other models or as elements of national energy policy. With this tool, the feasibil- ity of various proposed energy supply and demand forecasts can be reviewed in terms of the capital, labor, materials and equipment, and construction time schedules required for the necessary energy supply system. To date, the modeling effort has involved an expenditure of approximately 50,000 staff-hours over the past 5 years. The model has been extensively docu- mented (see, for example, J. Michael Gallagher, et al., "Resource Require- ments, Impacts, and Potential Constraints Associated with Various Energy Futures," August 1978, NTIS No. PAE-3794-9). Among the many existing energy system models now in use in public policy analysis, the ESPM is unique in several important respects: • The data base consists of detailed engineering estimates developed by an engineering and construction organiza- tion and has become a standard of reference for other energy researchers. • The model is conceptually simple and easily adaptable to user specifications. No feedback loops or optimizing procedures are employed. 2-1 • The model user (not the model itself) specifies the energy development program to be evaluated. • The model provides an integrated assessment of detailed capital, labor, and other resource requirements for the entire energy supply system. • The model highlights the dynamics of energy transition strategies by calculating annual schedules for required facilities and resources. The model has been used as an energy policy analysis tool by numerous organizations, including the U.S. Department of Energy, the Electric Power Research Institute, the International Institute of Applied Systems Anal- ysis (IIASA) , the U.S. National Academies of Science and Engineering (Com- mittee on Nuclear and Alternative Energy Systems, CONAES) , the Workshop on Alternative Energy Strategies (WAES) , the World Energy Conference, and the World Coal Study, among others. THE MODEL Design of the model emphasizes three features: • Straightforward structure • User access to decision variables • Flexibility Although dimensionally quite large, the model is structurally straightfor- ward and, therefore, easily understandable. It proceeds from user-specified assumptions for major variables and explicit assumptions for other vari- ables, through a series of easily understood submodels to produce resource requirements results. This decomposition into submodels is intended to allow model users a step-by-step specification of decision variables and in so doing to permit testing the sensitivity of results to these variables. User access to policy and other variables is deliberately emphasized, so that model results represent information derived from user decisions rather 2-2 than from a decision-making capability within the model. In addi- tion, flexible exercise of the various user options is easily accommodated. For most user options, there is a capability to specify user considerations at various levels of detail, making the model suitable for use by energy policymakers and analysts alike. To allow this flexibility, reference (or default) specifications exist in the model and become operative only when the user chooses not to exercise his prerogative to specify variables at all levels of detail. An application of the model follows this procedure: • The user chooses a candidate energy scenario, for example, for the years 1980, 1985, 1990, and 2000. • The model then calculates, by year, the number of new energy supply facilities of various types that must be brought onstream and operated in order to meet the sce- nario specifications. • The model then locates the facilities in various regions of the country, allocates fuels supplied by the facili- ties to regional demands, and calculates transportation facility requirements for fuel flows among the regions. Regional location of energy facilities and demands may be specified by the user. • The annual schedules of capital, labor, materials, and equipment resources required for -each resulting energy and transportation facility (from initial commitment to plant startup and for operation and maintenance through- out their economic lives) , and for the energy supply system as a whole are then calculated. Resource require- ments are expressed without regard to their availability. Examples of questions for which the model can provide explicit answers include: • What energy supply and transportation facilities must be constructed to implement a candidate national energy development program? When would they need to be on line? Committed? 2-3 m What direct capital, labor, equipment and raw materials would be needed? When? Where? © What would be the regional requirements of a specific energy industry? (e.g., What will be the labor require- ments of the nuclear power industry in the Mid-Atlantic region in the year 2000?) • How different are the requirements of various energy programs? The model can help answer some other questions: 9 For which capital, labor, and material resource cate- gories are. future shortages likely to occur unless reme- dial actions are taken? 9 What is the total impact of the resource development strategy on other branches of the national economy? The model does not presume to answer such policy questions as: 9 What should be the national energy program? • What should be the national nuclear program? 9 What should be the national energy export program? Answers to these questions are believed to be appropriate issues for anal- ysis by energy policymakers and not within the calculational capabilities of mathematical models. THE DATA BASE A central feature of the Energy Supply Planning Model (ESPM) is its exten- sive engineering data base, which consists of those resources directly required to engineer, construct, start up, operate, and maintain energy supply and transportation facilities. Most of the data are based on in- house engineering estimates by the various divisions of the Bechtel Group of Companies, relying on past construction experience, literature surveys, 2-4 and industry contacts. Some of the original operations and maintenance estimates were subcontracted to Stanford Research Institute, but these have since been updated by Bechtel. This extensive technology data base is frequently used as a primary data source by other energy researchers. Currently, there are 101 "nominal" energy facilities in the ESPM data base. These facilities include extraction, processing, transportation, and port facilities and were selected to give a comprehensive coverage of the energy supply industry in the United States. The concept of a nominal facility was used to translate the 101 energy facilities into building blocks with certain energy technology and resource requirements characteristics. A nominal facility represents a "future average" facility in that its resource requirements are intended to be typical of requirements for a facility of that kind and size likely to be under construction through the year 2000. This definition implies that a nominal facility may not be identical to any existing or planned facility but can yield reasonably accurate results over a future time period. Estimates of resources required for construction of each of 101 ESPM facilities have been developed for approximately 100 categories of: • Capital • Labor • Materials and equipment (directly purchased) • Raw materials All capital costs are expressed in January 1978 dollars. These cost esti- mates were originally developed in 1974 dollars and have recently been escalated to reflect unit cost increases in the detailed production factors (e.g., staffing, materials, and equipment), without consideration of the 2-5 effects of facility design changes that may have occurred since the original estimates were made (such changes in scope are currently being studied for subsequent inclusion) . The material and equipment components of capital cost are summarized in two-digit Bureau of Economic Analysis accounts (e.g., primary iron and steel products, BEA 37) to allow direct use in econometric input-output models, that is, to determine the total impact of ESPM-derived results on other branches of the national economy. In addition to various capital cost categories, labor requirements have been estimated for the major engineering disciplines (e.g., mechanical, electrical), designers and draftsmen, supervisors and managers, and major manual skills (pipefitters, electricians, carpenters, etc.). To complement the categories of capital and labor requirements described above, estimates have been developed for quantities of selected major material and equipment items that must be directly purchased for energy construction projects. Examples of these items include draglines, oil country tubular goods, compressors, and boilers. Construction resources are expended at various rates during the construc- tion period. To account for this effect, time-phased data on the percent- age of the total resources that are required during each year of the construction project have been developed. Detailed annual requirements for the operation and maintenance of the 101 ESPM facilities have also been developed. Annual costs for labor, mate- rials, equipment, and utilities, as well as annual labor requirements by discipline, have been developed at a level of detail similar to that described above for construction resources. Operations and maintenance cost estimates do not include the costs of fuels for further processing or carrying charges (e.g., interest charges and depreciation). 2-6 Estimates of land and water requirements are also included. The amount of water is stated in terms of water consumption (i.e., not returned to a location where it could be reused) . Four types of land requirements are tabulated. Fixed land is required during the entire life of the facility (e.g., the land used for the location of a plant). Incremental land is used for only part of the lifetime of a facility (e.g., land that is to be strip mined and later reclaimed) . Right-of-way is land over or under which there is the right to pass vehicles and/or lay pipes or wires; the land may or may not have alternative uses. Underground lease requirements are related to onshore resource extraction facilities. It is important to note that all requirements refer to direct requirements for the construction and operation of facilities. "Ripple" effects through the economy on indirect physical labor and material requirements are not calculated. For example, the data base includes the (direct) engineering requirements for the design of a power plant but not the (indirect) engi- neering requirements associated with the design of manufactured equipment (piping, heat exchangers, etc.) used for the power plant. 2-7 Section 3 DESCRIPTION OF SCENARIO The Department of Commerce "most likely" energy supply and demand forecast is based upon an assessment of the likely impact of policy actions and socioeconomic trends as they affect energy use in the United States. The national forecast is contained in Forecast of Likely U.S. Energy Supply /Demand Balances for 1985 and 2000 and Implications for U.S. Energy Policy > January 1977. Major assumptions of the forecast were: 9 1.2 percent per capita rate of energy growth over the 1976-2000 forecast period reflecting the impact of higher energy prices, conservation, energy-saving technology, and the effects of per capita energy saturation ® 2.8 percent rate of GNP growth based on a 50-year historical trend ® 0.9 percent population growth rate based on the Bureau of the Census Series II projection Key features of the Commerce forecast were: » 1.8 percent growth rate in overall energy consumption during the forecast period e Oil consumption increases at a 0.6 percent rate through 1985, but decreases at a 2 percent rate from 1985 to 2000. Domestic oil production is projected to decline at a 1.3 percent rate during the forecast period. Oil imports are projected to remain as an important source, still account- ing for 47 percent of oil consumption in the year 2000. • Consumption and production of natural gas decline at national average rates of 0.4 percent and 0.9 percent, respectively. This pattern of decline is exhibited despite increases in production of gas from offshore fields. Imports are projected to account for more than 20 percent of gas consumption by the year 2000. 3-1 • Coal consumption increases steadily at a 4.3 percent growth rate. Annual production increases at a 2.4 percent rate in the East and 9.2 percent in the West. • Electric power consumption increases steadily at a 4.0 percent rate. This increase occurs across the country with most areas projected to more than double their capacity by the year 2000. Nuclear power is projected to increase its share of generating power from 9 percent in 1976 to 34 percent in 2000. Coal-fired power is projected to maintain its share of electric capacity at 47 percent. More than half of these plants are projected to use Western low-Btu coal by the year 2000. Most Department of Commerce energy consumption/production estimates were directly input to the Bechtel Energy Supply Planning Model (ESPM) . Some modifications were necessary, however, given the extent of detail encom- passed and the need to ensure consistency between the scenario specifica- tions and ESPM data base. Thus, small differences between the Commerce and ESPM estimates occur. Estimates of coal production from the Department of Commerce had to be converted from "nominal" to real tons to account for differing Btu contents of Eastern and Western coal. Though Eastern and Western coal production specifications from the scenario were adopted, surface and underground estimates were modified with the concurrence of the DOC project officer for this study. It was assumed that the peak shaving specification for electricity applied to gas turbines only. Pumped storage requirements were assumed to be included as part of the hydro specifications. Other assumptions were made as required to provide input specifications of the ESPM. For example, secondary and tertiary oil production levels and surface and underground uranium mine locations were calculated using default values from the ESPM which were based on technological trends. Projected energy consumption and production levels for this scenario, as adapted by the ESPM, are given in Tables 3-1 and 3-2. Projected capacity specifications for electric utilities are given in Table 3-3. No resource 3-2 Table 3-1 PROJECTED ENERGY SUPPLY REQUIREMENTS (In Quadrillion Btu's) % Fossil Fuels 1976 1985 2000 Annual Growth Rate Coal 15.24 20.53 42.91 4.31 Eastern 13.08 15.02 23.09 2.37 Underground 6.84 7.78 15.70 3.46 Surface 6.24 7.25 7.39 0.71 Western 2.16 5.51 19.83 9.24 Underground 0.29 0.41 0.89 4.67 Surface 1.87 5.10 18.94 9.65 Petroleum 35.31 37.37 27.66 -1.02 Lower 48 14.61 11.05 6.77 -3.21 Primary Recovery 10.58 7.03 3. 18 -5.01 Secondary Recovery 3.39 2.75 1.48 -3.45 Enhanced Recovery 0.64 1.27 2. 12 4.99 Offshore 2.75 4.23 2.54 -0.33 Alaskan 0.00 2.75 3. 18 — Shale 0.00 0.17 0.64 — Natural Gas Liquids 2.39 2.09 1.50 -1.94 Imports 15.56 17.07 13.04 -0.74 Crude 11.22 11.64 8.04 -1.39 Refined 4.34 5.42 4.99 0.58 Natural Gas 20.00 18.85 18.20 -0.39 Onshore 14.90 12.95 8.80 -2. 19 Offshore 4.10 4.50 4.20 0. 10 Alaskan 0.00 0.00 1.20 - Synthetic* 0.33 0.43 1.20 5.38 Imports 1.00 1.40 4.00 5.78 Uranium 1.99 7.91 20.31 9.68 Underground 0.79 3.16 12.19 11.40 Surface 1.16 4.27 7.31 7.67 Infports 0.03 0.47 0.81 13.73 Solar Insolation 0.00 0.17 1.50 29.82 Space Heating 0.00 0.17 1.35 29.38 Space Conditioning 0.00 0.00 0.15 — (Heating and Cooling) Hydro 3.08 3.30 4.11 1.27 Geothermal 0.03 0.14 1.36 18.99 Municipal Trash 0.00 0.03 1.03 - Other 0.05 0.18 1.37 13.79 Total Energy Resource Consumption 75.70 88.48 118.45 1.86 ^Includes 0.33 quads naphtha-derived fuels in 1976 and 1985 and 0.1 and 1.20 quads of coal-derived fuels in 1985 and 2000, respectively. These quantities are not added to natural gas resource estimates since the primary resource requirements are included in petroleum and coal resourc estimates, respectively. 3-3 Table 3-2 PROJECTED FUEL REQUIREMENTS FOR ELECTRICITY (In Quadrillion Btu's) Fuel 1976 1985 2000 % Annual Growth Rate Coal 10.34 13.96 29.69 4.49 High Btu 8.69 9.53 14.66 2.20 Low Btu 1.65 4.4J 15.03 9.64 Oil 3.40 3.79 0.00 — Gas 3.18 2.70 0.72 -5.99 Nuclear 1.99 7.91 20.31 10.17 Gas Turbine 0.50 0.48 0.48 -0.10 Hydro/Pumped Storage 3.08 3.30 4.11 1.20 Geo thermal 0.03 0.14 1.36 15.89 Municipal Trash 0.00 0.02 0.62 — Other (a) 0.05 0.18 1.37 13.79 Total 22.62 32.50 58.66 3.97 (a) Includes wind, solar, and other sour which resource requirements are not ces of electricity for calculated. 3-4 in o < »- ox X X. o iu •« o o o ■J* V a- o 0> — <£ • — 3 Ui Ui ui z -x. Ui ■_ Ui z- _! O O o _» . w r>. 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M -H3 C - «4l>3">>l-ki >1 ■h u.cii3-uoH*j«4ij=&H O *H 3dt-MU35^H <0 O U -H4IO0303c0-HC034ln-|03«JJx 4( ODSUUWcyiSU^JOlX.OcNnuir-.tijbJ o 3 u z U 4-5 25 percent in the East South Central (5) region. More than one-third of surface Eastern mines are projected to h« located in the East North Central (4) and East South Central (.5) regions, respectively. OIL AND GAS PRODUCTION Although the overall level of oil and gas production is projected to de- cline, a substantial amount of new oil and gas production capacity will be required to maintain the forecasted production levels. This capacity would be provided by: • 1,188 new onshore primary oil recovery facilities at 1,825 Mbpd o 2,059 new onshore secondary oil recovery facilities at 0.923 Mbpd • 876 new onshore enhanced oil recovery facilities at 3.51 Mbpd • 94 new offshore oil facilities at 20 Mbpd • 49 new North Alaskan oil recovery facilities at 54 Mbpd • 932 new onshore conventional gas recovery facilities at 30 MMcfd • 47 new offshore gas recovery facilities at 250 MMcfd • 11 new North Alaskan gas recovery facilities at 250 MMcfd New oil production capacity of 11.6 MMbpd will be required, with 19 per- cent from primary recovery, 16 percent from secondary recovery, 26 percent from tertiary recovery, 16 percent offshore, and 23 percent from the North Alaskan Slope; and 42.5 billion cfd of new gas production capacity will be required, with 66 percent from conventional recovery methods, 28 percent from offshore, and 6 percent from the North Alaskan Slope. These require- ments arise from a specified rate of decline of 1.4 percent in domestic oil production and 1.2 percent in domestic natural gas production during the forecast period. In addition, 3 new oil import facilities at 1 MMbpd and 5 new LNG import facilities at 2.8 billion cfd will be required. 4-6 Though declining in relative importance, the West South Central (7) region is projected to remain as the largest source of oil and gas production, adding about 30 percent of new primary oil, 70 percent of new secondary and tertiary oil, and 70 percent of new conventional gas recovery facili- ties. The second largest source of new oil production will be the Southern Pacific (11) region, which will add about 20 percent of new primary, 10 percent of new secondary, and 10 percent of new tertiary recovery facilities. The second largest gas producing region will be the Southern Mountain (9) region, where about 10 percent of new gas production facilities are projected to be built. Most offshore oil and gas production facilities are projected to be located in the Gulf Coastal (13) region, where 65 percent of new offshore oil facilities and 90 percent of new offshore gas facilities are projected to be built. NUCLEAR FUEL CYCLE The following uranium mines will be required: • 183 new underground uranium mines at 500 tpd ore • 29 new surface uranium mines at 1,200 tpd ore Thus, 126,300 tpd ore in new capacity will be required. Over 75 percent of new surface mines are projected to be located in the Northern Mountain (8) region and over 60 percent of new underground mines are projected to be built in the Southern Mountain (9) region. Processing the mined uranium will require 77 new uranium mills (at 1,000 tpd ore) and 16 new uranium conversion facilities sized at 10,000 tpy, as well as additional fabricating and enrichment capacity. OTHER TECHNOLOGIES Required facilities to produce energy by other methods include: • 2 new surface oil shale mines at 54 MMtpd • 3 new in-situ shale oil recovery facilities at 37 Mbpd 4-7 • 14 coal gasification facilities at 250 MMcfd • 13.5 million dwellings with solar space heating • 1.5 million dwellings with solar space conditioning (including heating and cooling) Oil shale development is projected to occur in the Southern Mountain (9) region. Coal gasification is projected to be located primarily in the West North Central (6) (over 35 percent) and the West South Central (7) (over 40 percent) regions. Solar space heating and conditioning installa- tions are projected to be built primarily in Southern regions: the South Atlantic (3), 20 percent of solar space heating and 35 percent of solar space conditioning; and the West South Central (7) and Southern Pacific (11) regions, 13 percent of solar space heating and 20 percent of solar space conditioning in each region. ELECTRIC POWER PLANTS The following electric power plants will be required: 300 new high-Btu coal-fired power plants at 800 MWe 334 new low-Btu coal-fired power plants at 800 MWe 225 new light-water reactors at 1,100 MWe 48 new dam and hydroelectric power projects at 200 MWe 99 new geothermal power complexes at 200 MWe Most coal-fired and nuclear power plant additions are projected to be located in the more industrial Eastern regions. Over one-third of low- Btu coal-fired power plants (90,400 MWe) are projected to be built in the East North Central (4) region. Thirty-seven percent of high-Btu coal-fired power plants (88,800 MWe) are projected to be located in the South Atlantic (13) region. Nuclear power plant projections are as follows: 18 percent 4-8 in the Mid-Atlantic (2) region (40,700 MWe) ; 18 percent in the East North Central (4) region (41,800 MWe); and 16 percent in the East South Central (5) region (29,700 MWe). Another 14 percent (35,200 MWe) are projected to be built in the Southern Pacific (11) region. The required number of facility additions calculated by the ESPM may vary from estimates made by the Department of Commerce due to differing assump- tions regarding typical facility size. For example, in the electric power sector, capacity specifications from the Commerce report were simulated. However, since ESPM nominal power plants represent typical sizes for each plant type, rather than being of a uniform size for all types, numbers of required plants differ from those projected in the Commerce report. In the case of solar installations, differing ESPM and Commerce assumptions regarding square feet of collector area and energy output per installation led to some uncertainty as to how best to simulate the Commerce forecast. A decision was made, in consultation with the Commerce project officer, to adopt the Commerce specification of the number of solar installations (15 million dwellings by the year 2000), of which 13.5 million dwellings are space heating only, and 1.5 million residences have space conditioning (heating and cooling) . Resource requirements have been calculated by the ESPM for this number of facilities. However, the Commerce report assumes that this number of solar installations will require about 16.5 billion square feet of solar collectors (1,100 square feet of collector per installation) , whereas the ESPM assumes that only 7.5 billion square feet (500 square feet of collector per dwelling) will be needed. Hence, the ESPM resource requirements could be signifi- cantly understated. On the other hand, one recent study suggests that 4-9 the collector area required may be even less. This report suggests that, on the average, 350 square feet of collector area for solar space heating instal- lations and 84 square feet for hot water installations would be required. It appears that the ESPM estimates of required collector area are in the middle of the range of Commerce and SERI estimates, which differ by a factor of four. Other assumptions significant to facility calculations concern facility lifetimes and retirements of existing capacity. In the case of oil and gas wells and Eastern coal mines, the time stream of facility additions is highly dependent upon the retirement assumptions made. Cumulative results through the year 2000 should not vary much, however, as most existing facilities are assumed to have been retired by that time. Energy transportation facility requirements have also been calculated by the ESPM. Transportation requirements are subject to more uncertainty than is the case for most energy facilities in that assumptions must be made regarding allocation of energy flows to competing transport modes and the interregional patterns over which energy flows will move. These regionally-dependent parameters strongly affect the resulting calculations. The Department of Commerce made specific assumptions concerning the con- struction of coal slurry pipelines which were directly adapted to the ESPM. Silvio J. Flaim, et al. , Economic Feasibility and Market Readiness of Eight Solar Technologies, Interim Draft Report, SERI-34, Golden, Colorado; Solar Energy Research Institute, June 1978, p. 121 4-10 Section 5 RESOURCE REQUIREMENTS Requirements for capital, labor (both for construction and operations), mate- rials and equipment, operations and maintenance costs, and other resources were calculated based on the facility schedules using the model's extensive data base. The results for each category will be discussed in this section. CAPITAL Cumulative capital costs for the energy industry, including both produc- tion and transportation facilities, are projected to amount to $1,620 billion during the 1977-2000 period. All dollar amounts are reported in January 1978 dollars and assume that no real escalation in construction costs will occur. The projected share of cumulative capital requirements for the energy and electric utility industries is presented in Figure 5-1. Cumulative capital requirements in billion January 1978 dollars, by energy sector, for the 1977 to 2000 period, are projected to be: Oil $245 Gas 195 Coal 104 Coal Synthetics and Oil Shale 25 Nuclear Fuel Cycle 27 Solar 176* Electricity Generation 62 3 - Coal 337 (Continued on next page) *The uncertainty in solar estimates is reiterated. All values shown refer to cne requirements for implementing 15 million solar installations, each having 500 square feet of collector area. 5-1 - Nuclear 214 - Other 72 Electricity Transmission and Distribution 225 Total $1,620 The time stream of capital requirements by energy industry sector is presented in Figure 5-2. Total capital requirements are projected to increase at an average annual rate of 2.4 percent from about $50 billion in 1977 to about $87 billion in 2000. Though the capital requirements for energy are projected to grow at a slower rate than the economy, they in- crease at a faster rate than energy consumption, suggesting a move toward more capital-intensive forms of energy supply. Thus, as can be seen from the figure, the largest increases in capital requirements occur for the electric utility industry, which grow at an average rate of 4.4 percent from about $13 billion in 1977 to over $38 billion in 2000. Most of this increase is related to the capital requirements for coal-fired utility plants, which increase five-fold from $5 billion in 1977 to $24 billion in 2000. This corresponds to an average annual rate of 9 percent in the 1977-1985 period and 7.6 percent in the 1985-2000 period. Annual expenditures for nuclear power plants increase from $6 billion in 1977 to about $11 billion in 1982, and then decline to about the $8-9 billion level during the rest of the period. Annual expenditures for coal mines increase steadily from about $3 billion in 1977 to about $7 billion in 2000. The second largest share of the capital market is projected to be expenditures for the solar industry, which increase from a relatively insignificant amount in 1977 to over $13 billion annually in the year 2000. In spite of projected decreases in domestic oil and gas production, $340 billion dollars will be required for this industry during the forecast period. Annual capital expenditures for oil and gas production decrease from $28 billion in 1977 to $12 billion in 2000, giving an average rate 5-2 — SYNTHETICS 1.4% NUCLEAR FUEL CYCLE 1 .6% BY ENERGY SECTOR COAL 40% OTHER 8.5% TRANSMISSION / \ NUCLEAR AND / \ 25% DISTRIBUTION / 26.5% / ELECTRIC UTILITY INDUSTRY Figure 5-1 PROJECTED SHARE OF CUMULATIVE CAPITAL REQUIREMENTS 5-3 90 SYNTHETICS AND OIL SHALE NUCLEAR FUEL ELECTRIC TRANSMISSION & DISTRIBUTION J 1977 1980 1985 1990 YEAR 1995 2000 Figure 5-2 PROJECTED ANNUAL CAPITAL REQUIREMENTS BY ENERGY SECTOR 5-4 of decline of 5 percent for oil and 1 percent for gas. However, the future expenditures may be understated since they do not account for potentially declining finding rates (quantity of oil or gas found per foot drilled) for primary oil and gas exploration. The calculations do account for the trend toward higher cost recovery techniques. This caveat also applies to future finding rates for other resources, i.e., coal and uranium. However, the impact on total calculated capital requirements by these resources is not as great. Capital requirements for petroleum refineries are projected to peak at $3 billion in 1979/1980 and decline to $1 billion by the year 2000, reflecting a decline in refinery throughput. This decline in volume may create adjust- ment problems for the industry. Potential changes in the quality of the crude oil input toward heavy and sour feedstocks may result in additional costs which are not accounted for by the model and which would have to be passed on to the consumer. The largest capital requirements are projected to occur in the South Atlantic (3), East North Central (4), and West South Central (7) regions, as can be seen in Figure 5-3. Cumulative capital requirements are pro- jected to exceed $200 billion in the South Atlantic and East North Central regions and $300 billion in the West South Central region. Figure 5-4 shows a shift in relative capital expenditures from the West to the East for the two years, 1977 and 2000. Though the West South Central region is projected to remain as the area requiring the largest capital expenditures for energy facilities, it diminishes in relative importance, due primarily to the decline in domestic oil and gas production in the area. However, it maintains its average level of expenditure throughout the forecasting period. The largest increases are projected to occur in the Mid-Atlantic (2), South Atlantic (3), and East North Central (4) regions. 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Figure 5-6 PROJECTED LABOR REQUIREMENTS (CONSTRUCTION AND OPERATIONS IN THOUSAND PERSON -YEARS BY REGION) 'DOES NOT INCLUDE LABOR REQUIREMENTS FOR OFFSHORE OPERATIONS Z CC LU O ft D O o < co a. 5-13 requirements for coal mining. Projected labor requirements for construction and operations and maintenance of the energy facilities by sector and region are presented in Appendix A. Projected labor requirements by skill are given in Tables 5-3 and 5-4. The largest percentage increases in technical labor requirements for construc- tion are for mining engineers, followed by requirements for civil, elec- trical, and mechanical engineers. The requirements for chemical and nuclear engineers decline in relative terms while requirements for geological and petroleum engineers are shown to decline in absolute terms. In the near and mid-term, labor requirements related to the oil industry are likely to be affected by decreasing finding rates for oil. However, domestic oil production projections are sufficiently low for these conclusions to be valid in the long term. The largest increases in manual labor requirements for construction are for pipefitters, electricians, boilermakers , and carpenters. The smallest increases occur for equipment operators. The largest percentage increases in requirements for technical personnel in operations are for nuclear and mining engineers . The demand for chemi- cal, civil, and mechanical engineers decline in relative terms, while requirements for petroleum engineers decline in absolute terms. The largest increases in manual labor requirements for operations occur for electricians, ironworkers, equipment operators, and linemen. A detailed summary of projected manpower requirements by skill is given in Appendix A. MATERIALS AND EQUIPMENT Projected materials and equipment requirements are summarized in Table 5-5. 5-14 » • mttt* • ■ O o I x « c oo» r>-3 o-<»oo»o(sa » » •*» u*i •* ^ampiam«a»(roiKn3r-Kiaoiii4)iMr>»K07C4 co o* ft (unj^ffiNo^nom^i^^v^a^^ni^io-o -. „.,» » jj son o •* x •« ►» 4iUU O >■ Z IU 1 iu> ac Z 19 nau -t CO «- o Z O uj Ul o o X «1 ■« tu • at CL CO UJ -a i a _i o uzu »- to ac •« at — . k* O 3 «_J Z C) z « >- UOUI s I ■-> «=ooo»ortj»i«»oo.©oo'co«j or*iP i »r*or»tp»o«nf»»raoo h c <© ^ 9 -t^^ixnoff -0 if>f\j-»t>f»c\i»vif»inf«» .ooKi9n« u>uuz u « UU X I KtZn z or 1 z _i SQ U)U)»IA -t UJ ui x «t UJ •< ac ac at x ■« X ouu^ CO CO to. _J U4UUJU ►— to <^uo 09 ac X UJ UIU4iluO ^* z »- •- ac uj X _l z z z z z !■» u. •* •» • uj ^ O ■* a *— w e— » ^ < UZJ c _1 ■« CO •— »-t I9UUO en ts ■« a •< -J UJ X «* 1- z z z z cc m z> z 3 UJ X UJ -J •— u UJ UJ UJ UJ UJ z z i CO JO -V (O a. 3 uj °a 40 •* <*. ■« s» ■v z x a: ac a «S -1 X _» z ac x _j x X ac -4 uj uj uj co •« »— «* X >— co • ■« » ni>u«xx 1: x ►- Cfl 3 CO 3 is ac tf> Z J3 i *- — < ■« X UJ z X' z z x •-• ui Z uj ►»0 Z Ot- •- «-< x x a •-uiz .u •« •« - X 0* a z t.LUIM»Clt3Z <3 X 3ulWH UJ 3 •H — _i a e • x ■*, a -m UJ *=* z tso. am z a a. uj as co »-» UUJ e— 5-15 cc • o « r» o tur~ft* >■ &■ a •> • o • •••>••••••••••• •...•a«». •...••.. i-sn • «* »■ OE •— X X » « ••••••••••••••••••••••••••••<>••• Cc CO «• — • - >• Ui • IS *• (2 a z a. 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UJO < Z9Y OOO/^VOo^ o»-* «o-«*zz_i:D_i»-ia:_j ujoom — v — /\ o >~ -Jt3 HZXMH Z(ZUiUi40U(A u>cr -™ — /% ^. 5- w 0.-J *o — * ^ -»- « it so ctaviocatoa. uj*-^*-* <040 aim ui< _ iw>.(04iii0o) ox s\ v to ti o v)^)^ z a ox . 1 _j ooa: j • vwh ^ to cr-^p-ac x>> «-*o _t •— lu p* (n MUiu. iu <0w«*z.Z(O£r,£.:>u.a:tx- UUi UJ m OO uiUitOUCCTUiiOfOtO^JX z.»-*o_j p-»— zu>z. i *o z uoozzx >> iiaa.uw!0(n-*< •— *- uj —i to »->->oac jO^ai *> * "i^jLii^iuuiuiiw *^ Zuiui _j »*ua;uij*-r-sczz► -«ia:ixt-r-»-wM**iii<a.aLOac^^xz2Zai? 5-17 The largest projected increases are for basic industrial materials: stain- less steel (3.5 percent annual average growth rate), copper (4.7 percent), aluminum (8.8 percent), nickel (3.9 percent), steel castings (3.6 percent), aluminum castings (3.7 percent), brass and bronze castings (3.7 percent), iron and steel forgings (3.3 percent), and steel plate (3.3 percent). Most of the projected increases in stainless steel, nickel, castings, forgings, and steel plate are related to the construction of coal-fired and nuclear power plants. Projected increases in copper and aluminum are related primarily to the construction of solar facilities, over 20 percent of the increase of copper and 66 percent that of aluminum. The uncertainty regarding the precision of the solar calculations should be kept in mind in using these figures, however. Another consideration is that the ESPM nominal facility assumes that solar collectors will be constructed pri- marily with aluminum. However, it is possible that copper may be exten- sively used. Regardless, the conclusion that solar energy developments will strongly affect energy-related materials demands remains valid. Large increases in equipment requirements also occur for power plant ■components: steam turbogenerators (4". 8 percent annual average growth rate), steam turbines (4.7 percent), non-nuclear pressure vessels 1.5-4 inch wall (19.6 percent), and boilers (6.7 percent). Declines in material and equipment usage are projected for carbon steel pipe (-1.4 percent), oil country tubular goods (-3.2 percent), carbon steel valves (-0.9 per- cent), onshore drill rigs (-3.1 percent), offshore drill rigs (-8.0 percent) drill bits (-3.6 percent), centrifugal compressors and drivers (-1.0 per- cent), non-nuclear pressure vessels <1. 5-inch wall (-2.6 percent). These decreases are related primarily to the decline in oil and gas production and distribution facilities. As stated previously, these estimates may be offset by the potential impact of lower finding rates for oil and gas in the future. Table 5-5 also shows iarge increases in requirements for high power axial compressors. These computed requirements arise exclusively from the assumed construction of diffusion-type uranium enrichment plants. If, as seems 5-18 likely, future enrichment plants use other than diffusion technology, e.g., centrifuge technology, axial flow compressors would not be required. Requirements for centrifuge-type plants have not been assessed. The regional distribution of requirements for selected material and equipment items is given in Table 5-6. NATURAL RESOURCES Land and water resource requirements were also calculated by the ESPM. As can be seen in Table 5-7, fixed land requirements increase at an annual rate of 0.4 percent, incremental land requirements increase at a rate of 3.4 percent, and water consumption requirements increase at a rate of 3.7 per- cent. Fixed land requirements remain relatively constant due to the decline in oil and gas production. Over 70 percent of fixed land requirements in the base year were for this industry. Fixed land requirements for the nuclear fuel cycle and electric utilities increase at 7.7 and 4.2 percent average growth rates, respectively, accounting for the small increase in overall requirements during the forecast period. Increases in incremental land are related primarily to surface coal mining, and increases in water consumption to coal and nuclear power plants. Projected land and water requirements by industry are given in Tables 5-8, 5-9, and 5-10. The ESPM nominal facility assumes that a wet cooling tower will be employed. Other power plant cooling methods are used, i.e., once-through cooling (either with or without storage) or dry cooling. Water consumption require- ments for these alternative methods vary from essentially zero for dry cooling to potentially more than double the level required for wet cooling for once-through with storage, which involves losses from evaporation. In water-short regions, it is likely that water conserving techniques will be used which would reduce the calculated requirements for water consumption. Projected water requirements by region are given in Appendix A. 5-19 s s; hJ < M Pi w H S 13 O Q H W O H w O Pi w ►J >H w ca w v£> en 1 rt S LO O w fa H 0) i-i rH W XI H H cd !3 22 H W W «*— 4 *!- i«ti u 0-, s H H ZD & C O" W H Pi n O <2 w H U w »-> o Pi Ph 5 23 5 2,2 1 22 S . I H * O ° ° O O O 8 ro «, _ ,7- -T CM CM »n „ m m c- O O O O f 0. — 5 '.'■. """ ^ "* * s s c - a CO w go *n CSJ ^ ao ^ J? m O O _ O m O m O r - 5 m s 2 " - « O ° ° c O ° ° O » cm O O c V ON c 3 m 2 rt ■* BO 5 5 O O O O O O O O O O O SUV 1: J " I 1 1 23 7 ■*" 7 m o\ ° - CO "* ■7 7 7 *7 '"" CM * 7 *? 7 7 u ^ C 3 U | 1 1 c O O n "-, w O " — 7 7 O "* "* 7 7 "j* 9 K ^ 0*. w n NO O en * Oi ^ ^ ^ O (SI P, g. 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Ui (Y U? O Ol U.-' O CO * o a: ^ _J /2 -a o »-t »-• a> •— l-CUJ *< _J -a .* -r co »— *< a m Htr w »— O/ Jul ix o _l •"♦ .U .» V UJ *- (l u. a 2 «i x H aj m o »- juift a t- ad o o o 5C _l >- a JL UJ »-« O 1 <_» >_> ■J! CO O •«t D ^r o o *-e o tx. •-« o ^ »-* CC l-> ►— _l «»iiu>- -J X m t~ Ul u> K- U) 3C -J _1 O UJ _1 X _) « ^ «- «n 4 a Ul 2- a -- ^. EC •-• -» »-t f— o u •-• to 1- «i o _i t— in tr a (X ■a _ 1 Ul o >- IT JUJ ►- u f ui ti. _t uj e ►- lO < a ci u> c/> a f-1 (r >-a j. UJ X »-t JT •-♦ ►- _j i'. ^ «a K-t ** _l _J liJl JO o in era in 3 Ui ir >- a 7- ^r 7 i o a: uj o o t i i _3 _l O »-«<-# . I l«J U a/> "at WK ir < ?. _i co D or rf l") a ■< »-* wal tt «-• ► m?i oo f- o 5-25 OPERATIONS AND MAINTENANCE COSTS Operations and maintenance costs were also calculated. These costs include labor, materials and equipment. They exclude carrying charges (e.g., depreciation, interest charges) and fuel costs. They are projected to increase at a 3.0 percent growth rate during the 1977-2000 forecast period, as can be seen in Table 5-11. Projected operations and main- tenance costs increase at a somewhat higher rate than projected capital costs. The largest percentage increases occur in the Northern Mountain (8) region (5.5 percent growth rate), followed by the Northeast (1) region (4.6 percent), South Atlantic (3) region (3.8 percent), and the Southern Mountain (9) region (3.9 percent), as can be seen in Figure 5-7. 5-26 MAnmvon«»iito«or(nnnioo'iio !Vi>inn«ni4innr-nKinninnivxi\ingi>iinnoninNrtnnix'>ninffn — • -* cr r- o o r~ o •*» m iiOr.JCMr3nJinaioooMoo(\r(MON^ooAi*w«'(yg(y o o o- or co - o cr ui r» er NruT«oin**Ki(u9iri k >na)(vooK)KioiD39Ctr'4?otn»«i/tfn^«iQ0'O9' oooooooooe-ooooooor-ooooooooooooooooooo oooooooooc-oooc^c^oor^crooooooooooooooooo© ooooooooooooooooo^cToooooooooooooooooo njf^rvrvinjn]fvrui>jiv(unin;n)f\jruiv**-4r\ti\ii>jntiv(vnfm(vninjrv(v(urvrunini 0=3 »-t m o- m oj c nj 3 cr to r\j r- oi/1ip*«oo4)s>^>9 =j fyruff Ktq «nj a -o r^ -© r- (V«r* D ~« m .-. -m ro. at •-• M*«Mxa(U3 ^>«i^aO([;in(u — 1 nj =9 »* »-• c\j »~ cr 10 cr o- 1 z — _ju» UJ to < 2 a « ■4 f o -J -> >- cj *- a. - a -.'J a z ui ■4 u> <■' >- _j ui •-• CO z l_> I3> u Z «r >- _l Z _i _i stl UJ K-» *- X. 3. z — IS to or Z Ui IE <_> UJ _i z ■4 U •-' -; :-• M-l i£ •— . ui z •« 9— z cj> Ui (V CO -c ^ c >f\IO(\>(OKlCMPO"HP *»*OtflolJIK»(\14ffnOIJl « Kl m i/l 1* r~. -0 r»- . 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HTGR = High temperature gas reactor LNG - Liquefied natural gas LWR = Light water reactor Metric ton = 1,000 kilograms = 2,205 pounds Miles are statute miles unless otherwise stated Pu = Plutonium Nautical mile = 1.1515 statute miles Tons are short tons, unless otherwise stated Th - Thorium U = Uranium UF,. = Uranium hexafluoride 6 U„0 o = Yellowcake Years life are estimated physical life of the plant (not necessarily amortized life) B-l FACILITIES El Onshore Primary Oil Recovery — Lower '48 365 operating days per year — 20 years Outputs: 1,825 barrels per day and 1,825 thousand cubic feet of gas per day. 100 producing and 75 dry holes, average depth 4,440 feet, gathering and production equipment. E2 Onshore Secondary Oil Recovery — Lower '48 365 operating days per year — 12 years Output: 913 barrels per day, no gas. 25 of 100 old wells worked over, 50 new holes drilled, 120 producers, 30 water injection, average depth 4,000 feet, gathering and produc- tion equipment. E3 Onshore Enhanced Oil Recovery — Lower '48 365 operating days per year — 6 years Output: 3,510 barrels per day, no gas. Workover of 30 of 60 old wells, 111 new drilled, 96 producers, 75 steam injection, average depth 2,500 feet, thermal recovery only, gathering and production equipment. E4 Offshore Oil Recovery — Lower '48 365 operating days per year — 20 years Outputs: 20,000 barrels per day and 20 million cubic feet gas per day 125 producing wells on five platforms, 95 dry holes, average depth 9,350 feet, one mile pipeline to shore. E5 North Alaskan Oil Recovery 365 operating days per year — 20 years Outputs: 54,000 barrels per day and 40.5 million cubic feet gas per day. 18 producing wells on three pads, two dry holes, average depth 9,900 feet, gathering and production equipment. 10.5 million cubic feet of the 40.5 million cubic foot gas output is used for pumping for the northern portion of the Alaskan Oil Pipeline. B-2 E6 High-Gasoline Refinery 345 operating days per year — 25 years Input: 200,000 barrels crude oil per operating day Outputs: 122,600 barrels gasoline per operating day 18,000 barrels kerosine per operating day 44,000 barrels diesel per operating day 10,000 barrels liquefied petroleum gas per operating day. Flexicoking, catalytic cracking, distillate hydrotreating, reforming, alkylation, and sulfur recovery. E7 Low-Gasoline Refinery 345 operating days per year — 25 years Input: 200,000 barrels crude oil per operating day Outputs: 78,800 barrels fuel oil per operating day 15,700 barrels naphtha per operating day 26,000 barrels reformate per operating day 51,800 barrels low-sulfur distillate per operating day. Flexicoking, distillate and gas oil hydrotreating, reforming, hydrogen production, and sulfur recovery. E8 Heavy Fuel Oil Gasification 330 operating days per year — 25 years Input: 57,800 barrels vacuum residuum (5.6% sulfur) per operating day. Output: 250 million cubic feet synthetic natural gas per operating day and 569 tons sulfur per operating day. Partial oxidation, shift conversion, Rectisol absorption, regenera- tion, methanation, oxygen plant, and sulfur recovery. E9 Naphtha Gasification 330 operating days per year — 25 years Inputs: 6.8 million pounds naphtha per operating day and 2.1 million pounds light liquids per operating day. Outputs: 174 million cubic feet of high-Btu gas per operating day. Sulfur removal (ZnO bed), steam reforming, CRG (catalyst rich gas) methanation, C0 ? removal (Benfield process). B-3 E10 Crude Oil Stockpile 365 operating days per year — 50 years Input: filled once with 50 million barrels. Output: none, 48 million barrels available. In five salt domes, 10 million barrels per dome, initial filling takes 360 days, can be withdrawn in 100 days, includes 100 miles of 32-inch oil pipeline and 100 miles of 24-inch water pipeline and related pump stations. Ell Alaskan Oil Export 350 operating days per year — 50 years Input: 2 million barrels per operating day- Output: 1.9985 million barrels per operating day. 32 fixed-roof- tanks each having 0.51 million barrels capacity, five berths for tankers up to 250,000 deadweight long tons, outflow capacity of 6 million barrels per day, gravity flow. El 2 Offshore Crude Oil Import 350 operating days per year — 50 years Input and Output: 1.7 million barrels per operating day. 12 floating-roof -tanks on shore, each having 1 million barrels capacity, three single-point moorings at 100 feet draft, two pipelines of 48-inch diameter and 12-miles length. El 3 Onshore Oil Import 350 operating days per year — 50 years Input and Output: 1.0 million barrels per operating day of crude oil or refined products. Marine terminal for two tankers up to 90,000 deadweight long tons, storage, and shore connection. E14 Surface Oil Shale Mine 300 operating days per year — 25 years Output: 54 million tons of shale per year having average of about 25 recoverable gallons per ton. Stripping ratio 2.1, seam thickness 300 feet, two pits, overland conveyor to stockpile, stockpile and disposal after retort; pro- duction stripping 5 million tons. B-4 E15 Underground Oil Shale Mine 365 operating days per year — 25 years Output: 54.75 million tons of shale per year having an average of about 25 gallons of shale oil recoverable per ton. Includes stockpile, preparation for retort, and disposal after retort. Room-and-pillar , 45-foot seam, 850 feet deep. Assumes 65% recovery of the target 45-foot seam. Includes two 16%, 580-foot declines; two 3,000-foot drives; haulage and conveyor ways; buildings, utilities, and mining equipment. E16 In-Situ Shale Oil Recovery 330 operating days per year — 25 years Outputs: 36,830 barrels of in-situ shale oil per operating day plus 33,000 tons per day of shale having an additional recover- able 13,690 barrels per operating day. Assumes 450-foot seam, 1,300 feet deep; cross-cuts, explosive fracturing to produce rubble; 5 miles of 4-inch (gas) , and 6-inch (shale oil) pipelines to storage and processing; 50-day buffer storage. El 7 Oil Shale Retorting and Upgrading 328 operating days per year — 25 years Input: 165,000' tons of oil shale per operating day Outputs: 88,000 barrels of upgraded shale oil per operating day and 320 tons of anhydrous ammonia per operating day Oil shale sizing, 25 Petrosix-type retorts, delayed coking, gas oil (1,600 psia) , and naphtha (700 psia) hydrotreating, gas pro- cessing plant, hydrogen plant, ammonia recovery (Claus and Well- man Lord units). E18 Shale Oil Upgrading 330 operating days per year — 25 years Inputs: 75,800 barrels of in-situ raw shale oil per operating day plus 67,900 tons of oil shale per operating day. Outputs: 90,000 barrels of upgraded shale oil per operating day. Includes shale sizing and disposal, 11 retorts. Raw oil upgrading: delayed < recovery, delayed coking, hydrotreating, hydrogen production; NH_ and sulfur B-5 El 9 Onshore Conventional Gas Recovery — Lover '48 365 operating days per year — 20 years Outputs: 30 million cubic feet per day and 500 barrels of conden- sate per day. 100 producing wells, 80 dry holes, average depth of 5,870 feet, gathering and production equipment. E20 Onshore Enhanced Gas Recovery — Lover '48 365 operating days per year — 25 years Output: 208.2 million cubic feet per day. 120 producing wells, 24 dry holes, average depth 10,000 feet, tight formation, massive hydro-fracturing, pay sands 100 feet thick, gathering and production equipment. E21 Offshore Gas Recovery — Lower '48 365 operating days per year — 20 years Outputs: 250 million cubic feet per day and 10,000 barrels of condensate per day. 125 producing wells, 95 dry holes, average depth 10,700 feet, wells are on five platforms in 200 feet of water, pipeline to shore. E22 North Alaskan Gas Recovery 365 operating days per year — 20 years Outputs: 250 million cubic feet per day and 10,700 barrels of condensate per day. 24 producing wells, 2 dry holes, average depth 9,900 feet, gather- ing and production facilities- E23 Coal Mine Degasif ication 365 operating days per year — 30 years Output: 1 million cubic feet per day of pipeline quality gas (methane at about 900 Btu per cubic foot) 30 boreholes, 1,000 feet deep, includes collection, compression, and metering station; gas is withdrawn before mining begins. B-6 E24 Alaskan LNG Export 345 operating days per year — 50 years Input: 3,375 million cubic feet per operating day. Output: liquefied equivalent of 3,030 million cubic feet of gas per operating day. Four 550-thousand-barrel storage tanks, two ship berths of 50-foot draft. LNG plant with eight trains (treating, dehydration, cascade liquefaction) . E25 LNG Import 345 operating days per year — 50 years Input: liquefied equivalent of 2,809 million cubic feet of gas per day, Output: 2,795 million cubic feet per day. Two unloading docks with 48-foot draft, storage capacity of 2,200 barrels of LNG, 38-mile, 48-inch-diameter pipe to transmission system. E26 Natural Gas Stockpile 365 operating days per year — 50 years Input: filled once with 66,000 million cubic feet. Output: none, 60,000 million cubic feet available. 50 wells drilled in depleted field, withdrawal would require 100 days, and reinjection of 62,000 million cubic feet would require 200 days, scrubbing and dehydration included, 30 miles of 30-inch connecting pipe E27 Underground Eastern Coal Mine 253 operating days per year — 20 years Output: 2 million tons per year. Preparation included, room-and-pillar , one 24-foot-diameter concrete shaft, one 17 14 x 14 x 2,900 foot stope; mining, onsite transporta- tion, and preparation equipment; assumes 5-foot seam E28 Surface Eastern Coal Mine 253 operating days per year — 20 years Output: 4 million tons per year. Assumes level 6-foot seam, stripping ratio 16:1, 90% recovery; includes initial stripping for two weeks' production, mining, onsite transportation, and processing equipment, preparation included. B-7 E29 Surface Western Coal Mine 253 operating days per year — 20 years Output: 6 million tons per year. Assumes level terrain, 30-foot seam, 2.1:1 stripping ratio, 90% recovery; includes initial stripping for two weeks' production, mining, onsite transportation, and processing equipment, prepara- tion included. E30 Underground Western Coal Mine 253 operating days per year — 20 years Output: 2 million tons per year. Preparation included, room-and-pillar , one 24-foot-diameter concrete shaft, one 17° x 14 x 14 x 2,900 foot stope; mining, onsite trans- portation, and preparation equipment; assumes 5-foot seam. E31 Coal Gasification — High-Btu Gas 330 operating days per year — 25 years Input: 27,500 tons of Western lignite (8,300 Btu per pound) per operating day. Outputs: 250 million cubic feet of high heating value (about 980 Btu per cubic foot) gas per operating day, 1,475 tons of tar, tar oil, and naphtha per operating day, 905 tons of phenol and ammonia per operating day. The thermal efficiency for gas alone is about 53.6%, including by- products it is about 65.5%. Lurgi oxygen gasification, shift con- version, methanation, oxygen plant, sulfur recovery. E32 Coal Gasification — Low-and Medium-Btu Gas 330 operating days per year — 25 years Input: 27,500 tons of Western lignite, (8,300 Btu per pound) per operating day. Outputs: 1,440 million cubic feet of low-Btu (about 196 Btu per cubic foot) gas per operating day 1,645 tons of tar, tar oil, and naphtha per operating day 960 tons of phenols and ammonia per operating day. The thermal efficiency for gas alone is about 60.4%, including byproducts it is about 75.8%. Lurgi air-blown system, gas treatment, Claus, Wellman-Lord sulfur recovery. B-8 E33 Coal Gasification — Methanol 330 operating days per year — 25 years Input: 37,985 tons of Illinois 4.4% sulfur coal per operating day (10,200 Btu per pound). Output: 15,073 tons of fuel grade methanol per operating day (9,782 Btu per pound gives daily output of slightly more than in 250 million cubic feet of natural gas). The thermal efficiency is about 38.1%. Koppers-Totzek oxygen-blown gasification, Imperial Chemical Industries methanol synthesis. E34 Coal Liquefaction — Heavy Fuel Oil 330 operating days per year — 25 years Input: 10,000 tons of Kentucky 5.4% sulfur (11,000 Btu per pound) coal per operating day. Outputs: 4,330 tons (23,710 barrels) of 0.2% sulfur fuel oil per operating day 87 tons of ammonia per operating day 505 tons of sulfur per operating day* The thermal efficiency excluding the ammonia is about 70.7% including the ammonia about 71.5%. Synthoil catalysis coal liquefaction process. E35 Coal Solvent Refining 330 operating days per year — 25 years Input: 10,000 tons of coal (12,800 Btu per pound) per operating day. Outputs: 4,560 tons of solvent refined coal (about 16,600 Btu per pound) .per operating day 2,010 barrels of naphtha per operating day 36 million cubic feet of low-Btu (about 636 Btu per cubic foot) fuel gas per operating day 306 tons of sulfur per operating day. The thermal efficiency for coal alone is about 59.0%, including byproducts it is about 72.0% Noncatalytic dissolver, aminal gas purification, Claus, Wellman-Lord sulfur recovery. E36 Coal Liquids Refinery 345 operating days per year — 25 years Input: 100,000 barrels of 0.2% sulfur fuel oil per operating day from coal liquefaction plant- Outputs: gasoline at about 61% of feed, other refined products at 36% of feed. Overall thermal efficiency is about 90.1%. Includes flexicoking, catalytic cracking, hydrotreating, reforming, alkylation, and sulfur recovery. B-9 E37 Surface Uranium Mine 253 operating days per year — 20 years Output: 1,200 short tons of 0.2% U~0 ft ore per operating day. Run-of-mine ore is piled for pickup. Assumes level terrain; stripping ratio 20 cubic yards/ton ore, small ore body, 80% recovery; includes exploratory survey, drilling, access roads; preproduction stripping (5 x 10" cubic yards); diesel power plant, buildings, and mining equipment E38 Underground Uranium Mine 253 operating days per year — 20 years Output: 500 short tons of 0.2% U-0 ft per ore per operating day Run-of-mine ore is piled for pickup. Includes exploratory survey, drilling, access roads; 16 x 500 foot shaft; 8 x 10 foot x 2,000 foot drifting; 8 x 10 x 2,000 foot crosscutting; 6 x 8 x 400 foot stope raises; buildings, power, and mining equipment; assumes "erratic" ore body, 80% recovery. E39 Uranium Mill 330 operating days per year — 30 years Inputs: 330,000 tons of 0.2% U o o ore per year. J o Outputs: 880 tons of 75% U o o (yellowcake) per year. Aoid leach process E40 Uranium Conversion 360 operating days per year — 15 years Inputs: 10,000 tons of 75% UoO fi (yellowcake) per year, plus hydrogen fluoride and nitric acid* Output: 10,000 tons of UF, (uranium hexaf luoride) per year. b Acid dissolution, solvent extraction, calcination, hydrof luorination, and fluorination, product purification. E41 Uranium Enrichment — Diffusion 365 operating days per year — 25 years Input: 15,850 metric tons of uranium per year as 0.71% U-235 in UF,. Outputs: 2,300 metric tons of uranium per year as 3.2% of U-235 in UFg plus tails of 13,550 metric tons of uranium per year as 0.29% U-235 in UF 6 - This amounts to 8.75 million separative work units per year. Gaseous diffusion process. B-10 E42 LWR Fuel Fabrication — No Pu Recycle 300 operating days per year — 15 years Input: 600 metric tons of uranium per year, contained in 900 metric tons of UF^ (uranium hexaf luoride) ; cold chemicals. Outputs: 600 metric tons of uranium per year in U02 pellets in PWR and BWR fuel bundles; also HF and wastes. Oxidation of UF5 to UO2, pelletizing, loading pellets into pins, and assembly into fuel elements. E43 LWR Fuel Fabrication — Pu Recycle 300 operating days per year — 15 years Inputs: 150 metric tons of heavy metals (uranium and plutonium) per year contained in 1973 metric tons of UO3 and 6.43 metric tons of Pu02 • Outputs: 150 metric tons of heavy metals per year in reactor fuel bundles, HF and wastes. Oxidation of U and Pu compounds to oxides; pelletizing, loading into pins, fuel bundle assembly; includes glove-box handling of Pu. E44 HTGR Fue l Fabrication 300 operating days per year — 15 years Inputs: 432 metric tons of thorium per year in 850 metric tons of Th (N03)4 and 16 metric tons of uranium per year in 42 metric tons of enriched UF5; also cold chemicals- Outputs: 448 metric tons of heavy metals per year in 24,000 fuel elements. Fertile particle production by Solgel process; includes calcination, coating, blending; preparation of fuel rods, loading into graphite fuel elements; heat conditioning. E45 FBR Fuel Fabrication 300 operating days per year — 15 years Inputs: 290 metric tons of uranium per year in 390 metric tons of UF6 (yellowcake) and 25 metric tons of plutonium per year in 30 metric tons of PUO2; also cold chemicals. Outputs: 315 metric tons of heavy metals (uranium and plutonium) per year in fuel bundles. Conversion of yellowcake to UO2 pellets; formation of Pu02 pellets, pellet blending, loading into pins, fuel bundle assembly; glove-box handling of Pu. B-ll E46 LWR Spent Fuel Reprocessing 2 10 operating days per year — 15 years Inputs: depleted fuel bundles from original reactor charges totaling 1,500 metric tons of heavy metals (uranium and plutonium) per year; also cold chemicals. Outputs: 1,380 metric tons of uranium per year. in UF^ and 36 metric tons of plutonium per year in Pu02i also 80 metric tons per year of calcined fission products; other wastes. Cladding removal, Purex separation, "disaster-proof" processing building; solidified waste. E47 HTGR Spent Fuel Reprocessing 300 operating days per year — 15 years 3.nput: 300 metric tons per year of heavy metals (uranium and thorium) in irradiated fuel elements; also cold chemicals- Outputs: 283 metric tons of thorium per year in aequeous nitrate 11 metric tons of uranium per year in U-233 aequeous nitrate, 6 metric tons per year of heavy metals in calcined fission products. Controlled burning, acid leach, solvent extraction E48 FBR Spent Fuel Reprocessing .'00 operating days per year — 15 years Input: 950 metric tons of heavy metals, (uranium and plutonium) in the form of irradiated fuel elements; also cold chemicals. Outputs: 800 metric tons of uranium per year in UO2 90 metric tons of plutonium per year in Pu02 60 tons per year of heavy metals in calcined fission products and other radioactive wastes. lladding removal; Purex separation, U and Pu to oxides, "disaster- oroof" processing building, waste storage. E49 High-Level Waste Disposal In 250 handling days per year this facility accepts 3,100 canisters per year of calcined fission products, plus other waste equal to ibout 500 metric tons per year. At this rate, its capacity would be reached in about 40 years. Canisters sealed in 2-inch casks, stored in outdoor concrete cylinders Surface retrievable storage facility concept. B-12 E50 Solid Waste Collection/Separation Plant 250 operating days per year — 30 years Input: 500 tons of municipal solid waste per operating day. Outputs: 335 tons of combustible solid waste per operating day. 165 tons of noncombustibles and higher valued combustibles. Includes dumping floor, air classification, magnetic metals separa- tion, screening. E51 Oil-Fired Power Plant 365 days per year — 30 years Rated at 800 megawatts Input: Heat rate is 9,375 Btu per kilowatt hour, which is a thermal efficiency of 0.3456. At a nominal 55% of full load and using only fuel oil at 6.3 million Btu per barrel, the annual oil input would be 6.04 million barrels. Output: at nominal 55% of full load is 3.854 billion kilowatt- hours per year . Uses fuel oil; natural gas is an alternative and light oil an emergency alternative. E52 Reconversion of Oil Power Plant to Coal 365 days per year — Conversion happens once, plant operates to end of its original life which is 30 years or less Rated at 250 megawatts Input: Heat rate is 9,875 Btu per kilowatt-hour, which is a thermal efficiency of 0.3456. At a nominal 60% of full load and using high-Btu coal of 12,000 Btu per pound the annual coal input would be 0.541 million tons. If low-Btu coal of 8,500 Btu per pound were used then the annual input would be 0.763 million tons. Output: At nominal 60% of full load is 1.314 billion kilowatt-hours per year. Plant originally designed to burn coal and was converted to oil and reconverted to coal. B-13 E53 Coal-Fired Power Plant — Low-Btu Coal 365 days per year — 30 years Rated at 800 megawatts Input: Heat rate is 9,875 Btu per kilowatt-hour, which is a thermal efficiency of 0.3456. At a nominal 60% of full load and using low-Btu coal of 8,500 Btu per pound the annual input would be 2.442 million tons. Output: at nominal 60% of full load is 4.205 billion kilowatt-hours per year. Burns low-Btu coal. Has natural draft cooling tower (s). E54 Coal/Waste Power Plant - High-Btu Coal 365 days per year — 30 years Rated at 800 megawatts Input: Heat rate is 9,875 Btu per kilowatt-hour, which is a thermal efficiency of 0.3456. At a nominal 60% of full load and using only high-Btu coal of 12,000 Btu per pound the annual input would be 1.730 million tons. Output: at nominal 60% of full load is 4.205 billion kilowatt-hours per year. Burns high-Btu coal or solvent refined coal. Has natural draft cooling tower(s). E55 Coal/Waste Power Plant — Low-Btu Coal 365 days per year — 30 years Rated at 350 megawatts Input: 10% of the Btu input is from municipal waste. Heat rate is 9,875 Btu per kilowatt-hour, which is a thermal efficiency of 0.3456. At a nominal 60% of full load the annual inputs would be 0.151 million tons of separated combustible municipal waste (at 6,000 Btu per pound) and 0.962 million tons of low- Btu coal (at 8,500 Btu per pound). Output: at nominal 60% of full load is 1.840 billion kilowatt-hours per ye?r Has natural draft cooling tower(s). B-14 E56 Coal/Waste Power Plant - High-Btu Coal 365 days per year — 30 years Rated at 350 megawatts Input: 10% of the Btu input is from municipal waste. Heat rate is 9,875 Btu per kilowatt hour, which is a thermal efficiency of 0.3456. At a nominal 60% of full load the annual inputs would be 0.151 million tons of separated combustible municipal waste (at 6,000 Btu per pound) ana 0.681 million tons of high- Btu coal (at 12,000 Btu per pound). Output: at nominal 60% of full load is 1.840 billion kilowatt-hours per year. Has natural draft cooling tower (s). E57 Sulfur Oxide Removal 365 days per year — 30 years Removes 80% of sulfur from stack gas of 800 megawatt power plant fired with 3.5% sulfur coal, operating at a nominal 60% of full load. Reduces plant efficiency 7-1/2%. Uses Wellman-Lord process. Produces sulfur as a byproduct. E58 Low/Intermediate-Btu Gas-Fired Power Plant 365 days per year — 30 years Rates at 800 megawatts Input: Heat rate is 9,875 Btu per kilowatt-hour, which is a thermal efficiency of 0.3456. At a nominal 55% of full load the input would be either 76.12 billion cubic foot of intermediate-Btu gas (at 500 Btu per cubic foot) or 190.31 billion cubic foot of low-Btu gas (at 200 Btu per cubic foot)- Output: at nominal 55% of full load is 3.854 billion kilowatt-hours per year. Can burn light oil as an emergency alternative. E59 High-Btu Gas-Fired Power Plant 365 days per year — 30 years Rated at 800 megawatts Input: Heat rate is 9,875 Btu per kilowatt-hour, which is a thermal efficiency of 0.3456. At a nominal 55% of full load and using gas of 1,025 Btu per cubic foot the annual input would be 37.13 billion cubic feet. Output: at nominal 55% of full load is 3.854 billion kilowatt-hours per year . Can burn light oil as an emergency alternative. Has natural draft cooling tower(s). B-15 E60 Conversion of Gas Plant to Coal 365 days per year — Conversion happens once, plant operates to end of its original life, which is 30 years or less Rated at 250 megawatts Input: Heat rate is 9,875 per kilowatt-hour, which is a thermal efficiency of 0.3456. At a nominal 60% of full load and using high-Btu coal of 12,000 Btu per pound the annual coal input would be 0.541 million tons. If low Btu coal of 8,500 Btu per pound were used then the annual input would be 0.763 million tons. Output: at nominal 60% of full load is 1.314 billion kilowatt-hours per year. E61 Combined Cycle Power Plant 365 days per year — 30 years Rated at 400 megawatts Inputs: Heat rate is 8,530 Btu per kilowatt-hour, which is a thermal efficiency of 0.4000. At a nominal 55% of full load and using only high Btu gas (at 1,025 Btu per cubic foot) the annual input would be 16.04 billion cubic feet. Output: at nominal 55% of full load is 1.927 billion kilowatt-hours per year. Has 240-megawatt gas turbine and 160-megawatt steam turbine. Uses natural gas, but can use light oil as an alternate, Has natural draft cooling tower(s). E62 Gas Turbine Power Plant Available 365 days per year for 30 years, but is operated only at peak periods. Rated at 133 megawatts. Input: Heat rate is 11,000 Btu per kilowatt-hour which is a thermal efficiency of 0.3103. At a nominal 10% of full load and using only high-Btu gas (at. 1,020 Btu per cubic foot the annual input would be 1.25 billion cubic feet). Output: at nominal 10% of full load is 0.1165 billion kilowatt-hours per year. Uses natural gas but can use light oil as an alternate. B-16 E63 Fuel Cells Available 365 days per year for 30 years but operated only at peak periods, amounting to 2,000 hours per year. Inputs: 41 barrels of No. 2 fuel oil per operating hour, or 242 thousand cubic feet of natural gas or methane per operating hour, or 44 barrels of naphtha per operating hour. Outputs: In 2,000 hours of operation per year this output is 0.052 billion kilowatt-hours- Included are cells, fuel reformer, dc-ac inverter, transformer, switchgear, controls, and telemetry for remote control. E64 Light Water Reactor Power Plant 365 days per year — 30 years Rated at 1,100 megawatts. Output: at nominal 71% of full load is 6.842 billion kilowatt- hours per year. Has natural draft cooling tower(s). E65 High-Temperature Gas Reactor Power Plant 365 days per year — 30 years Rated at 1,500 megawatts. Output: at nominal 71% of full load is 9.329 billion kilowatt- hours per year. Has natural draft cooling tower(s). E66 Liquid Metal Fast Breeder Reactor Power Plant 365 days per year — 30 years Rated at 1,000 megawatts- Output: at nominal 71% of full load is 6.220 billion kilowatt- hours per year. Has natural draft cooling tower(s). E67 Dam and Hydroelectric Power Plant 365 days per year — 60 years Rated at 200 megawatts (three 66-2/3 megawatt generating units) Has earthfill dam of 15 million cubic yards. Output: at nominal 56% of full load is 0.981 billion kilowatt- hours per year. B-17 E68 Pumped Storage 365 days per year — 60 years Rated at 1,000 megawatts. Pumped storage facilities, overall, consume more power than they produce. Viewed by the electricity demand; however, they produce power at the peak time when it is needed. In that respect, the output of this facility at a nominal 13% of full time is 1.139 billion kilowatt-hours per year. This facility has two earthfilled dams and four 250-megawatt combination generating and pumping units. E69 Geothermal Power Complex 341 days per year — 30 years Power plant rated at 200 megawatts, flash steam cycle. Output: at 75% of full capacity, is 1.314 billion kilowatt-hours. Includes gathering system and 20% dry holes. Vapor-dominated (e.g., Geysers) geothermal system. E70 Solar Space Heating 200 heating days per year — 30 years 30,000 1,600-square-foot dwellings in climate equivalent to Washington, D.C., each with 500 square feet of collector. Input: 4.3 trillion Btu per heating season. Output: 2.1 trillion Btu per heating season. Installations are in new construction in batches of 150. 1,000- gallon tank and auxiliary boiler included. Collectors, frames and structures are of aluminum. E71 Solar Space Conditioning 200 heating and 100 cooling days per year — 30 years 30,000 1,600-square-foot dwellings in climate equivalent to Washington, D.C., each with 500 square feet of collector. Inputs: 4.3 trillion Btu per heating season 4.1 trillion Btu per cooling season- Outputs: 2.1 trillion Btu per heating season 0.8 trillion Btu per cooling season. Installations are in new construction in batches of 150. Solat supplies 70% of energy requirement. 1,000 gallon tank, auxiliary boiler, and 3-ton lithium bromide absorption chiller included. Collectors, frames, and structures are of aluminum. B-18 E72 Geopressured Gas Recovery 365 operating days per year — 12 years Input: 700,000 barrels per day of saline water containing methane and other chemicals. Outputs: 50 million cubic feet of natural gas per day. Can, but need not, produce 700,000 barrels per day of fresh water at 215°F. 100 producing wells and 76 dry holes averaging 15,000 feet depth, some onshore, some offshore. Characteristics of geological forma- tion are assumed, not known. Transfers excess heat to imported fresh water. Transfers saline water to adjacent depleted oil field. Includes exploratory and production drilling, gathering and disposal systems and surge tankages for fresh and saline water. Excludes off- site pipe for input and output of fresh water. E7 3 Coal Solvent Refining — SRC II 330 operating days per year — 25 years Input: 34,000 tons of Illinois Basin Coal per operating day. Outputs: 57,390 barrels of fuel oil per operating day 6 million cubic feet of gas per operating day 8,222 barrels of liquefied petroleum gas (LPG) per operating day 15,000 barrels of light distillate per operating day 66.7 tons of ammonia per operating day 990 tons of sulfur per operating day- Fuel oil produced is liquid at atmospheric conditions, burnable in most oil fired boilers. Thermal efficiency of the plant including byproducts is 0.62. For fuel oil only the thermal effi- ciency is 0.45. E74 Fluidized Bed (Atmospheric) Power Plant 365 operating days per year — 30 years Rated at 800 megawatts, available about 1990. Inputs: Any coal, most useful with high sulfur coal, limestone or dolomite at about one third of coal tonnage. Outputs: At nominal 65% of full load is 4.555 billion kilowatt-hours per year Slag (coal ash and calcium sulfate) at about 35% of input coal tonnage. Stack gas cleaned with cyclones and electrostatic precipitators. Slag disposed of locally as land fill. Has natural draft cooling tower(s). B-19 Tl Crude Oil Pipeline — Lower '48 360 operating days per year — 40 years 150 miles, 36-inch diameter Input: 800,000 barrels per operating day. Output: 800,000 barrels per operating day. Pump horsepower is 270 per mile, of which 26% is spare. For lesser mileages, resources should not be scaled downward proportionately, but may be scaled upward (to at most about 1,500 miles) proportional to mileage. T2 Alaskan Oil Pipeline 350 operating days per year — 40 years 800 miles, 48-inch diameter Input: 2,050,000 thousand barrels per operating day. Output: 2,000,000 barrels per operating day. Total pumping horsepower is 650,000, of which about 23% is spare. Some pumps fueled by associated gas, some by processed crude taken from the pipeline. T3 Oil Tanker 90,000-deadweight-long-ton ship with 24,500 shaft horsepower power plant. Capacity is 620,000 barrels. After consideration of veloc- ity, turnaround time, drydock time, and typical transit distance for crude and refined products imported to the U.S., the tanker is rated at 25,550 million barrel-statute miles per year (22,188 million barrel-nautical miles). It is expected to have a 25-year life. T4 Oil Barge Five barges, each having a capacity of 18,000 barrels, total capacity 90,000 barrels, plus a 3 ,000-horsepower towboat. After consideration of velocity, turnaround time, drydock time, and typical oil transit distances in U.S. inland waterways, this barge combination is rated at 1 ,424-million-barrel-miles per year. It is expected to have a 30-year life. T5 Oil Tank Truck The tractor-trailer rig has a 300-horsepower tractor; trailer has aluminum tank with capacity of 9,500 gallons. After consideration of typical routings, hours per week, and maintenance times, the oil truck is rated at 2.825 million barrel-miles per year. It is expected to have a 7-year life. B-20 T6 Products Pipeline 345 operating days per year — 40 years 100 miles, 12-inch-diameter , two pump stations Input and Output: 70,000 barrels of refined products per operating day. T7 Hot Oil Pipeline 360 operating days per year — 40 years 50 miles, 12-inch diameter, insulated, two heating stations Input: 40,000 barrels of heavy fuel oil per operating day. Output: 39,000 barrels of heavy oil per operating day. T8 Refined Products Bulk Station 345 days per year receiving from pipeline 250 days per year loading trucks, expected 30-year life Input: 50,000 barrels on each of 345 days per year. Output: 69,000 barrels on each of 250 days per year. 500,000-barrel storage capacity, manifolds, loading pumps, 12 double-loading racks, metering, and controls. T9 Rail Line 40 new miles of single track — expected life 40 years Includes signals, communications, structures, wooden ties, grading, ballast, 119-pound per yard rail. This facility is new heavy duty line, not rehabilitation of existing track. T10 Mixed Train This train is a composite of those coal cars that are normally dis- patched by railroads in less-than-train-load quantities. It has 85 steel cars, each carrying 85 tons of coal. There is one 3,000 horsepower locomotive for every 29.35 cars. After consideration of typical distances, turnaround time, and time in yards and sidings, this train is rated at 28.18 million ton-miles per year. Expected life is 30 years. B-21 Til Coal Unit Train 105 steel cars each carrying 100 tons, average of 6.5 3 ,000-horsepower locomotives, 10 spare cars, and 7.5% spare locomotives in maintenance, in dedicated service with expedited dispatching. After consideration of typical distances, turnaround times, and expedited dispatching, this train is rated at 661.5 million ton-miles per year. Expected life is 20 years. T12 Coal Slurry Pipeline 357 operating days per year — 40 years 150 miles, 38-inch diameter Preparation and dewatering not included, they are facilities T13 and T14 Input and output: 25 million tons per year. Includes water and slurry ponds and remix tanks; pump horsepower is 140 per mile. T13 Coal Slurry Preparation 357 operating days per year — 40 years Input and Output: 25 million tons per year. Includes preparation plant, water supply wells and storage, and agitated slurry storage. T14 Coal Slurry Dewatering 357 operating days per year — 40 years Input and Output: 25 million tons per year. Includes slurry tanks and water treatment plant. T15 Coal Barge Fifteen barges, each having a capacity of 1,400 tons, total capacity 21,000 tons. One 4,200-horsepower towboat. After consideration of typical velocity, turnaround time, drydock time, and typical transit distances in U.S. inland waterways, this barge combination is rated at 546.1 million ton-miles per year. Expected life is 30 years. T16 Coal Truck i One over-the-road semi-rig of maximum size carrying 25 tons of coal. After consideration of typical velocities, coal haul distances, turn- around times, and work hours, this truck is rated at 1.15 million ton-miles per year. Expected life is 7 years. B-22 T17 Gas Pipeline — Lower '48 360 operating days per year — 40 years 150 miles, 36- inch diameter Input: 870 million cubic feet per operating day. Output: 830 million cubic feet per operating day. Compressor horsepower is 252 per mile, of which about 32.5% is spare. Gas from pipeline used to power compressors. For lesser mileages, resources should not be scaled downward proportionately, but may be scaled upward (to at most about 1,500 miles) proportional to mileage. T18 Gas Distribution Facilities 365 operating days per year — 40 years Input and Output: 50 million cubic feet per day. Includes main station, four substations, metering and control equip- ment, city mains, secondary lines, and connection to meters for 24-square-mile urban area of 100,000 population. T19 Alaskan Gas Pipeline 345 operating days per year — 40 years Route of Alaskan Oil Pipeline, 809 miles, 42-inch-diameter chilled pipeline. Input: 3,500 million cubic feet per operating day. Output: 3,375 million cubic feet per opearting day. 12 compressor stations, 562,000 horsepower of compressors, 11 re- frigerating plants, four maintenance bases, two metering stations. T20 LNG Tanker One ship transports the liquefied equivalent of 2.6 billion cubic feet per trip. Velocity, composite transit time from likely sources, drydock time, and turnaround time considerations result in a rated 120.8 trillion cubic foot-statute miles (104.9 trillion cubic foot- nautical miles) per year. Expected life is 25 years. T21 230-kVac Transmission Line 365 operating days per year — 50 years 500 miles, single-circuit, 3-phase, aluminum clad steel reinforced cable, no station, rated at 250 megawatts. Input: at nominal 65% of full load is 1.424 billion kilowatt- hours per year. Losses are about 8% (compounded) per hundred miles. B-23 T22 345-k.Vac Transmission Line 365 operating days per year — 50 years 500 miles, single-circuit, 3-phase, aluminum clad steel reinforced cable, no station, rated at 600 megawatts. Input: at nominal 65% of full load is 3.416 billion kilowatt-hours per year Losses are about 4% (compounded) per hundred miles T23 500-kVac Transmission Line 365 operating days per year — 50 years 500 miles, single-circuit, 3-phase, aluminum clad steel reinforced cable. 500/230 step-down station to supply 16 distribution feeders. Rated at 1,200 megawatts. Input: at nominal 65% of full load is 6,833 billion kilowatt-hours per year. Losses are about 2% (compounded) per hundred miles plus about 2% of the output of the step-down station. T24 765-kVac Transmission Line 365 operating days per year — 50 years 500 miles, single-circuit, 3-phase, aluminum clad steel reinforced cable. Includes 765/230 step-down station to supply 25 distribution feeders Rated at 2,500 megawatts. Input: at 65% of full load is 14.235 billion kilowatt-hours per year. Losses are about 1% (compounded) per hundred miles plus about 2% of the output to the step-down station. B-24 T25 -400-kVdc Transmission Line 365 operating days per year — 50 years 800 miles, single-circuit, aluminum clad steel reinforced cable. Includes rectifier station, converts to -400 kVdc from generating plants' 13.8 kVac. Includes inverter station, converts output to 230 kVac to supply eight distribution feeders. Rated at 1,500 megawatts. Input: at 65% of full load is 8.541 billion kilowatt-hours per year. Losses are about 2% at the rectifier station. 1% per hundred miles and about 1% of the output to the inverter station. T26 Electricity Distribution — Aerial Lines 365 days of operation per year — 50 years 70.2 megawatts of power to 100 industrial customers 21.0 megawatts of power to 2,400 commercial customers 29.0 megawatts of power to 18,300 residential customers 11.4 megawatts of power to losses in system 131.6 megawatts total rated power. Small amount of undergrounding in very dense areas T27 Electricity Distribution — Underground Lines 365 days of operation per year — 50 years 70.2 megawatts of power to 100 industrial customers 21.0 megawatts of power to 2,400 commercial customers 29.0 megawatts of power to 18,300 residential customers 11.4 megawatts of power to losses in system 131.6 megawatts total rated power. Main feeders, except in very dense areas, are overhead, new trans- formers are on the surface, new secondary feeders are underground, new drops (individual service lines) are underground. B-25 Appendix B BRIEF DEFINITIONS OF THE 101 FACILITIES DEFINITION OF TERMS One barrel = 42 U.S. gallons Billion, in U.S. count, is 1,000 million Trillion, in U.S. count, is a million million Btu = British thermal unit FBR = Fast breeder reactor Gallons are U.S. gallons Gas/liquid ratio of a substance is the ratio of its volume in the gaseous state to its volume in the liquid state. For LNG, it is about 593. Heat rate of a power plant is the number of Btu's in the input fuel that are needed to produce one kilowatt of electric power. Because a kilowatt of power has 3,413 Btu's, the thermal efficiency of a power plant is 3,413 * heat rate. HTGR = High temperature gas reactor LNG = Liquefied natural gas LWR = Light water reactor Metric ton = 1,000 kilograms = 2,205 pounds Miles are statute miles unless otherwise stated Pu = Plutonium Nautical mile = 1.1515 statute miles Tons are short tons, unless otherwise stated Th = Thorium U = Uranium UF, = Uranium hexafluoride 6 U„0 o = Yellowcake J o Years life are estimated physical life of the plant (not necessarily amortized life) B-l FACILITIES El Onshore Primary Oil Recovery — Lower '48 365 operating days per year — 20 years Outputs: 1,825 barrels per day and 1,825 thousand cubic feet of gas per day. 100 producing and 75 dry holes, average depth 4,440 feet, gathering and production equipment. E2 Onshore Secondary Oil Recovery — Lower '48 365 operating days per year — 12 years Output: 913 barrels per day, no gas. 25 of 100 old wells worked over, 50 new holes drilled, 120 producers, 30 water injection, average depth 4,000 feet, gathering and produc- tion equipment. E3 Onshore Enhanced Oil Recovery — Lower '48 365 operating days per year — 6 years Output: 3,510 barrels per day, no gas. Workover of 30 of 60 old wells, 111 new drilled, 96 producers, 75 steam injection, average depth 2,500 feet, thermal recovery only, gathering and production equipment. E4 Offshore Oil Recovery — Lower '48 365 operating days per year — 20 years Outputs: 20,000 barrels per day and 20 million cubic feet gas per day 125 producing wells on five platforms, 95 dry holes, average depth 9,350 feet, one mile pipeline to shore. E5 North Alaskan Oil Recovery 365 operating days per year — 20 years Outputs: 54,000 barrels per day and 40.5 million cubic feet gas per day. 18 producing wells on three pads, two dry holes, average depth 9,900 feet, gathering and production equipment. 10.5 million cubic feet of the 40.5 million cubic foot gas output is used for pumping for the northern portion of the Alaskan Oil Pipeline. B-2 E6 High-Gasoline Refinery 345 operating days per year — 25 years Input: 200,000 barrels crude oil per operating day Outputs: 122,600 barrels gasoline per operating day 18,000 barrels kerosine per operating day 44,000 barrels diesel per operating day 10,000 barrels liquefied petroleum gas per operating day. Flexicoking, catalytic cracking, distillate hydrotreating, reforming, alkylation, and sulfur recovery. E7 Low-Gasoline Refinery 345 operating days per year — 25 years Input: 200,000 barrels crude oil per operating day Outputs: 78,800 barrels fuel oil per operating day 15,700 barrels naphtha per operating day 26,000 barrels reformate per operating day 51,800 barrels low-sulfur distillate per operating day. Flexicoking, distillate and gas oil hydrotreating, reforming, hydrogen production, and sulfur recovery. E8 Heavy Fuel Oil Gasification 330 operating days per year — 25 years Input: 57,800 barrels vacuum residuum (5.6% sulfur) per operating day. Output: 250 million cubic feet synthetic natural gas per operating day and 569 tons sulfur per operating day. Partial oxidation, shift conversion, Rectisol absorption, regenera- tion, methanation, oxygen plant, and sulfur recovery. E9 Naphtha Gasification 330 operating days per year — 25 years Inputs: 6.8 million pounds naphtha per operating day and 2.1 million pounds light liquids per operating day. Outputs: 174 million cubic feet of high-Btu gas per operating day. Sulfur removal (ZnO bed), steam reforming, CRG (catalyst rich gas) methanation, C0„ removal (Benfield process). 5-3 E10 Crude Oil Stockpile 365 operating days per year — 50 years Input: filled once with 50 million barrels. Output: none, 48 million barrels available. In five salt domes, 10 million barrels per dome, initial filling takes 360 days, can be withdrawn in 100 days, includes 100 miles of 32-inch oil pipeline and 100 miles of 24-inch water pipeline and related pump stations. Ell Alaskan Oil Export 350 operating days per year — 50 years Input: 2 million barrels per operating day. Output: 1.9985 million barrels per operating day. 32 fixed-roof-tanks each having 0.51 million barrels capacity, five berths for tankers up to 250,000 deadweight long tons, outflow capacity of 6 million barrels per day, gravity flow. El 2 Offshore Crude Oil Import 350 operating days per year — 50 years Input and Output: 1.7 million barrels per operating day. 12 floating-roof -tanks on shore, each having 1 million barrels capacity, three single-point moorings at 100 feet draft, two pipelines of 48-inch diameter and 12-miles length. El 3 Onshore Oil Import 350 operating days per year — 50 years Input and Output: 1.0 million barrels per operating day of crude oil or refined products. Marine terminal for two tankers up to 90,000 deadweight long tons, storage, and shore connection. E14 Surface Oil Shale Mine 300 operating days per year — 25 years Output: 54 million tons of shale per year having average of about 25 recoverable gallons per ton. Stripping ratio 2.1, seam thickness 300 feet, two pits, overland conveyor to stockpile, stockpile and disposal after retort; pro- duction stripping 5 million tons. B-4 E15 Underground Oil Shale Mine 365 operating days per year — 25 years Output: 54.75 million tons of shale per year having an average of about 25 gallons of shale oil recoverable per ton. Includes stockpile, preparation for retort, and disposal after retort. Room-and-pillar , 45-foot seam, 850 feet deep. Assumes 65% recovery of the target 45-foot seam. Includes two 16%, 580-foot declines; two 3,000-foot drives; haulage and conveyor ways; buildings, utilities, and mining equipment. El 6 In-Situ Shale Oil Recovery 330 operating days per year — 25 years Outputs: 36,830 barrels of in-situ shale oil per operating day plus 33,000 tons per day of shale having an additional recover- able 13,690 barrels per operating day. Assumes 450-foot seam, 1,300 feet deep; cross-cuts, explosive fracturing to produce rubble; 5 miles of 4-inch (gas), and 6-inch (shale oil) pipelines to storage and processing; 50-day buffer storage. El 7 Oil Shale Retorting and Upgradin g 328 operating days per year — 25 years Input: 165,000 tons of oil shale per operating day Outputs: 88,000 barrels of upgraded shale oil per operating day and 320 tons of anhydrous ammonia per operating day. Oil shale sizing, 25 Petrosix-type retorts, delayed coking, gas oil (1,600 psia) , and naphtha (700 psia) hydrotreating, gas pro- cessing plant, hydrogen plant, ammonia recovery (Claus and Well- man Lord units). E18 Shale Oil Upgradin g 330 operating days per year — 25 years Inputs: 75,800 barrels of in-situ raw shale oil per operating day plus 67,900 tons of oil shale per operating day. Outputs: 90,000 barrels of upgraded shale oil per operating day. Includes shale sizing and disposal, 11 retorts. Raw oil upgrading: delayed coking, hydrotreating, hydrogen production; NH and sulfur recovery. B-5 El 9 Onshore Conventional Gas Recovery — Lower '48 365 operating days per year — 20 years Outputs: 30 million cubic feet per day and 500 barrels of conden- sate per day. 100 producing wells, 80 dry holes, average depth of 5,870 feet, gathering and production equipment. E20 Onshore Enhanced Gas Recovery — Lower '48 365 operating days per year — 25 years Output: 208.2 million cubic feet per day. 120 producing wells, 24 dry holes, average depth 10,000 feet, tight formation, massive hydro-fracturing, pay sands 100 feet thick, gathering and production equipment. E21 Offshore Gas Recovery — Lower '48 365 operating days per year — 20 years Outputs: 250 million cubic feet per day and 10,000 barrels of condensate per day. 125 producing wells, 95 dry holes, average depth 10,700 feet, wells are on five platforms in 200 feet of water, pipeline to shore. E22 North Alaskan Gas Recovery 365 operating days per year — 20 years Outputs: 250 million cubic feet per day and 10,700 barrels of condensate per day. 24 producing wells, 2 dry holes, average depth 9,900 feet, gather- ing and production facilities. E23 Coal Mine Degasif ication 365 operating days per year — 30 years Output: 1 million cubic feet per day of pipeline quality gas (methane at about 900 Btu per cubic foot) 30 boreholes, 1,000 feet deep, includes collection, compression, and metering station; gas is withdrawn before mining begins. B-6 E24 Alaskan LNG Export 345 operating days per year — 50 years Input: 3,375 million cubic feet per operating day. Output: liquefied equivalent of 3,030 million cubic feet of gas per operating day. Four 550-thousand-barrel storage tanks, two ship berths of 50-foot draft. LNG plant with eight trains (treating, dehydration, cascade liquefaction) . E25 LNG Import 345 operating days per year — 50 years Input: liquefied equivalent of 2,809 million cubic feet of gas per day. Output: 2,795 million cubic feet per day. Two unloading docks with 48-foot draft, storage capacity of 2,200 barrels of LNG, 38-mile, 48-inch-diameter pipe to transmission system. E26 Natural Gas Stockpile 365 operating days per year — 50 years Input: filled once with 66,000 million cubic feet. Output: none, 60,000 million cubic feet available. 50 wells drilled in depleted field, withdrawal would require 100 days, and reinjection of 62,000 million cubic feet would require 200 days, scrubbing and dehydration included, 30 miles of 30-inch connecting pipe. E27 Underground Eastern Coal Mine 253 operating days per year — 20 years Output: 2 million tons per year. Preparation included, room-and-pillar , one 24-foot-diameter concrete shaft, one 17 14 x 14 x 2,900 foot stope; mining, onsite transporta- tion, and preparation equipment; assumes 5-foot seam E28 Surface Eastern Coal Mine 253 operating days per year — 20 years Output: 4 million tons per year. Assumes level 6-foot seam, stripping ratio 16:1, 90% recovery; includes initial stripping for two weeks' production, mining, onsite transportation, and processing equipment, preparation included. B-7 E29 Surface Western Coal Mine 253 operating days per year — 20 years Output: 6 million tons per year. Assumes level terrain, 30-foot seam, 2.1:1 stripping ratio, 90% recovery; includes initial stripping for two weeks' production, mining, onsite transportation, and processing equipment, prepara- tion included. E30 Underground Western Coal Mine 253 operating days per year — 20 years Output: 2 million tons per year. Preparation included, room-and-pillar , one 24-f oot-diameter concrete shaft, one 17° x 14 x 14 x 2,900 foot stope; mining, onsite trans- portation, and preparation equipment; assumes 5-foot seam. E31 Coal Gasification — High-Btu Gas 330 operating days per year — 25 years Input: 27,500 tons of Western lignite (8,300 Btu per pound) per operating day. Outputs: 250 million cubic feet of high heating value (about 980 Btu per cubic foot) gas per operating day, 1,475 tons of tar, tar oil, and naphtha per operating day, 905 tons of phenol and ammonia per operating day. The thermal efficiency for gas alone is about 53.6%, including by- products it is about 65.5%. Lurgi oxygen gasification, shift con- version, methanation, oxygen plant, sulfur recovery. E32 Coal Gasification — Low-and Medium-Btu Gas 330 operating days per year — 25 years Input: 27,500 tons of Western lignite, (8,300 Btu per pound) per operating day. Outputs: 1,440 million cubic feet of low-Btu (about 196 Btu per cubic foot) gas per operating day 1,645 tons of tar, tar oil, and naphtha per operating day 960 tons of phenols and ammonia per operating day. The thermal efficiency for gas alone is about 60.4%, including byproducts it is about 75.8%. Lurgi air-blown system, gas treatment, Claus, Wellman-Lord sulfur recovery. B-8 E33 Coal Gasification — Methanol 330 operating days per year — 25 years Input: 37,985 tons of Illinois 4.4% sulfur coal per operating day (10,200 Btu per pound). Output: 15,073 tons of fuel grade methanol per operating day (9,782 Btu per pound gives daily output of slightly more than in 250 million cubic feet of natural gas). The thermal efficiency is about 38.1%. Koppers-Totzek oxygen-blown gasification, Imperial Chemical Industries methanol synthesis. E34 Coal Liquefaction — Heavy Fuel Oil 330 operating days per year — 25 years Input: 10,000 tons of Kentucky 5.4% sulfur (11,000 Btu per pound) coal per operating day. Outputs: 4,330 tons (23,710 barrels) of 0.2% sulfur fuel oil per operating day 87 tons of ammonia per operating day 505 tons of sulfur per operating day- The thermal efficiency excluding the ammonia is about 70.7% including the ammonia about 71.5%. Synthoil catalysis coal liquefaction process. E35 Coal Solvent Refining 330 operating days per year — 25 years Input: 10,000 tons of coal (12,800 Btu per pound) per operating day. Outputs: 4,560 tons of solvent refined coal (about 16,600 Btu per pound) per operating day 2,010 barrels of naphtha per operating day 36 million cubic feet of low-Btu (about 636 Btu per cubic foot) fuel gas per operating day 306 tons of sulfur per operating day. The thermal efficiency for coal alone is about 59.0%, including byproducts it is about 72.0% Noncatalytic dissolver, aminal gas purification, Claus, Wellman-Lord sulfur recovery. E36 Coal Liquids Refinery 345 operating days per year — 25 years Input: 100,000 barrels of 0.2% sulfur fuel oil per operating day from coal liquefaction plant. Outputs: gasoline at about 61% of feed, other refined products at 36% of feed. Overall thermal efficiency is about 90.1%. Includes flexicoking, catalytic cracking, hydrotreating, reforming, alkylation, and sulfur recovery. B-9 E37 Surface Uranium Mine 253 operating days per year — 20 years Output: 1,200 short tons of 0.2% U o o ore per operating day. j o Run-of~mine ore is piled for pickup. Assumes level terrain; stripping ratio 20 cubic yards/ton ore, small ore body, 80% recovery; includes exploratory survey, drilling, access roads; preproduction stripping (5 x 10" cubic yards); diesel power plant, buildings, and mining equipment E38 Underground Uranium Mine 253 operating days per year — 20 years Output: 500 short tons of 0.2% U o o per ore per operating day J o Run-of-mine ore is piled for pickup. Includes exploratory survey, drilling, access roads; 16 x 500 foot shaft; 8 x 10 foot x 2,000 foot drifting; 8 x 10 x 2,000 foot crosscutting ; 6 x 8 x 400 foot stope raises; buildings, power, and mining equipment; assumes "erratic" ore body, 80% recovery. E39 Uranium Mill 330 operating days per year — 30 years Inputs: 330,000 tons of 0.2% U o o ore per year. J o Outputs: 880 tons of 75% U o o (yellowcake) per year. J o Acid leach process E 4 Ura nium Conversion 360 operating days per year — 15 years Inputs: 10,000 tons of 75% U~0 R (yellowcake) per year, plus hydrogen fluoride and nitric acid. Output: 10,000 tons of UF, (uranium hexaf luoride) per year. b Acid dissolution, solvent extraction, calcination, hydrof luorination, and f luorination, product purification. E41 Uranium Enrichment — Diffusion 365 operating days per year — 25 years Input: 15,850 metric tons of uranium per year as 0.71% U-235 in UF,. Outputs: 2,300 metric tons of uranium per year as 3.2% of U-235 in UF5 plus tails of 13,550 metric tons of uranium per year as 0.29% U-235 in UF 6 - This amounts to 8.75 million separative work units per year. Gaseous diffusion process. B-10 E42 LWR Fuel Fabrication — No Pu Recycle 300 operating days per year — 15 years Input: 600 metric tons of uranium per year, contained in 900 metric tons of UF5 (uranium hexaf luoride) ; cold chemicals. Outputs: 600 metric tons of uranium per year in U02 pellets in PWR and BWR fuel bundles; also HF and wastes. Oxidation of UF5 to UO2 , pelletizing, loading pellets into pins, and assembly into fuel elements. E43 LWR Fuel Fabrication — Pu Recycle 300 operating days per year — 15 years Inputs: 150 metric tons of heavy metals (uranium and plutonium) per year contained in 1973 metric tons of UO3 and 6.43 metric tons of Pu02 • Outputs: 150 metric tons of heavy metals per year in reactor fuel bundles, HF and wastes. Oxidation of U and Pu compounds to oxides; pelletizing, loading into pins, fuel bundle assembly; includes glove-box handling of Pu. E44 HTGR Fuel Fabrication 300 operating days per year — 15 years Inputs: 432 metric tons of thorium per year in 850 metric tons of Th (N03)4 and 16 metric tons of uranium per year in 42 metric tons of enriched UF5 ; also cold chemicals- Outputs: 448 metric tons of heavy metals per year in 24,000 fuel elements. Fertile particle production by Solgel process; includes calcination, coating, blending; preparation of fuel rods, loading into graphite fuel elements; heat conditioning. E45 FBR Fuel Fabrication 300 operating days per year — 15 years Inputs: 290 metric tons of uranium per year in 390 metric tons of UF6 (yellowcake) and 25 metric tons of plutonium per year in 30 metric tons of PUO2 ; also cold chemicals. Outputs: 315 metric tons of heavy metals (uranium and plutonium) per year in fuel bundles. Conversion of yellowcake to UO2 pellets; formation of Pu02 pellets, pellet blending, loading into pins, fuel bundle assembly; glove-box handling of Pu. B-ll E46 LWR Spent Fuel Reprocessing 300 operating days per year — 15 years Inputs: depleted fuel bundles from original reactor charges totaling 1,500 metric tons of heavy metals (uranium and plutonium) per year; also cold chemicals. Outputs: 1,380 metric tons of uranium per year in UF^ and 36 metric tons of plutonium per year in Pu02; also 80 metric tons per year of calcined fission products; other wastes. Cladding removal, Purex separation, "disaster-proof" processing building; solidified waste. E47 HTGR Spent Fuel Reprocessing 300 operating days per year — 15 years Input: 300 metric tons per year of heavy metals (uranium and thorium) in irradiated fuel elements; also cold chemicals- Outputs: 283 metric tons of thorium per year in aequeous nitrate 11 metric tons of uranium per year in U-233 aequeous nitrate, 6 metric tons per year of heavy metals in calcined fission products* Controlled burning, acid leach, solvent extraction E48 FBR Spent Fuel Reprocessing 300 operating days per year — 15 years Input: 950 metric tons of heavy metals, (uranium and plutonium) in the form of irradiated fuel elements; also cold chemicals. Outputs: 800 metric tons of uranium per year in UO2 90 metric tons of plutonium per year in Pu02 60 tons per year of heavy metals in calcined fission products and other radioactive wastes- Cladding removal; Purex separation, U and Pu to oxides, "disaster- proof" processing building, waste storage. E49 High-Level Waste Disposal In 250 handling days per year this facility accepts 3,100 canisters per year of calcined fission products, plus other waste equal to about 500 metric tons per year. At this rate, its capacity would be reached in about 40 years. Canisters sealed in 2-inch casks, stored in outdoor concrete cylinders, Surface retrievable storage facility concept. B-12 E50 Solid Waste Collection/Separation Plant 250 operating days per year — 30 years Input: 500 tons of municipal solid waste per operating day. Outputs: 335 tons of combustible solid waste per operating day. 165 tons of noncombustibles and higher valued combustibles. Includes dumping floor, air classification, magnetic metals separa- tion, screening. E51 Oil-Fired Power Plant 365 days per year — 30 years Rated at 800 megawatts Input: Heat rate is 9»875 Btu per kilowatt hour, which is a thermal efficiency of 0.3456. At a nominal 55% of full load and using only fuel oil at 6.3 million Btu per barrel, the annual oil input would be 6.04 million barrels. Output: at nominal 55% of full load is 3.854 billion kilowatt- hours per year. Uses fuel oil; natural gas is an alternative and light oil an emergency alternative. E52 Reconversion of Oil Power Plant to Coal 365 days per year — Conversion happens once, plant operates to end of its original life which is 30 years or less Rated at 250 megawatts Input: Heat rate is 9,875 Btu per kilowatt-hour, which is a thermal efficiency of 0.3456. At a nominal 60% of full load and using high-Btu coal of 12,000 Btu per pound the annual coal input would be 0.541 million tons. If low-Btu coal of 8,500 Btu per pound were used then the annual input would be 0.763 million tons. Output: At nominal 60% of full load is 1.314 billion kilowatt-hours per year. Plant originally designed to burn coal and was converted to oil and reconverted to coal. B-13 E53 Coal-Fired Power Plant — Low-Btu Coal 365 days per year — 30 years Rated at 800 megawatts Input: Heat rate is 9,875 Btu per kilowatt-hour, which is a thermal efficiency of 0.3456. At a nominal 60% of full load and using low-Btu coal of 8,500 Btu per pound the annual input would be 2.442 million tons. Output: at nominal 60% of full load is 4.205 billion kilowatt-hours per year. Burns low-Btu coal. Has natural draft cooling tower(s). E54 Coal/Waste Power Plant — High-Btu Coal 365 days per year — 30 years Rated at 800 megawatts Input: Heat rate is 9,875 Btu per kilowatt-hour, which is a thermal efficiency of 0.3456. At a nominal 60% of full load and using only high-Btu coal of 12,000 Btu per pound the annual input would be 1.730 million tons. Output: at nominal 60% of full load is 4.205 billion kilowatt-hours per year. Burns high-Btu coal or solvent refined coal. Has natural draft cooling tower(s). E55 Coal/Waste Power Plant — Low-Btu Coal 365 days per year — 30 years Rated at 350 megawatts Input: 10% of the Btu input is from municipal waste. Heat rate is 9,875 Btu per kilowatt-hour, which is a thermal efficiency of 0.3456. At a nominal 60% of full load the annual inputs would be 0.151 million tons of separated combustible municipal waste (at 6,000 Btu per pound) and 0.962 million tons of low- Btu coal (at 8,500 Btu per pound). Output: at nominal 60% of full load is 1.840 billion kilowatt-hours per year Has natural draft cooling tower(s). B-14 E56 Coal/Waste Power Plant — High-Btu Coal 365 days per year — 30 years Rated at 350 megawatts Input: 10% of the Btu input is from municipal waste. Heat rate is 9,875 Btu per kilowatt hour, which is a thermal efficiency of 0.3456. At a nominal 60% of full load the annual inputs would be 0.151 million tons of separated combustible municipal waste (at 6,000 Btu per pound) and 0.681 million tons of high- Btu coal (at 12,000 Btu per pound). Output: at nominal 60% of full load is 1.840 billion kilowatt-hours per year. Has natural draft cooling tower (s). E57 Sulfur Oxide Removal 365 days per year — 30 years Removes 80% of sulfur from stack gas of 800 megawatt power plant fired with 3.5% sulfur coal, operating at a nominal 60% of full load. Reduces plant efficiency 7-1/2%. Uses Wellman-Lord process. Produces sulfur as a byproduct. E58 Low/Intermediate-Btu Gas-Fired Power Plant 365 days per year — 30 years Rates at 800 megawatts Input: Heat rate is 9,875 Btu per kilowatt-hour, which is a thermal efficiency of 0.3456. At a nominal 55% of full load the input would be either 76.12 billion cubic foot of intermediate-Btu gas (at 500 Btu per cubic foot) or 190.31 billion cubic foot of low-Btu gas (at 200 Btu per cubic foot)* Output: at nominal 55% of full load is 3.854 billion kilowatt-hours per year. Can burn light oil as an emergency alternative. E59 High-Btu Gas-Fired Power Plant 365 days per year — 30 years Rated at 800 megawatts Input: Heat rate is 9,875 Btu per kilowatt-hour, which is a thermal efficiency of 0.3456. At a nominal 55% of full load and using gas of 1,025 Btu per cubic foot the annual input would be 37.13 billion cubic feet. Output: at nominal 55% of full load is 3.854 billion kilowatt-hours per year. Can burn light oil as an emergency alternative. Has natural draft cooling tower(s). B-15 E60 Conversion of Gas Plant to Coal 365 days per year — Conversion happens once, plant operates to end of its original life, which is 30 years or less Rated at 250 megawatts Input: Heat rate is 9,875 per kilowatt-hour, which is a thermal efficiency of 0.3456. At a nominal 60% of full load and using high-Btu coal of 12,000 Btu per pound the annual coal input would be 0.541 million tons. If low Btu coal of 8,500 Btu per pound were used then the annual input would be 0.763 million tons. Output: at nominal 60% of full load is 1.314 billion kilowatt-hours per year. E61 Combined Cycle Power Plant 365 days per year — 30 years Rated at 400 megawatts Inputs: Heat rate is 8,530 Btu per kilowatt-hour, which is a thermal efficiency of 0.4000. At a nominal 55% of full load and using only high Btu gas (at 1,025 Btu per cubic foot) the annual input would be 16.04 billion cubic feet. Output: at nominal 55% of full load is 1.927 billion kilowatt-hours per year. Has 240-mega*watt gas turbine and 160-megawatt steam turbine. Uses natural gas, but can use light oil as an alternate. Has natural draft cooling tower(s). E62 Gas Turbine Power Plant Available 365 days per year for 30 years, but is operated only at peak periods. Rated at 133 megawatts. Input: Heat rate is 11,000 Btu per kilowatt-hour which is a thermal efficiency of 0.3103. At a nominal 10% of full load and usinj only high-Btu gas (at 1,020 Btu per cubic foot the annual input would be 1.25 billion cubic feet). Output: at nominal 10% of full load is 0.1165 billion kilowatt-hours per year. Uses natural gas but can use light oil as an alternate. B-16 E63 Fuel Cells Available 365 days per year for 30 years but operated only at peak periods, amounting to 2,000 hours per year. Inputs: 41 barrels of No. 2 fuel oil per operating hour, or 242 thousand cubic feet of natural gas or methane per operating hour, or 44 barrels of naphtha per operating hour. Outputs: In 2,000 hours of operation per year this output is 0.052 billion kilowatt-hours- Included are cells, fuel reformer, dc-ac inverter, transformer, switchgear, controls, and telemetry for remote control. E64 Light Water Reactor Power Plant 365 days per year — 30 years Rated at 1,100 megawatts. Output: at nominal 71% of full load is 6.842 billion kilowatt- hours per year. Has natural draft cooling tower(s). E65 High-Temperature Gas Reactor Power Plant 365 days per year — 30 years Rated at 1,500 megawatts. Output: at nominal 71% of full load is 9.329 billion kilowatt- hours per year. Has natural draft cooling tower (s). E66 Liquid Metal Fast Breeder Reactor Power Plant 365 days per year — 30 years Rated at 1,000 megawatts- Output: at nominal 71% of full load is 6.220 billion kilowatt- hours per year. Has natural draft cooling tower (s). E67 Dam and Hydroelectric Power Plant 365 days per year — 60 years Rated at 200 megawatts (three 66-2/3 megawatt generating units) Has earthfill dam of 15 million cubic yards. Output: at nominal 56% of full load is 0.981 billion kilowatt- hours per year. B-17 E68 Pumped Storage 365 days per year — 60 years Rated at 1,000 megawatts. Pumped storage facilities, overall, consume more power than they produce. Viewed by the electricity demand; however, they produce power at the peak time when it is needed. In that respect, the output of this facility at a nominal 13% of full time is 1.139 billion kilowatt-hours per year. This facility has two earthfilled dams and four 250-megawatt combination generating and pumping units. E69 Geothermal Power Complex 341 days per year — 30 years Power plant rated at 200 megawatts, flash steam cycle. Output: at 75% of full capacity, is 1.314 billion kilowatt-hours. Includes gathering system and 20% dry holes. Vapor-dominated (e.g., Geysers) geothermal system. E70 Solar Space Heating 200 heating days per year — 30 years 30,000 1,600-square-foot dwellings in climate equivalent to Washington, D.C., each with 500 square feet of collector. Input: 4.3 trillion Btu per heating season. Output: 2.1 trillion Btu per heating season. Installations are in new construction in batches of 150. 1,000- gallon tank and auxiliary boiler included. Collectors, frames and structures are of aluminum. E71 Solar Space Conditioning 200 heating and 100 cooling days per year — 30 years 30,000 1,600-square-foot dwellings in climate equivalent to Washington, D.C., each with 500 square feet of collector. Inputs: 4.3 trillion Btu per heating season 4.1 trillion Btu per cooling season • Outputs: 2.1 trillion Btu per heating season 0.8 trillion Btu per cooling season. Installations are in new construction in batches of 150. Solar supplies 70% of energy requirement. 1,000 gallon tank, auxiliary boiler, and 3-ton lithium bromide absorption chiller included. Collectors, frames, and structures are of aluminum. B-18 E72 Geopressured Gas Recovery 365 operating days per year — 12 years Input: 700,000 barrels per day of saline water containing methane and other chemicals. Outputs: 50 million cubic feet of natural gas per day. Can, but need not, produce 700,000 barrels per day of fresh water at 215°F. 100 producing wells and 76 dry holes averaging 15,000 feet depth, some onshore, some offshore. Characteristics of geological forma- tion are assumed, not known. Transfers excess heat to imported fresh water. Transfers saline water to adjacent depleted oil field. Includes exploratory and production drilling, gathering and disposal systems and surge tankages for fresh and saline water. Excludes off- site pipe for input and output of fresh water. E73 Coal Solvent Refining - SRC II 330 operating days per year — 25 years Input: 34,000 tons of Illinois Basin Coal per operating day. Outputs: 57,390 barrels of fuel oil per operating day 6 million cubic feet of gas per operating day 8,222 barrels of liquefied petroleum gas (LPG) per operating day 15,000 barrels of light distillate per operating day 66.7 tons of ammonia per operating day 990 tons of sulfur per operating day* Fuel oil produced is liquid at atmospheric conditions, burnable in most oil fired boilers. Thermal efficiency of the plant including byproducts is 0.62. For fuel oil only the thermal effi- ciency is 0.45. E74 Fluidized Bed (Atmospheric) Power Plant 365 operating days per year — 30 years Rated at 800 megawatts, available about 1990. Inputs: Any coal, most useful with high sulfur coal, limestone or dolomite at about one third of coal tonnage. Outputs: At nominal 65% of full load is 4.555 billion kilowatt-hours per year Slag (coal ash and calcium sulfate) at about 35% of input coal tonnage. Stack gas cleaned with cyclones and electrostatic precipitators. Slag disposed of locally as land fill. Has natural draft cooling tower (s). B-19 Tl Crude Oil Pipeline — Lower '48 360 operating days per year — 40 years 150 miles, 36- inch diameter Input: 800,000 barrels per operating day. Output: 800,000 barrels per operating day. Pump horsepower is 270 per mile, of which 26% is spare. For lesser mileages, resources should not be scaled downward proportionately, but may be scaled upward (to at most about 1,500 miles) proportional to mileage. T2 Alaskan Oil Pipeline 350 operating days per year — 40 years 800 miles, 48-inch diameter Input: 2,050,000 thousand barrels per operating day. Output: 2,000,000 barrels per operating day. Total pumping horsepower is 650,000, of which about 23% is spare. Some pumps fueled by associated gas, some by processed crude taken from the pipeline. T3 Oil Tanker 90,000-deadweight-long-ton ship with 24,500 shaft horsepower power plant. Capacity is 620,000 barrels. After consideration of veloc- ity, turnaround time, drydock time, and typical transit distance for crude and refined products imported to the U.S., the tanker is rated at 25,550 million barrel-statute miles per year (22,188 million barrel-nautical miles). It is expected to have a 25-year life. T4 Oil Barge Five barges, each having a capacity of 18,000 barrels, total capacity 90,000 barrels, plus a 3,000-horsepower towboat. After consideration of velocity, turnaround time, drydock time, and typical oil transit distances in U.S. inland waterways, this barge combination is rated at 1 ,424-million-barrel-miles per year. It is expected to have a 30-year life. T5 Oil Tank Truck The tractor-trailer rig has a 300-horsepower tractor; trailer has aluminum tank with capacity of 9,500 gallons. After consideration of typical routings, hours per week, and maintenance times, the oil truck is rated at 2.825 million barrel-miles per year. It is expected to have a 7-year life. B-20 T6 Products Pipeline 345 operating days per year — 40 years 100 miles, 12-inch-diameter , two pump stations Input and Output: 70,000 barrels of refined products per operating day. T7 Hot Oil Pipeline 360 operating days per year — 40 years 50 miles, 12-inch diameter, insulated, two heating stations Input: 40,000 barrels of heavy fuel oil per operating day. Output: 39,000 barrels of heavy oil per operating day. T8 Refined Products Bulk Station 345 days per year receiving from pipeline 250 days per year loading trucks, expected 30-year life Input: 50,000 barrels on each of 345 days per year. Output: 69,000 barrels on each of 250 days per year. 500,000-barrel storage capacity, manifolds, loading pumps, 12 double-loading racks, metering, and controls. T9 Rail Line 40 new miles of single track — expected life 40 years Includes signals, communications, structures, wooden ties, grading, ballast, 119-pound per yard rail. This facility is new heavy duty line, not rehabilitation of existing track. T10 Mixed Train This train is a composite of those coal cars that are normally dis- patched by railroads in less-than-train-load quantities. It has 85 steel cars, each carrying 85 tons of coal. There is one 3 3 000 horsepower locomotive for every 29.35 cars. After consideration of typical distances, turnaround time, and time in yards and sidings this train is rated at 28.18 million ton-miles per year. Expected life is 30 years. B-21 Til Coal Unit Trai n 105 steel cars each carrying 100 tons, average of 6.5 3 ,000-horsepower locomotives, 10 spare cars, and 7.5% spare locomotives in maintenance, in dedicated service with expedited dispatching. After consideration of typical distances, turnaround times, and expedited dispatching, this train is rated at 661.5 million ton-miles per year. Expected life is 20 years. T12 Coal Slurry Pipeline 357 operating days per year — 40 years 150 miles, 38-inch diameter Preparation and dewatering not included, they are facilities T13 and T14 Input and output: 25 million tons per year. Includes water and slurry ponds and remix tanks; pump horsepower is 140 per mile. T13 Coal Slurry Preparation 357 operating days per year — 40 years Input and Output: 25 million tons per year. Includes preparation plant, water supply wells and storage, and agitated slurry storage. T14 Coal Slurry Dewatering 357 operating days per year — 40 years Input and Output: 25 million tons per year. Includes slurry tanks and water treatment plant. T15 Coal Barge Fifteen barges, each having a capacity of 1,400 tons, total capacity 21,000 tons. One 4,200-horsepower towboat. After consideration of typical velocity, turnaround time, drydock time, and typical transit distances in U.S. inland waterways, this barge combination is rated at 546.1 million ton-miles per year. Expected life is 30 years. T16 Coal Truck One over-the-road semi-rig of maximum size carrying 25 tons of coal. After consideration of typical velocities, coal haul distances, turn- around times, and work hours, this truck is rated at 1.15 million ton-miles per year. Expected life is 7 years. B-22 T17 Gas Pipeline — Lower '48 360 operating days per year — 40 years 150 miles, 36-inch diameter Input: 870 million cubic feet per operating day. Output: 830 million cubic feet per operating day. Compressor horsepower is 252 per mile, of which about 32.5% is spare. Gas from pipeline used to power compressors. For lesser mileages, resources should not be scaled downward proportionately, but may be scaled upward (to at most about 1,500 miles) proportional to mileage. T18 Gas Distribution Facilities 365 operating days per year — 40 years Input and Output: 50 million cubic feet per day. Includes main station, four substations, metering and control equip- ment, city mains, secondary lines, and connection to meters for 24-square-mile urban area of 100,000 population. T19 Alaskan Gas Pipeline 345 operating days per year — 40 years Route of Alaskan Oil Pipeline, 809 miles, 42-inch-diameter chilled pipeline. Input: 3,500 million cubic feet per operating day. Output: 3,375 million cubic feet per opearting day. 12 compressor stations, 562,000 horsepower of compressors, 11 re- frigerating plants, four maintenance bases, two metering stations. T20 LNG Tanker One ship transports the liquefied equivalent of 2.6 billion cubic feet per trip. Velocity, composite transit time from likely sources, drydock time, and turnaround time considerations result in a rated 120.8 trillion cubic foot-statute miles (104.9 trillion cubic foot- nautical miles) per year. Expected life is 25 years. T21 230-kVac Transmission Line 365 operating days per year — 50 years 500 miles, single-circuit, 3-phase, aluminum clad steel reinforced cable, no station, rated at 250 megawatts. Input: at nominal 65% of full load is 1.424 billion kilowatt- hours per year- Losses are about 8% (compounded) per hundred miles. B-23 T22 345-kVac Transmission Line 365 operating days per year — 50 years 500 miles, single-circuit, 3-phase, aluminum clad steel reinforced cable, no station, rated at 600 megawatts. Input: at nominal 65% of full load is 3.416 billion kilowatt-hours per year Losses are about 4% (compounded) per hundred miles T23 500-kVac Transmission Line 365 operating days per year — 50 years 500 miles, single-circuit, 3-phase, aluminum clad steel reinforced cable. 500/230 step-down station to supply 16 distribution feeders. Rated at 1,200 megawatts. Input: at nominal 65% of full load is 6,833 billion kilowatt-hours per year. Losses are about 2% (compounded) per hundred miles plus about 2% of the output of the step-down station. T24 765-kVac Transmission Line 365 operating days per year — 50 years 500 miles, single-circuit, 3-phase, aluminum clad steel reinforced cable. Includes 765/230 step-down station to supply 25 distribution feeders, Rated at 2,500 megawatts. Input: at 65% of full load is 14.235 billion kilowatt-hours per year. Losses are about 1% (compounded) per hundred miles plus about 2% of the output to the step-down station. B-24 T25 -400-kVdc Transmission Line 365 operating days per year — 50 years 800 miles, single-circuit, aluminum clad steel reinforced cable. Includes rectifier station, converts to -400 kVdc from generating plants' 13.8 kVac. Includes inverter station, converts output to 230. kVac to supply eight distribution feeders. Rated at 1,500 megawatts. Input: at 65% of full load is 8.541 billion kilowatt-hours per year. Losses are about 2% at the rectifier station. 1% per hundred miles and about 1% of the output to the inverter station. T26 Electricity Distribution — Aerial Lines 365 days of operation per year — 50 years 70.2 megawatts of power to 100 industrial customers. 21.0 megawatts of power to 2,400 commercial customers 29.0 megawatts of power to 18,300 residential customers 11.4 megawatts of power to losses in system 131.6 megawatts total rated power. Small amount of undergrounding in very dense areas T27 Electricity Distribution — Underground Lines 365 days of operation per year — 50 years 70.2 megawatts of power to 100 industrial customers 21.0 megawatts of power to 2,400 commercial customers 29.0 megawatts of power to 18,300 residential customers 11.4 megawatts of power to losses in system 131.6 megawatts total rated power. Main feeders, except in very dense areas, are overhead, new trans- formers are on the surface, new secondary feeders are underground, new drops (individual service lines) are underground. B-25 Appendix C Appendix C WATER CONSUMPTION REQUIREMENTS FOR ESPM ENERGY RELATED FACILITIES Water Type Facility No. Facility Name Consumed (Annual acre-ft) 1 Onshore primary oil recovery — Lower '48 (1.825 Mbpd) o 2 Onshore secondary oil recovery — Lower '48 (0.913 Mbpd) 660 3 Onshore enhanced oil recovery — Lower '48 (3.510 Mbpd) 1,260 4 Offshore oil recovery — Lower '48 and South Alaska (20 Mbpd) 5 North Slope Alaskan Oil Recovery Cfi (180 Mbpd) ' ■H 6 High-Gasoline Refinery 4J •H (200 Mbpd, effective) 12,700 H •H 7 Low-gasoline refinery CJ CO (200 Mbpd, effective) 10,900 i fe 8 Heavy fuel oil gasification W3 (250 MMcfd) 2,920 9 Naphtha gasification (174 MMcfd) 1,550 10 Crude oil stockpile (50 MMb) 11 Alaskan oil export (2,000 Mbpd) 12 Offshore crude oil import (1,700 Mbpd) o 13 Onshore oil import (1,000 Mbpd) o 14 Surface oil shale mine (54 MMtpy) 1,690 15 Underground oil shale mine (54.75 MMtpy) 5,700 16 In-situ shale oil recovery (37 Mbpd oil) 1,910 17 Oil shale retorting and upgrading (90 Mbpd) 15,900 ! 18 Shale oil upgrading (90 Mbpd oil) 15,900 19 Onshore conventional gas recovery — Lower '48 (30 MMcfd) o ! 20 Onshore enhanced gas recovery — Lower '48 (208 MMcfd) 21 Offshore gas recovery — Lower '48 (250 MMcfd) 22 North Slope Alaskan gas recovery (250 MMcfd) 23 Coal mine degasif ication (1 MMcfd) C-l Appendix C (Continued) Water Consumed Facility Facility (Annual Type No. Name acre-f t) 24 Alaskan LNG export (3,030 MMcfd) 25 LNG import (2,795 MMcfd) 26 Natural gas stockpile (66,000 MMcf) 27 Underground eastern coal mine (2 MMtpy) 400 28 Surface eastern coal mine (4 MMtpy) 307 29 Surface western coal mine (6 MMtpy) 307 30 Underground western coal mine (2 MMtpy) 400 31 Coal gasification — high Btu (250 MMcfd) 7,440 32 Coal gasification — . low and medium Btu (1,449 MMcfd) 5,100 CO 33 Coal gasification - methanol 0) ■H (15,000 tpd) 8,100 •H 34 Coal liquefaction — heavy fuel oil •H (21.7 Mbpd) 3,870 ca 35 Coal solvent refining — SRC (4,560 tpd SRC) 3,720 00 36 Coal liquids refinery (100 Mbpd) 1,338 5-i 0) 37 Surface uranium mine (1,200 tpd) 6 38 Underground uranium mine (500 tpd) 9 39 Uranium mill (1,000 tpd) 40 Uranium conversion (1,000 tpd) 3,010 41 Uranium enrichment — diffusion (8,750 Mt SWU/y) 23,500 42 LWR fuel fabrication — no Pu recycle (600 MtU/y) 586 43 LWR fuel fabrication — Pu recycle (150 MTh/y) 140 44 HTGR fuel fabrication (450 MTh/y) 209 45 FBR fuel fabrication (315 MTh/y) 104 46 LWR spent fuel reprocessing (1,500 MTU/y) 1,075 47 HTGR spent fuel reprocessing (300 MTh/y) 491 48 FBR spent fuel reprocessing (950 MTh/y) 843 49 High-level waste disposal (3,000 canisters/y) 50 Solid waste collection/separation plant (335 tpd) 51 Oil-fired power plant (800 MWe) 9,330 C-2 Appendix C (Continued) Water Facility Facility Consumed Type No. Name (Annual acre-f t) 52 Reconversion of oil plant to coal (250 MWe) 3,175 53 Coal-fired power plant — low Btu (800 MWe) 14,000 54 Coal-fired power plant — high Btu (800 MWe) 10,150 55 Coal/waste power plant — low-Btu coal (350 MWe) 5,810 56 Coal/waste power plant — high-Btu coal (350 MWe) 5,810 57 Sulfur oxide removal (800 MWe) 1,740 58 Low/intermediate-Btu gas-fired plant (800 MWe) 9,325 •H 4-J 59 High-Btu gas-fired power plant •H H •H O (800 MWe) 9,325 60 Conversion of gas plant to coal 03 (250 MWe) 3,175 >. 61 Combined-cycle power plant (400 MWe) 3,100 oO 62 Gas turbine power plant (133 MWe) 0) 63 Fuel cells (26 MWe) w 64 Light water reactor — LWR (1,100 MWe) 25,200 65 High-temperature gas reactor — HTGR (1,500 MWe) 20,600 66 Fast breeder reactor — LMFBR (1,000 MWe) 20,600 67 Dam and hydroelectric power plant (200 MWe) 68 Pumped storage (1,000 MWe) 69 Geothermal power complex (200 MWe) 70 Solar space heating (30,000 dwellings) 18 71 Solar space conditioning (30,000 dwellings) 18 C-3 Appendix C (Continued) Water Type Facility No. Facility Name Consumed (Annual acre-f t) 1 Crude oil pipeline — Lower '48 (800 Mbpd, 1,000 mi) 2 Alaskan oil pipeline (2,000 Mbpd, 789 mi) 3 Oil tanker (90,000 dwt) 1.5 4 Oil barges (90,000 bbl) 0.7 5 Oil tank truck (9,500 gal) 6 Products pipeline (70 Mbpd, 100 mi) 7 Hot oil pipeline (40 Mbpd, 50 mi) rn 8 Refined products bulk station (69 Mbpd^ i .2 9 Rail line (40 mi, single track) 12 Lilt: 10 Conventional train (100 t per car) 11 Coal unit train (10,500 t) o rt 12 Coal slurry pipeline (25 MMtpy, Pn 1,000 mi) o 13 Coal slurry preparation (25 MMtpy) 19,700 •H 4_j 14 Coal slurry dewatering (25 MMtpy) 03 I 4-J 15 Coal barges (21,000 t) 0.7 5-( O CO 16 Coal truck (25 t) 17 Gas pipeline — Lower '48 a rt H I (870 MMscfd, 1,000 mi) 18 Gas distribution facilities (50 MMcfd) 19 Alaskan gas pipeline (3,400- MMcfd) , 809 mi) 20 LNG tanker (2,600 MMcf) 17 21 230 kVac transmission line (250 MWe, 500 mi) 22 345 kVac transmission line (600 MWe, 500 mi) 23 500 kVac transmission line (1,200 MWe, 500 mi) o 24 765 kVac transmission line (2,500 MWe, 500 mi) 25 ±400 kVdc transmission line (1,500 MWe, 800 mi) 26 Electricity distribution — aerial line (131.6 MWe) 27 Electricity distribution — underground lines (131.6 MWe) ■tt U.S. GOVERNMENT PRINTING OFFICE : 1979 O— 281-067 (180) C-4 miHr A000070ft75H5M