600779082A
Energy From the West
Impact Analysis Report
Volume I:
Introduction and Summary
By
Science and Public Policy Program
University of Oklahoma
Irvin L. White
Michael A. Chartock
R. Leon Leonard
Steven C. Ballard
Martha W. Gilliland
Edward J. Malecki
Edward B. Rappaport
Frank J. Calzonetti
MarkS. Eckert
Timothy A. Hall
Gary D. Miller
Michael D. Devine
Managers, Impact Analysis Report
R. Leon Leonard, Science and Public Policy
University of Oklahoma
Martha W. Gilliland, Energy Policy Studies, Inc.
C. Patrick Bartosh
B. Russ Eppright
Thomas W. Grimshaw
Milton Owen
KenChoffel
Timothy J. Wolterink
Jim Sherman
James L. Machin
Dennis D. Harner
David Cabe
Sam A. Gavande
W. F. Holland
Carl-Heinz Michelis
Michael W. Hooper
Prepared for:
Office of Research and Development
U.S. Environmental Protection Agency
Washington, D.C. 10460
Project Officer:
Steven E. Plotkin
Office of Energy, Minerals and Industry
Contract Number 68-01-1916
nergy
from
the
West
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DISCLAIMER
This report has been reviewed by the Office of Energy,
Minerals and Industry, U.S. Environmental Protection Agency, and
approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the U.S.
Environmental Protection Agency, nor does mention of trade names
or commercial products constitute endorsement or recommendation
for use.
-L-L
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FORWARD
The production of electricity and fossil fuels inevitably
impacts Man and his environment. The nature of these impacts
must be thoroughly understood if balanced judgements concerning
future energy development in the United States are to be made.
The Office of Energy, Minerals and Industry (OEMI), in its role
as coordinator of the Federal Energy/Environment Research and
Development Program, is responsible for producing the informa-
tion on health and ecological effects - and methods for miti-
gating the adverse effects - that is critical to developing the
Nation's environmental and energy policy. OEMI's Integrated
Assessment Program combines the results of research projects
within the Energy/Environment Program with research on the
socioeconomic and political/institutional aspects of energy
development, and conducts policy - oriented studies to identify
the tradeoffs among alternative energy technologies, development
patterns, and impact mitigation measures.
The Integrated Assessment Program has supported several
"technology assessments" in fulfilling its mission. Assess-
ments have been supported which explore the impact of future
energy development on both a nationwide and a regional scale.
Current assessments include national assessments of future
development of the electric utility industry and of advanced
coal technologies (such as fluidized bed combustion). Also,
the Program is conducting assessments concerned with multiple-
resource development in two "energy resource areas":
o Western coal states
o Lower Ohio River Basin
This report, which describes the impacts likely to be
experienced when six energy resources are developed in eight
western states, is one of three major reports produced by the
"Technology Assessment of Western Energy Resource Development"
study. (The other two reports describe the technologies likely
to be used and analyze policy problems and issues that can
be expected to arise.) The report is divided into two volumes.
The first or summary volume introduces the study, describes the
development alternatives which were assessed and summarizes the
results of the impact analyses which were conducted. The second
volume reports the detailed results of both site-specific and
iii
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regional impact analyses. The report has been designed to be
useful to laypersons as well as persons who have a professional
interest in energy resource development. And results are pre-
sented in a way which make this report a useful planning hand-
book for both professional planners and interested citizens.
We would like to receive your comments concerning this
report. Such comments will help us to improve the usefulness of
the products produced by our Integrated Assessment Program.
Steven R. Rezne
Acting Deputy Assistant
Administrator for Energy,
Minerals and Industry
IV
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PREFACE
This Impact Analysis Report has been prepared as part
of "A Technology Assessment of Western Energy Resource
Development" being conducted by an interdisciplinary research
team from the Science and Public Policy Program (S&PP) of
the University of Oklahoma for the Office of Energy, Minerals
and Industry (OEMI), Office of Research and Development (ORD),
U.S. Environmental Protection Agency (EPA). This study is
one of several conducted under the Integrated Assessment
Program established by OEMI in 1975. Recommended by an
interagency task force, the purpose of the Program is to
identify economically, environmentally, and socially accepta-
ble energy development alternatives. The overall purposes
of this particular study were to identify and analyze a
broad range of consequences of energy resource development
in the western U.S. and to evaluate and compare alternative
courses of action for dealing with the problems and issues
either raised or likely to be raised by development of these
resources.
The Project Director was Irvin L.(Jack) White, Assistant
Director of S&PP and Professor of Political Science, at the
University of Oklahoma. White is now Special Assistant to
Dr. Stephen J. Gage, EPA's Assistant Administrator for
Research and Development. Michael D. Devine, now Project
Director, supervised the final stages of producing this
report.
R. Leon Leonard and Martha W. Gilliland have had pri-
mary management responsibility for producing this report.
Leonard, now a Senior Scientist with the Radian Corporation
in Austin, Texas, was a Co-Director of the research team,
Associate Professor of Aeronautical, Mechanical, and Nuclear
Engineering and a Research Fellow in S&PP while the study
was being conducted. Gilliland is Executive Director of
Energy Policy Studies, Inc., El Paso, Texas.
Steven E. Plotkin, now with the Office of Technology
Assessment, was the EPA Project Officer.
v
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Other S&PP team members are: Michael A. Chartock, a
Co-Director of the research team and Associate Professor of
Ecology; Steven C. Ballard, Assistant Professor of Political
Science; Edward J. Malecki, Assistant Professor of Geography;
Edward B. Rappaport, Visiting Assistant Professor of Geogra-
phy; Frank J. Calzonetti, Research Associate in S&PP; Timothy
A. Hall, Research Associate in S&PP; Gary D. Miller, Graduate
Research Assistant (Civil Engineering and Environmental
Science); Mark S. Eckert, Graduate Research Assistant (Geogra-
phy) ; Dipak Kumar Sinha, Graduate Research Assistant (Aeronau-
tical, Mechanical and Nuclear Engineering); and Michael E.
Vanderpool, Graduate Research Assistant (Aeronautical,
Mechanical, and Nuclear Engineering). Professors Ballard,
Devine, Malecki, and Rappaport are also Research Fellows in
S&PP.
Radian Corporation, Austin, Texas, has been a major
contributor to this impact analysis report. C. Patrick
Bartosh, Program-Manager, has directed the Radian effort.
Radian Personnel who contributed to the study are: B. Russ
Eppright, Thomas W. Grimshaw, Milton Owen, Ken Choffel,
Timothy J. Wolterink, Jim Sherman, James L. Machin, Dennis
D. Harver, David Cabe, Sam A. Gavande, W.F. Holland, Carl
Heinz Michelis, and Michael W. Hooper.
Water Purification Associates, Cambridge, Massachusetts,
conducted a study of water requirements for steam-electric
power generation and synthetic fuel plants; and the Center
for Advanced Computation, the University of Illinois at
Urbana-Champaign conducted a study of route specific costs
comparisons of alternative transportation modes. Results of
both studies have contributed to this report.
Several persons no longer with S&PP or Radian partici-
pated in the early stages of the research upon which this
report is based. Three are now in graduate school at other
universities: Gary N. Bloyd at Carnegie-Mellon University,
Lori L. Serbin at Ohio University, and Patrick Kangas at the
University of Florida. Gerald M. Clancy, William D. Conine
and E. Douglas Sethness, Jr., have moved from Radicin to
other corporate positions.
VI
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ABSTRACT
This is the final impact analysis report of a three-year tech-
nology assessment of the development of six energy resources (coal,
geothermal, natural gas, oil, oil shale, and uranium) in eight west-
ern states (Arizona, Colorado, Montana, New Mexico, North Dakota,
South Dakota, Utah, Wyoming) during the period from the present to
the year 2000. Volume I describes the purpose of the study and sum-
marizes the results and conclusions of the analysis. In Volume II,
more detailed analytical results are presented. Six chapters report
on the analysis of site-specific impacts of deploying typical energy
resource development technologies at sites representative of the
kinds of conditions likely to be encountered in the eight-state
study area. A seventh chapter of Volume II identifies localized
impacts, which do not differ significantly from site to site. A
last chapter focuses on regional impacts likely to occur across the
eight states if energy resources are developed at two different
levels from the present to the year 2000. In addition to these two
volumes of the Impact Analysis Report, the Policy Analysis Report
and the Energy Resource Development Systems Report are published
separately.
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OVERALL TABLE OF CONTENTS
FOR
ENERGY FROM THE WEST: IMPACT ANALYSIS REPORT
VOLUME I
Page
Foreword
Preface
Abstract
List of Figures x-t-t-t
List of Tables x^-c-t
List of Acronyms and. Abbreviations xv-t
Conversion Table x-tx
Acknowledgements xx
PART I : INTRODUCTION 1
CHAPTER 1: AN INTRODUCTION TO WESTERN ENERGY RESOURCE
DEVELOPMENT 2
CHAPTER 2: STRUCTURE OF THE STUDY 15
CHAPTER 3: THE IMPACTS OF WESTERN ENERGY RESOURCE
DEVELOPMENT: SUMMARY AND CONCLUSIONS 41
VOLUME II
PART II: SITE-SPECIFIC AND REGIONAL IMPACT ANALYSIS 160
CHAPTER 4: THE IMPACTS OF ENERGY RESOURCE DEVELOPMENT
AT THE KAIPAROWITS/ESCALANTE AREA 169
CHAPTER 5: THE IMPACTS OF ENERGY RESOURCE DEVELOPMENT
AT THE NAVAJO/FARMINGTON AREA 268
CHAPTER 6: THE IMPACTS OF ENERGY RESOURCE DEVELOPMENTS
AT THE RIFLE AREA 383
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Table of Contents (Continued)
CHAPTER 7: THE IMPACTS OF ENERGY RESOURCE DEVELOPMENT
AT THE GILLETTE AREA 491
CHAPTER 8: THE IMPACTS OF ENERGY RESOURCE DEVELOPMENT
AT THE COLSTRIP AREA 612
CHAPTER 9: THE IMPACTS OF ENERGY RESOURCE DEVELOPMENT
AT THE BEULAH AREA 722
CHAPTER 10: LOCALIZED IMPACTS 822
CHAPTER 11: REGIONAL IMPACTS 914
GLOSSARY 1092
-LK
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TABLE OF CONTENTS
VOLUME I
Page
Foreword
Preface
Abstract
List of Figures
List of Tables
List of Acronyms and Abbreviations
Conversion Table
Acknowledgements xx
PART I: INTRODUCTION 1
CHAPTER 1: AN INTRODUCTION TO WESTERN ENERGY RESOURCE
DEVELOPMENT 2
1.1 INTRODUCTION TO THE WESTERN ENERGY STUDY 2
1.2 THE CONTEXT OF WESTERN ENERGY RESOURCE DEVELOPMENT 4
1.3 ORGANIZATION OF THIS REPORT 14
CHAPTER 2: STRUCTURE OF THE STUDY 15
2.1 INTRODUCTION 15
2.2 CONCEPTUAL FRAMEWORK 15
2.3 THE SCENARIOS 16
2.4 TECHNOLOGIES FOR DEVELOPING WESTERN ENERGY
RESOURCES 19
2.4.1 Coal Development Technologies 23
2.4.2 Coal Mining 23
2.4.3 Coal-Fired Steam-Electric Power Plants 24
2.4.4 Coal Gasification 27
2.4.5 Coal Liquefaction 30
2.4.6 Coal Transportation 30
2.4.7 Oil Shale Development Technologies 31
2.4.8 Underground Oil Shale Mining 31
2.4.9 Surface Oil Shale Retorting 33
2.4.10 In. Situ Oil Shale Retorting 33
2.4.11 Uranium Development Technologies 35
2.4.12 Surface Uranium Mining 35
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Table of Contents (Continued) Page
2.4.13 Underground Uranium Mining 36
2.4.14 Solutional Uranium Mining 36
2.4.15 Uranium Milling 37
2.4.16 Oil Development Technologies 38
2.4.17 Conventional Oil Production 38
2.4.18 Enhanced Oil Recovery 38
2.4.19 Natural Gas Development Technologies 39
2.4.20 Geothermal Development Technologies 39
2.4.21 Hot Water Geothermal 39
2.4.22 Hot Dry Rock Geothermal 40
2.4.23 Summary 40
CHAPTER 3: THE IMPACTS OF WESTERN ENERGY RESOURCE
DEVELOPMENT: SUMMARY AND CONCLUSIONS 41
3.1 INTRODUCTION 41
3.2 AIR QUALITY 48
3.2.1 Introduction 50
3.2.2 Variations of Technologies 50
3.2.3 Variations in Existing Conditions 62
3.2.4 Regional Impacts 66
3.2.5 Summary of .Technological and Locational Factors 68
3.3 WATER AVAILABILITY AND QUALITY 71
3.3.1 Introduction 73
3.3.2 Variations Among Technologies 73
3.3.3 Variations in Existing Conditions 83
3.3.4 Regional Impacts 88
3.3.5 Summary of Technological and Locational Factors 92
3.4 SOCIAL AND ECONOMIC 94
3.4.1 Introduction 96
3.4.2 Variations Among Technologies 96
3.4.3 Variations in Existing Conditions 101
3.4.4 Regional Impacts 108
3.4.5 Summary of Technological and Locational Factors 113
3.5 ECOLOGICAL 115
3.5.1 Introduction 116
3.5.2 Variations by Technologies 117
3.5.3 Variations by Existing Conditions 122
3.5.4 Regional Impacts 128
3.5.5 Summary of Technological and Locational Factors 128
3.6 HEALTH EFFECTS 131
3.6.1 Introduction 132
3.6.2 Variations by Technologies 132
3.6.3 Variations in Existing Conditions 141
3.6.4 Summary of Technological and Locational Factors 143
3.7 TRANSPORTATION 145
3.7.1 Introduction 146
3.7.2 Variations Among Technologies 146
3.7.3 Variations Among Existing Conditions 149
xx.
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Table of Contents (Continued Page
3.8 AESTHETICS AND NOISE 151
3.8.1 Introduction 152
3.8.2 Variations by Technologies 152
3.8.3 Variations by Existing Conditions 154
3.8.4 Summary of Technological and Locational Factors 155
3.9 SUMMARY 156
3.9.1 Technological and Locational Factors that Cause
Impacts 156
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LIST OF FIGURES
VOLUME I
LIST OF TABLES
VOLUME I
Page
1-1 The Eight-State Study Area and Six Sites 2
1-2 General Distribution of Coal, Crude Oil/Natural Gas,
Geothermal, Oil Shale, and Uranium Resources in
Eight Western States 7
2-1 A Conceptual Framework for Assessing Physical
Technologies 16
2-2 Dragline Used for Surface Mining Coal 21
2-3 Continuous Miner for Underground Mining of Coal 22
2-4 Simplified Schematic of a Steam Power Plant 25
2-5 Wet Forced Draft Cooling Towers 26
2-6 Schematic of a Lurgi Gasifier 29
2-7 Oil Shale Room-and-Piliar Mining 32
2-8 Simplified Drawing of an Operating Modified In. Situ
Oil Shale Retort 34
3-1 Energy Resource Development 42
Page
1-1 Development Alternatives 3
1-2 Proven Reserves of Six Energy Resources in the
Eight-State Study Area 5
1-3 Federal and Indian Lands in the Eight-State Study Area 8
2-1 Site-Specific Energy Developments 17
2-2 Regional Energy Developments 20
2-3 Surface Coal Mining Data 24
2-4 Underground Coal Mining Data 27
2-5 Coal Fired Power Pl-ant Data 27
2-6 Coal Gasification Plant Data 28
2-7 Coal Liquefaction Plant Data 30
2-8 Underground Oil Shale Mine Data 31
2-9 Surface Oil Shale Retorting Data 33
2-10 Modified _Tn. Situ Oil Shale Facility Data 35
2-11 Surface Uranium Mining Data 36
2-12 Underground Uranium Mining Data 36
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List of Tables (Continued) Page
2-13 Solutional Uranium Mining Data 37
2-14 Uranium Milling Plant Data 37
2-15 Conventional Oil Production Data 38
2-16 Steam Flooding Enhanced Oil Recovery Data 38
2-17 Natural Gas Production Data 39
2-18 Hot Water Geothermal Power Production Data 40
2-19 Hot Rock Geothermal Power Production Data 40
3-1 Site-Specific Energy Development 44
3-2 Regional Energy Developments 46
3-3 Number of Facilities Required for Low Demand Case 47
3-4 Air Emissions for Standard Size Energy Facilities 52
3-5 Air Emissions on an Equivalent Energy Basis 54
3-6 The Effects on Ambient Air Concentrations of Alter-
native Sulfur Dioxide Controls on Power Plants for
the Site-Specific Scenarios 59
3-7 A Comparison of Predicted Peak Ground Level Concentra-
tions of Pollutants from Urban Sources and Power
Plants for the Six Site-Specific Scenarios, 1990 61
3-8 Sulfur Removal Efficiencies Required for Coal-Fired
Power Plants to Meet All Federal and State Sulfur
Dioxide Standards 65
3-9 Projected Emissions in 2000 for the Northern Great
Plains and Rocky Mountain Regions: Low Demand
Scenario 67
3-10 Projected Emissions of Six Western States: Low
Demand Scenario 69
3-11 Summary of Air Quality Problems 70
3-12 Water Consumption by Technology 74
3-13 Water Use Reduction from Alternative Cooling 77
3-14 Water Requirements Associated with Population Increases 79
3-15 Effluents from Energy Conversion Technologies 80
3-16 Total Dissolved Solids in Surface and Groundwater 84
3-17 Water Requirements for Each Technology by Site 85
3-18 Total Solids Residuals for Each Technology by Site 87
3-19 Surface Water Demand and Availability: Year 2000 89
3-20 Projected Regional Solid Residuals and Wastewater:
Year 2000 91
3-21 Summary of Water Problems 93
3-22 Construction and Operational Manpower Requirements
for Energy Facilities 98
3-23 Manpower Requirements for Energy Facilities 99
3-24 Population Increases in Western States After 1975
Due to Energy Development 109
3-25 Projected Local and State Expenditures and Revenues by
the Year 2000 111
3-26 Summary of Social and Economic Problems 114
3-27 Land Use by Technology 118
3-28 Rainfall Averages in the West 124
3-29 Land Use for Surface Coal Mines by Site 124
3-30 Plant Communities and Their Productivity 126
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List of Tables (Continued) Page
3-31 Land Use by Region in the Year 2000 129
3-32 Summary of Ecological Problems 130
3-33 Sulfate Concentrations and Their Health Effects 134
3-34 Peak Oxides of Nitrogen Concentrations for Scenario
Locations 136
3-35 Selected Ambient 3-Hour Hydrocarbon Concentrations
which Result from Urban Expansion and Energy
Facilities 137
3-36 Safety Risks Associated with Energy Facilities
Expressed per Individual 140
3-37 Summary of Technological and Locational Factors
Affecting Health Problems 144
3-38 Impact Causing Factors 157
X.V
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LIST OF ACRONYMS AND ABBREVIATIONS
AC
acre-f t
acre-ft/yr
AOG
AsH 3
AUM
BACT
bbl
bbl/day
bcf
BIA
BLM
BPT
Btu
Btu/bbl
BuRec
CAA
CaC03
cf s
CO
CO 2
dB
dBA
DC
EDA
EHV
EPA
ERDS
ESP
F
FDA
FERC
FGD
FPC
FWPCA
GAG LA
GNP
gpd
gpm
HC
H2S
alternating current
acre-feet
acre-feet per year
associations of government
arsine
animal units per month
best available control technology
barrel(s)
barrel(s) per day
billion cubic feet
Bureau of Indian Affairs
Bureau of Land Management
best practicable technology
British thermal unit
British thermal units per barrel
Bureau of Reclamation
Clean Air Act
calcium carbonate
calcium sulfate
cubic feet per second
carbon monoxide
carbon dioxide
decibel
decibel(s) A-weighted
direct current
Economic Development Administration
extra-high voltage
Environmental Protection Agency
Energy Resource Development Systems
electrostatic precipitator
Fahrenheit
Food and Drug Administration
Federal Energy Regulatory Commission
flue gas desulfurization
Federal Power Commission
Federal Water Pollution Control Act
Governors' Advisory Council on Local Affairs
gross national product
gallons per day
gallons per minute
hydrocarbons
hydrogen sulfide
X.V4.
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kV
kWh
Ibs/ton
LCRB
Ldn
MESA
mg/ฃ
MMcfd
MMgpd
MMscfd
MMtpy
MW
MWe
mph
NAAQS
NC
NH3
NIOSH
NO
NO 2
NOx
NSPS
OPEC
ORV
PAH
pCi/g
PH
ppb
ppm
PSD
psi
psia
Q
Ra-226
Rn-222
SEAS
S02
S&PP
SRI
tcf
TDS
TOSCO
tpd
tpy
TSP
TVA
UCRB
ug
kilovolt(s)
kilowatt-hour(s)
pounds per ton
Lower Colorado River Basin
day-night equivalent sound level
Mining Enforcement and Safety Administration
milligrams per liter
million cubic feet per day
million gallons per day
million standard cubic feet per day
million tons per year
megawatt(s)
megawatt-electric
miles per hour
National Ambient Air Quality Standards
not calculated or not considered
ammonia
ammonium chloride
National Institute of Occupational Safety and
Health
nitric oxide
nitrogen dioxide
oxides of nitrogen
New Source Performance Standards
Organization of Petroleum Exporting Countries
off-road vehicle
polyaromatic hydrocarbons
picocuries per gram
picocuries per liter
acidity/alkalinity
parts per billion
parts per million
prevention of significant deterioration
pounds per square inch
pounds per square inch atmosphere
1015 British thermal units and/or quad(s)
Radium 226
Radon 222 gas
Strategic Environmental Assessment System
sulfur dioxide
Science and Public Policy Program
Stanford Research Institute
trillion cubic feet
total dissolved solids
The Oil Shale Corporation
tons per day
tons per year
total suspended particulates
Tennessee Valley Authority
Upper Colorado River Basin
microgram(s)
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yg/m3 micrograms per cubic meter
UMRB Upper Missouri River Basin
UsOs uranium oxide and/or yellowcake
USGS U.S. Geological Survey
WPA Water Purification Associates
ZDP zero discharge of pollutants
XV/t-CX.
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CONVERSION TABLE
BTU CONTENT OF ENERGY FORMS
Electricity: 1 kVh - 3*13 Btu.
Natural gaป: 1 cubic foot - 1000 Btu.
Petroleum: 1 barrel (bbl) - 42 gallons
crude oil--l bbl - 5.8 million Btu;
distillate fuel1 bbl - 5.8 million Btu;
renldual fuel --1 bbl - 6.3 million Btu;
gasoline1 bbl - 5.3 million Btu;
Uranium1 pound Ujis 3.6 X 101* Btu.
1 million - 10*
1 billion - 10'
1 trillion - 10"
1 Quad - 1014 Btu
1 megawatt - 10' Watts
1 kilowatt - 10' Watts
ENERGY
UNITS
1 joule
1 cal
1 Btu
1 kWh
Joule
1
4.186
1.055 X 10'
3.6 X 10*
cal
2.389 X 10"'
1
2.52 X 10*
9.6 X 10'
Btu
9.48 I 10~*
3.97 X 10"'
1
3.413'X 10'
kWh
2.778 X 10"'
1.163 X 10"'
2.93 X 10"*
1
RATE
UNITS
1 gallon/minute
1 acre-foot/year
Cubic Meter/Tear
1.9898 X 10'
1.2335 X 10'
Gallon /Minute
1
6.2 X 10"*
Acre-Feet /Tear
1.613
1
PRESSURE
UNITS
1 atmosphere
1 pound/sq. inch
atmospheres
1
6.804 X 10"2
kiloRraris/sauare
centimeter
1.033
7.03 X 10~2
pounds oer
square Inch
1.469 X 10'
1
N/m2, Pซ
1.03 X 10s
6S94.76
LEKCTH
UNITS
1 meter
1 yard
1 mile
Meters
1
9.14 X 10"'
1.609 X 10*
Feet
3.28
3.0
5.28 X 10'
Tards
1.093
1
1.76 X 10'
Miles
6.21 X iO~*
5.68 X 10"*
1
WEIGHT
UNITS
1 kllogru
1 metric ton
1 ton (short)
Kllograa
1
1.0 X 10'
9.072 X 102
Pound
2.2046
2.205 X 10'
2.0 X 10'
Metric Ton
1.0 X 10-'
1
9.078 X 10~'
Ton (Short)
1.102 X 10~*
1.102
1
VOLUME
UNITS
1 liter
1 acre- foot
1 Mllon (U.S.)
Liters
1
1.234 X 10*
3.785
Cubic Feet
3.531 x n"2
4,356 X 10*
1.337 X 10"1
Ac re -Feet
8.107 X 10"T
1
3.068 X 10"'
Gallons
2.642 I 10"'
3.259 X 10s
1
AREA
UNITS
1 square aeter
1 square yard
1 acre
1 square mile
Square Meters
1
8.361 X 10"1
4.047 X 10'
2.59 X 10*
Square Feet
r 1.076 X 10
9.0
4.35 X 10*
2.788 X 10'
Square Tards
1.196
1
4.84 X 10'
3.098
Acres
2.471 X 10~*
2.066 X 10~*
1
6.402 X 102
Square Miles
3.86 X 10"'
3.228 X 10~7
1.562 X 10"'
1
atm atmospheres
psi * pounds per square inrh
cal * calorie
N/m1, Pa - Newton per square
Btu - British thermal units
kVh - kilowatt hour
eter, Pascal
X-CX
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ACKNOWLEDGEMENTS
The research reported here could not have been completed
without the assistance of a dedicated administrative support
staff. Members of the staff are an integral part of the inter-
disciplinary team approach employed by the Science and Public
Policy Program. This staff is headed by Janice Whinery, Assis-
tant to the Director, and Nancy Heinicke, Clerical Supervisor.
Staff members are: Ellen Ladd, Cyndy Allison, Patti Mershon,
Brenda Skaggs, Pam Odell, Judy Williams, and Julia Leonard.
Sharon Pursel assisted as Clerical Supervisor in the production
of the draft policy analysis report.
The research support staff is headed by Martha Jordan, Li-
brarian. Research Team Assistants are David Sage, Mary Sutton,
and Diane Dean. Lorna Caraway and Phil Kabrich assisted as Re-
search Team Assistants in the final production of the report.
Nancy Ballard, graphics arts consultant, designed the title
page.
Steven E. Plotkin, EPA Project Officer, and Terry Thoem,
EPA, Denver, have provided continuing support and assistance in
the preparation of this report.
An Advisory Committee and numerous individuals, corporations,
government agencies, and public interest groups have assisted the
team at various stages in the preparation of the report. The
names of the members of the Advisory Committee are listed below.
Others who have assisted are far too numerous to list here.
Needless to say, no member of the Advisory Committee, consultant,
or any other individual or agency is responsible for the content
of this progress report. The report is the sole responsibility
of the Science and Public Policy interdisciplinary research team
conducting this study.
Mr. John Bermingham Dr. Thadis W. Box
Attorney Dean
Denver, Colorado College of Environmental
(formerly Regional Represen- Studies
tative for the secretary, U.S. Utah State University
Department of Commerce) Logan, Utah
xx
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Governor Jack Campbell
President
Federation of Rocky Mountain
States
Denver, Colorado
Mr. Bill Conine
Environmentalist
Energy MineralsU.S. and
Canada
Mobil Oil Corporation
Denver, Colorado
Ms. Sharon Eads
Attorney
Native American Rights Fund
Boulder, Colorado
Mr. Michael B. Enzi
Mayor
Gillette, Wyoming
Mr. Lionel S. Johns
Program Manager
Office of Technology
Assessment.
U.S. Congress
Washington, D.C.
Mr. Kenneth Kauffman
Chairman
Water for Energy Management
Team
U.S. Department of the
Interior
Engineering and Research
Center
Denver, Colorado
Mr. S.P. Mathur
Division of Regional
Assessment
U.S. Department of Energy
Washington, D.C.
(formerly ERDA Representative
to the Water Resources Council)
Mr. Leonard Meeker
Attorney
Center for Law and Social
Policies
Washington, D.C.
Dr. Richard Meyer
ABT Associates
Anglewood, Colorado
(formerly Acting Director,
Western Governors' Energy
Policy Office)
Dr. Raphael Moure
Industrial Hygienist
Oil, Chemical, and Atomic
Workers Union
Denver, Colorado
Mr. Bruce Pasternack
Booz, Allen, Hamilton
Bethesda, Maryland
(formerly Assistant Admini-
strator, Policy and Program
Evaluation, Federal Energy
Administration, Washington,
D.C.)
Mr. Robert Richards
Kaiser Engineers
Oakland, California
Mr. H. Anthony Ruckel
Regional Lawyer
Sierra Club Legal Defense
Fund
Denver, Colorado
Mr. Warren Schmechel
President and Chief
Operating Officer
Western Energy Company
Butte, Montana
Mr. Vernon Valantine
Colorado River Board of
California
Los Angeles, California
XXX,
-------
Three subcontractors contributed to the impact analyses and
background studies used in this report: Radian Corporation,
Austin, Texas; Water Purification Associates, Cambridge, Massa-
chusetts; and the Western Governors' Policy Office, Denver,
Colorado.
Others who have contributed to specific analyses include:
Mr. Donald S. Cooper
Principal Energy Analyst
International Research and
Technology Corporation
McLean, Virginia
Dr. James M. Goodman
Associate Professor of
Geography
University of Oklahoma
Dr. Arnold G. Henderson
Professor of Architecture
University of Oklahoma
Dr. Daniel B. Kohlhepp
Assistant Professor of
Finance
University of Oklahoma
Mr. Richard Meyer
Program Manager
International Research and
Technology Corporation
McLean, Virginia
-------
PART I: THE ENERGY FROM THE WEST STUDY
INTRODUCTION
The three chapters in this part of the report: introduce
the "Energy From the West" study and describe the general context
within which energy resource development in the West will occur
(Chapter 1); describe the analytical structure of the study and
the energy technologies considered (Chapter 2); and present a sum-
mary of the results of the analysis of impacts likely to occur
when western energy resources are developed (Chapter 3).
-------
CHAPTER 1
AN INTRODUCTION TO WESTERN ENERGY RESOURCE DEVELOPMENT
1.1 INTRODUCTION TO THE WESTERN ENERGY STUDY
This impact analysis report is a product of a three-year
"Technology Assessment of Western Energy Resource Development"
being conducted for the Office of Energy, Minerals and Industry,
Office of Research and Development, U.S., Environmental Protection
Agency. The study is being conducted by an interdisciplinary re-
search team from the Science and Public Policy Program (S&PP),
University of Oklahoma, with the assistance of two major subcon-
tractors (Radian Corporation, Austin, Texas, and Water Purification
Associates, Cambridge, Massachusetts), several other subcontrac-
tors, consultants, and an advisory committee.
The overall purpose of the study is to attempt to determine
what the consequences of western energy resource development will
be and how public and private policymakers night deal with them.
Specific objectives are to:
Identify and describe
energy development al-
ternatives ;
Determine and analyze
impacts;
Identify and define pol-
icy problems and issues;
Identify, evaluate and
compare alternative pol-
icies and implementation
strategies;
Identify and describe
research and data needs.
The study focuses on the
development of six energy re-
sources in the eight-state
area and at the six sites
shown in Figure 1-1. Coal,
FIGURE 1-1:
THE EIGHT-STATE STUDY
AREA AND SIX SITES
-------
oil shale, uranium, oil, natural gas and geothermal are the six
energy resources being considered. The technological alternatives
for developing these resources are listed in Table 1-1. (These
alternatives are described in Chapter 2.) The time period during
which the consequences of development are being assessed extends
to the year 2000.
Technological alterna-
tives and the laws and regula-
tions which regulate and con-
trol their construction and
operation are described in de-
tail in Energy From the West:
Energy Resource Development
Systems.1An earlier progress
report presented the prelimi-
nary results of an analysis of
impacts likely to occur when
these technologies are deployed
at specific sites and to pro-
duce specified quantities of
energy on a region-wide basis.2
The problems and issues likely
to arise as a consequence of
this development together with
the results of an analysis of
alternative policies and strat-
egies for dealing with them are
reported in Energy From the
West; Policy Analysis Report.3
Two work plans or research de-
sign reports describe our
interdisciplinary team approach
to technology assessment as a
kind of applied policy analysis,
the analytical structure of the
study, and the analytical
TABLE 1-1: DEVELOPMENT ALTERNATIVES1
Coal:
Surface and Underground Mining
Direct Export by Unit Train and
Slurry Pipeline
Electric Power Generation
Gasification
Liquefaction
Transportation by Pipeline and EHV
Oil Shale:
Underground Mining
Surface Retorting
Modified In-Situ
Transportation by Pipeline
Uranium:
Surface, Underground, and
Solutional Mining
Milling
Transportation by Truck
Oil and Natural Gas:
Conventional Drilling and Production
Enhanced Oil Recovery
Transportation by Pipeline
Geothermal
Hot Water and Hot Rock
Electric Power Generation
Transportation by EHV
EHV = extra-high voltage
Irvin L., et al. Energy From the West; Energy Re-
source Development Systems Report. Washington, D.C.: U.S., En-
vironmental Protection Agency, forthcoming.
2White, Irvin L., et al. Energy From the West: A Progress
Report of a Technology Assessment of Western Energy Resource
Development,4 vols.and Executive Summary.Washington,D.C.:
U.S., Environmental Protection Agency,1977.
3White, Irvin L., et al. Energy From the West; Policy Analy-
sis Report. Washington, D.C.: U.S., Environmental Protection
Agency, forthcoming.
-------
methods and techniques we have used.1 This report presents the
final results of our impact analyses and represents an extension
and refinement of the results presented in our Energy From the
West progress report.
1.2 THE CONTEXT OF WESTERN ENERGY RESOURCE DEVELOPMENT2
As now articulated, our major national energy policy objec-
tives are to dedrease dependence on foreign energy sources and
to reduce imports to a more economically acceptable level. In
the short- and mid-term future, this translates into an emphasis
on increasing domestic production, particularly fossil fuels.
Given its substantial energy resources, the western U.S. is ex-
pected to be a major contributor to the increased production of
these resources.
As noted earlier, six western energy resources are being
considered in this study: coal, oil shale, uranium, oil, natural
gas and geothermal. The quantity of each of these in the region
is shown in Table 1-2 and their general distribution in the eight-
state study area in Figure 1-2. Coal and oil shale are the most
abundant of the six. In fact, approximately 36 percent of all
U.S. coal is located in the study area; virtually all the nation's
high grade oil shale is located in the Green River Formation in
western Colprado, Utah, and Wyoming; and almost all of the na-
tion's high grade uranium ore is located in the eight states,
primarily in New Mexico and Wyoming.
As shown in Table 1-3, the federal government and Indians
own almost 45 percent of the total land in the eight-state study
area. Together, the federal government and Indians own more than
half the land in Arizona, Utah, and Wyoming and more than a third
in Colorado, Montana, and New Mexico.
Data on resource ownership are more difficult to obtain.
However, it appears that the federal government owns about half
the coal, geothermal, and uranium, and about 80 percent
:White, Irvin L., et al. First Year Work Plan for a Tech-
nology Assessment of Western Energy Resource Development. Wash-
ington, D.C. : U.S., Environmental Protection Agency, 1976; and
White, Irvin L., et al. Work Plan for Completing a Technology
Assessment of Western Energy Resource Development. Washington,
D.C.: U.S., Environmental Protection Agency, 1978.
2See White, Irvin L., et al. Energy From the West; Policy
Analysis Report. Washington, D.C.: U.S., Environmental Protec-
tion Agency, forthcoming, for a more extensive description of the
national and regional context of western energy resource devel-
opment .
-------
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Geothermal
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FIGURE 1-2:
GENERAL DISTRIBUTION OF COAL, CRUDE OIL/NATURAL
GAS, GEOTHERMAL, OIL SHALE, AND URANIUM RESOURCES
IN EIGHT WESTERN STATES
-------
TABLE 1-3:
FEDERAL AND INDIAN LANDS IN
THE EIGHT-STATE STUDY AREA
STATE
Arizona
Utah
Wyoming
New Mexico
Colorado
Montana
South Dakota
North Dakota
Total
TOTAL AREA
(Thousands of Acres)
72,688
52,697
62,343
77,766
66,486
93,271
48,882
44,452
518,585
PERCENT
FEDERAL
44
66
48
33
36
30
7
5
35
1 PERCENT
INDIAN
30
7
3
8
1
6
12
5
9
PERCENT FEDERAL
AND INDIAN
74
73
51
41
37
36
19
10
44
Sources: U.S., Department of the Interior, Bureau of Land Management.
Public Land Statistics 1976. Washington, D.C.: Government Printing
Federal and State
Office, 1977, p. 10; and U.S., Department of Commerce.
Indian Reservations and Indian Trust Areas. Washington, D.C.:
ment Printing Office, 1974.
Govern-
of the oil shale resources in the eight-state area. The 271 In-
dian reservations in the U.S. are estimated to contain from 10
to 16 percent of the nation's coal reserves and one-third of all
lands held for uranium exploration and development. Most of these
resources are located on a few of the approximately 50 Indian
reservations located in our study area.l For example, Indian
lands in Colorado, New Mexico, and Wyoming account for 45 percent
of all lands held for uranium exploration and development. Over
85 percent of the nation's proven uranium reserves are located
in these three states.2
JSee U.S., Federal Trade Commission, Bureau of Competition.
Report to the Federal Trade Commission on Mineral Leasing on
Indian Lands. Washington, D.C.: Federal Trade Commission, 1975.
2Bendix Field Engineering Corp. Survey of Lands Held for
Uranium Exploration, Development and Production in Fourteen West-
ern States in the Six Month Period Ending December 31, 1.976,
GJBX-33(77). Grand Junction, Colo.: U.S.,, Energy Research and
Development Administration, 1977, p. 1; arid U.S., Energy Research
and Development Administration, Grand Junction Office. Statis-
tical Data of the Uranium Industry, GJO-100(77). Grand Junction,
Colo.: Energy Research and Development Administration, 1977,
p. 61.
8
-------
Coal production in the study area exceeded 115 million tons
in 1975, more than 85 percent of which was surface-mined..1 In
addition to being low in sulfur content, many western coals occur
in thick seams near the surface, which also enhances the attrac-
tiveness of these coals to developers. As a result, the number
of surface coal,mines in the West has increased during the past
five years, while the number of underground mines has remained
relatively unchanged.
Demonstrated oil shale reserves in the study area are esti-
mated at 464 billion barrels (bbl).2 As with coal, the federal
government owns the major share of this resource.3 However, un-
like coal, no commercial oil shale production has yet taken place.
In spite of the large quantity of oil shale resources, difficul-
ties in planning, mining, and efficiently and economically con-
verting the resource to a usable fuel have restrained develop-
ment . k
Although highly dependent on ore quality and recoverability,
uranium reserves in the study area are estimated to be above 600
thousand tons of yellowcake. Large uncertainties surround the
availability of uranium resources, most of which are located in
northwestern New Mexico and in Wyoming. Subsurface mineral rights
for about two-thirds of the lands thought to contain significant
uranium resources are held by the federal government. In 1975,
11 thousand tons of yellowcake were produced in the area. This
represented more than 90 percent of total U.S. production.
1U.S., Federal Energy Administration. 1977 National Energy
Outlook, Draft. Washington, D.C.: Federal Energy Administration,
January 15, 1977, Vol. 1, p. 23.
2University of Oklahoma, Science and Public Policy Program.
Energy Alternatives: A Comparative Analysis. Washington, D.C.:
Government Printing Office, 1975, pp. 2-7. This total represents
only reserves of the highest quality category. This is virtually
all of the nation's demonstrated oil shale reserves.
3Some ownership is in dispute and will probably have to be
determined by the courts.
"Science and Public Policy. Energy Alternatives. Chapter 2.
Oil shale has been developed in other countries.
5U.S., Energy Research and Development Administration, Grand
Junction Office. Statistical Data of the Uranium Industry, GJO-
100(77). Grand Junction, Colo.: Energy Research and Development
Administration, 1977, p. 61.
-------
Oil production from the West in 1976 was about 214 million
bbl, a large percentage of the remaining proved western reserves
of 2.1 billion bbl.1 Gas production in the West was about 1.8
trillion cubic feet (tcf) in 1976 or almost 10 percent of the
remaining reserves of 19.8 tcf. At current consumption rates,
this quantity of gas would meet national needs for a single year.:
Although none of the Rocky Mountain and Great Plains states
is using geothermal energy commercially, exploration and experi-
mental development are taking place in several locations. Re-
sources have not been accurately characterized, and estimates
vary from as little as one thousand megawatts-electric (MWe)3 of
recoverable generating capacity to as high as 150 million MWe for
the entire West.1* Recent estimates of western reserves suggest
an electrical capacity of 43 thousand MWe, and most of these re-
sources are owned by the federal government.5
The actual pattern and development rates of the western
energy resources described above will be contingent on a wide
range of economic, social, and political factors such as energy
demand, price, availability of development capital, availability
of raw materials and skilled manpower, environmental policies
and regulations, competing land uses, and attitudes toward devel-
opment. Thus, although not the focus of this study, identifica-
tion of some of these factors is important to understanding the
Bureau of National Affairs. Energy Users Report, Reference
File, R81:0623, (September 28, 1977).
2Ibid., p. 81: 0601.
3A megawatt-electric is one million watts (one thousand kilo-
watts) and is a standard measure of the amount of power, as elec-
tricity, that can be produced by a facility at any one time.
4Muffler, L.D.P., and D.E. White. Geothermal Energy Re-
sources of the U.S., Geological Survey Circular 650. Washington,
D.C.: Government Printing Office, 1972, p. 10; and Rex, Robert W.,
and David J. Howell. "Assessment of U.S. Geothermal Resources,"
in Kruger, Paul, and Carel Otte, eds. Geothermal Energy; Re-
sources, Production, and Stimulation. Stanford, Calif.: Stan-
ford University Press, 1973, p. 63.
5Assuming a conversion efficiency of ten percent, a reser-
voir lifetime of fifty years and reserve estimates as reported
in Table 1-2.
10
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context within which western energy development is and will con-
tinue to take place.1
Energy demand is affected by (among other things) price,
availability, level of economic activity, and public perceptions.
Demand projections indicate increases, although at lower growth
rates than in the past.2 However, the demand for electricity is
expected to continue to grow at a rate almost twice as fast as
overall energy demand, and a gradual shift from the use of oil
and gas to coal and nuclear materials for generating electricity
is expected.3
The price of oil has largely been a product of the current
seller's market in petroleum created by worldwide increases in
oil consumption, decreasing production in consuming nations, and
a greater ability of producing nations to act in concert. The
Organization of Petroleum Exporting. Countries (OPEC) has now gained
control over the majority of oil producing operations and effec-
tively determines the price of oil and, thereby, the price of many
other energy resources.1*
Recent oil price increases have made coal and uranium more
economically attractive fuels and have stimulated interest in oil
shale and geothermal resources, as well as in enhanced recovery
of domestic oil. For example, the U.S. and several other countries
1 These factors are discussed in Chapters 1 and 2 of White,
Irvin L., et al. Energy From the West: Policy Analysis Report.
Washington, D.C.: U.S.,Environmental Protection Agency, forth-
coming.
2The demand for energy has increased at a rate of about 7
percent per year over the past decade. During the past 2 years
however, U.S. energy demand has actually diminished, from 74 quad-
rillion British thermal units (Btu's) per year in 1973 to 71 quad-
rillion Btu's by the end of 1975. See U.S., Federal Energy Admin-
istration. "Overview." Monthly Energy Review, March 1976, p. 13.
The 1976 figures show that demand for energy was back up to over
74 quadrillion Btu's; 1977 demand was over 75 quadrillion Btu's.
For the 1976 and 1977 estimates see U.S., Federal Energy Adminis-
tration. "Overview." Monthly Energy Review, May 1978, p. 8.
3The price of OPEC 'oil varied from $1.89 to $2.00 per bbl
between 1955 and 1970. In January 1972, the price was $2.18; in
October 1973, it rose to $5.12. In January 1976, following the
October embargo, OPEC oil was $11.65. In January 1976, the price
was about $14.00 per bbl. In January 1978 OPEC oil was approxi-
mately $14.30 per bbl.
11
-------
have greatly increased their coal exports in recent years.1 How-
ever, importing uranium for domestic use has been prohibited since
the mid-1960's.2 Although this policy has resulted in relatively
high U.S. uranium prices, it has also provided stability for ura-
nium mining operations in the Rocky Mountains and the Northern
Great Plains.3
While high energy prices have stimulated new interest in
western energy resources, there is no guarantee that prices will
remain high. As noted, energy prices are being supported through
the efforts of an international cartel, OPEC, and do not directly
reflect production costs. Future decreases in price are quite
possible, leading investors to be wary of investing in new pro-
jects (such as coal gasification), even though such projects might
appear to be profitable at current prices. Risk factors such as
these may significantly impede the availability of capital for
certain kinds of western energy resource development.
The availability of raw materials, manpower, and equipment
will also help to determine development schedules and production
rates for western energy resource development. For example, many
resource-rich sections of the study area have marginal water sup-
plies. Thus, meeting the water needs of large-scale energy devel-
opments could result in inadequate water supplies for some users.
Large and/or rapid resource developments can be constrained
by available skilled manpower pools and equipment problems. These
problems might range from a shortage of mining engineers to the
questionable ability of industry to meet the short-term need for
large numbers of specialized pieces of equipment (such as drag-
lines and high-pressure vessels for gasification and liquefaction
facilities).
A wide range of environmental and social factors will also
influence decisions to develop western U.S. energy resources.
For example, environmental quality has been described as both a
major reason for and a potential obstacle to development in the
region. Low-sulfur western coal has been an attractive substitute
lln contrast to oil, trade in coal has been based on bilat-
eral agreements between private purchasers and producers.
2Yager, Joseph A., and Eleanor B. Steinberg. Energy and U.S.
Foreign Policy, a report to the Energy Policy Project of the Ford
Foundation. Cambridge, Mass.: Ballinger, 1974, p. 21.
3Ibid.
12
-------
for more polluting fuels.1 Conversely, the "Big Sky" of the
Northern Great Plains and the undisturbed vistas of the Rocky
Mountains and canyonlands are widely recognized as national re-
sources. In fact, the Congress has enacted legislation intended
to maintain or improve the quality of such resources by, for exam-
ple, establishing prevention of significant deterioration standards
for air.2
Western attitudes toward energy development also help to set
the context of western energy resource development. It is diffi-
cult to generalize about westerner's attitudes. Environmental
quality, scenic beauty, and present lifestyle are obviously widely
held values. But so are higher personal incomes, more job oppor-
tunities, more amenities, easier access to medical services, and
a variety of other benefits associated with energy resource devel-
opment. Both kinds of values can be and apparently often are held
by the same person. Since these values are often in conflict, it
is difficult for westerners both individually and collectively to
be consistent in expressing their attitudes toward energy devel-
opment.
However, there do seem to be several consistent themes among
westerners. For example, outside the large metropolitan areas
there is a general opposition to the intervention of outsiders
whether the intervener be the federal government or the Sierra
Club. Westerners generally seem to believe that they should be
the ones to decide their futures; for example, public officials
in southern Utah believe they should decide whether maintaining
75-mile visibility is more or less highly valued than the antici-
pated economic and fiscal benefits of energy resource development.3
The actual level of western energy resource development,
where development will take place, and what technologies are used
to develop it will be determined by these and numerous other fac-
tors, national and state energy policies, and other considerations.
The brief discussion here is intended to provide only a very gen-
eral introduction to the context within which development is and
However, the 1977 Clean Air Act Amendments require "best
available control technology" be used regardless of the sulfur
content of the coal, thus lessening, perhaps eliminating, the
advantage low sulfur coal has had. Clean Air Act Amendments of
1977, Pub. L. 95-95, 91 Stat. 685.
2Ibid.
3This is the position strongly expressed to members of the
S&PP Research Team who visited the area.
13
-------
will be taking place. A more extended discussion is presented in
Chapters 1 and 2 of the Energy From the West policy analysis re-
port. 1
1.3 ORGANIZATION OF THIS REPORT
The two remaining chapters in Part I describe the development
alternatives being assessed and summarize our impact analysis
findings. Six of the eight chapters in Part II report the results
of impact analyses for our site-specific scenarios: Colstrip,
Montana; Beulah, North Dakota; Gillette, Wyoming; Rifle, Colorado;
Kaiparowits/Escalante, Utah; and Navajo/Farmington, New Mexico.
The seventh chapter in Part II, Chapter 10, discusses local im-
pacts which either do not differ significantly from site to site
or which cannot be dealt with on a site-specific basis because so
little is known about them. The final chapter in Part II reports
the results of our aggregate analyses of impacts in the eight-
state study area.
JWhite, Irvin L., et al. Energy From the West; Policy
Analysis Report. Washington, D.C.: U.S., Environmental Protec-
tion Agency, forthcoming.
14
-------
CHAPTER 2
STRUCTURE OF THE STUDY
2.1 INTRODUCTION
As indicated briefly in Chapter 1, this study of western
energy resource development focuses on the development of six
resources in eight western states. This chapter describes the
conceptual framework used to structure the study, the site-
specific and regional scenarios analyzed, and the technologies
examined.
2.2 CONCEPTUAL FRAMEWORK
The conceptual framework used in this technology assessment
is shown in Figure 2-1. This systems diagram shows that impacts
are a product of the interaction of a technology and "existing
conditions." When sited, constructed, and operated, a technology
creates input demands, such as for land, water, capital, labor,
and services, and produces outputs, including a product such as
electricity, and residuals or byproducts such as air and water
pollutants. These inputs and outputs interact with the existing
social and physical environment to produce impacts. The existing
conditions include such things as the availability and current
uses of water, meteorological conditions, the capacity of existing
community services and facilities, the economy, and current siting
and air quality policies and regulations. Impacts1 include such
things as changes in ambient air quality, the availability of
housing, employment opportunities, and tax revenues. Impacts can
be either costs or benefits.
The systems diagram in Figure 2-1 shows that, on the basis
of individual and/or group perceptions, some of these impacts
are identified as problems and issues which policymakers, both
public and private, must attempt to resolve. In choosing among
the range of available responses, policymakers are limited by a
variety of economic, legal, technological, social, and other
constraints.
xThe term impact is not a pejorative as used in this study.
It includes effects which can be defined as either benefits or
costs.
15
-------
ป
Outputs
.
-
>
Impacts
h
>
1 Problems
and
Issjes
^
>
Policy
Alternatives &
Implementation
Strategies
FIGURE 2-1:
A CONCEPTUAL FRAMEWORK FOR ASSESSING
PHYSICAL TECHNOLOGIES
A more detailed description of this conceptual framework
and how it has been applied in this study is presented in our
First Year Work Plan for a Technology Assessment of Western
Energy Resource Development.1The brief description here is
limited to showing why we structured the study as we did. This
structure is described in the following section.
2.3 THE SCENARIOS
Seven energy resource development scenarios were used to or-
ganize various combinations of energy resource development alter-
natives and levels of development between 1975 and the year 2000,
and to structure the impact analyses described in this report.
Six of these scenarios are site-specific and combine typical en-
ergy development technologies and sites representative of the
range of existing conditions found in the study area. The seventh
scenario specifies two levels of development for the entire study
area and the combinations of technologies and resources used to
produce these quantities of energy.
Table 2-1 identifies the six sites selected and lists the
hypothetical energy developments considered and the development
schedule for each site. As the table shows, several process
mixes, development schedules, and levels of development have
been included in the scenarios. Our objective was to analyze a
variety of technology and location combinations as a basis for
^hite, Irvin L., et al. First Year Work Plan for a Tech-
nology Assessment of Western Energy Resource Development.
Washington,D.C.:U.S., Environmental Protection Agency, 1976.
16
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formulating generalizations about the impacts that can be expected
to occur when western energy resources are developed (see the
Introduction to Part II) .
Table 2-2 indicates the total quantities of energy required
from the western U.S. at two national levels of energy consump-
tion in 1980, 1990, and 2000. This table also shows the role of
each of these six resources in producing these quantities.1
The technological alternatives included in both the site-
specific and eight-state area scenarios are described in the
following section.
2.4 TECHNOLOGIES FOR DEVELOPING WESTERN ENERGY RESOURCES
In this section, we describe the technologies which are
considered in this study. These technologies were selected as
being typical of the technologies we believe are likely to be
deployed for developing western energy resources during the
next 25 years. The technologies deployed are described in the
Energy Resource Development Systems (ERDS)2 Report which are part
of the background and supporting materials developed to support the
impact and policy analyses. The ERDS description for each of the
six resources includes an overview of technological alternatives
for exploration, extraction, conversion, and environmental con-
trol. These descriptions, written for well-informed laypersons,
specify input materials and personnel requirements, outputs and
residuals (byproducts), energy requirements, and internalized
economic costs. Input, output, residual, and economic costs
data from the ERDS are introduced at the appropriate place in
each of the impact analysis chapters in this report.
1In our progress report, we used three levels of development
or cases based on the Stanford Research Institute's (SRI) inter-
fuel competition model. The model and the three cases are de-
scribed in Chapter 12 of our progress report (White, Irvin, L.,
et al. Energy From the West: A Progress Report of a Technology
Assessment of Western Energy Resource Development. Washington,
D.C.: U.S., Environmental Protection Agency, 1977) and in more
detail in SRI Decision Analysis Group, Cazalet, Edward, et al.
A Western Regional Energy Development Study: Economics, Final Re-
port, 2 vols. Menlo Park, Calif.: Stanford Research Institute,
1976. Only two levels of development are considered in this re-
port. These modify the SRI cases by reducing the level of oil
shale development and adding geothermal (which is not included in
the SRI model). Table 2-2 reflects these changes.
2White, Irvin L., et al. Energy From the West: Energy Re-
source Development Systems Report. Washington, D.C.: U.S., En-
vironmental Protection Agency, forthcoming.
19
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The descriptions of the technologies in this section are much
less detailed than those presented in the ERDS Report. The tech-
nologies will be described by resource in the following sequence:
coal, oil shale, uranium, oil, gas, and geothermal. This descrip-
tion will include a brief characterization of the technology and
information on the size, efficiency, and load factor which are
considered typical and which are assumed in our impact analyses.1
2.4.1 Coal Development Technologies
We have analyzed the impacts of coal mining, coal-fired steam
electric power plants, Lurgi and Synthane coal gasification, Syn-
thoil coal liquefaction, and unit train and slurry pipeline coal
transportation .
2.4.2 Coal Mining
Two types of coal mining are considered: surface and under-
ground. Area surface mining is assumed at four of the six local
sites examined. Surface mining begins with the removal and stor-
age of topsoil from the area to be mined. (Topsoil is stored so
that it can be replaced during reclamation.) Overburden, the rock
and soil material between the surface and the coal seam, may be
loosened by blasting and removed using a dragline. The dragline,
usually electrically powered, lifts the overburden and places it
on a spoils pile adjacent to the mining area (Figure 2-2) . The
exposed coal is then mined and loaded into large trucks or onto
conveyor belts for transportation to either a conversion or load-
ing facility.
Current regulations require surface-mined lands to be re-
claimed. Present practice is for mining and reclamation to pro-
ceed simultaneously. Overburden is placed in the mined-out area,
graded and contoured; topsoil is then replaced and the area is
revegetated. Data on surface mining are shown in Table 2-3.
Underground room and pillar mining is the alternative assumed
for the Kaiparowits/Escalante and Rifle sites. As the coal is
mined, pillars of coal are left in place to support the roof.
(Roof supports are used in addition to the pillars.)
In our scenario, continuous mechanical miners are used (see
Figure 2-3) . . When this mining technology is used, the coal is
continuously scraped from the seam and loaded directly onto a con-
veyor or mine rail car train.
detailed technical information is contained in White,
Irvin L. , et al. Energy From the West: Energy Resource Develop-
ment Sytems Report. Washington, D.C.: U.S., Environmental Pro-
tection Agency, forthcoming; Coal, Chapter 3; Oil Shale, Chapter 4;
Uranium, Chapter 5; Oil, Chapter 6; Natural Gas, Chapter 7; and
Geothermal, Chapter 8.
23
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TABLE 2-3: SURFACE COAL MINING DATA
Mine Size
Recovery
Nominally 12 million tons per year
(size varies depending on demand of
conversion facility)
80-90 percent of resource in place
Reclamation involves separate topsoil retention, re-
placement of topsoil, returning land to original
contours, and revegetation to native cover. Revege-
tation is thought to require 6 to 9 inches of water
per year for five years.
Reclamation for underground mines involves finding permanent
disposal for the spoils mined along with the coal and material
removed to gain access to the seam. These materials are usually
stabilized with lime and deposited in sealed landfills. Data on
underground mining are shown in Table 2-4.
2.4.3 Coal-Fired Steam-Electric Power Plants
The power plants analyzed in this study are assumed to be
direct fired boilers producing high pressure, superheated steam
which is then expanded in a multistage turbine to produce mechani-
cal energy. The mechanical energy is then converted to electricity
in an electrical generator (Figure 2-4). Details of the boiler
and turbine design are not considered, but an overall efficiency
of 34 percent is assumed for the plant including environmental
controls. This level of efficiency for the overall plant could
be achieved with a number of alternative systems, but would re-
quire a relatively sophisticated boiler-turbine arrangement with
superheaters, reheaters, economizers, and preheaters.
Environmental controls for the plant include a wet limestone
scrubber for flue gas desulfurization (FGD) and an electrostatic
precipitator (ESP) for particulate removal. To examine the sen-
sitivity of impacts to alternative environmental control systems,
FGD and ESP efficiencies and stack height are varied in our air
impact analyses. No cleanup technology is assumed for oxides of
nitrogen.
Because of thermodynamic limitations, almost two-thirds of
the heat generated in a power plant boiler must be dissipated.
Forced draft, wet cooling towers are assumed in which heat is dis-
sipated by evaporation of water into the atmosphere (Figure 2-5).
To examine the sensitivity of impacts to cooling technology, com-
bined wet-dry and dry cooling system costs and water consumption
are also examined.
24
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TABLE 2-4: UNDERGROUND COAL MINING DATA
Mine Size
Recovery
Nominally 3 million tons per year
(size and number of mines varies
depending on demand of conversion
facility)
45-50% of resource in place
Reclamation requires waiting 2 years for subsidence
and then returning land to original contours and
native cover. No reclamation was assumed to be nec-
essary for the underground coal mines in this study.
Data on coal-fired steam-electric power plants are shown in
Table 2-5.
2.4.4 Coal Gasification
Impacts of two coal gasification processes are analyzed. The
Lurgi process was selected because it is a presently available com-
mercial scale technology. The Synthane process was selected as
representative of a number of second generation processes which
are likely to be commercially available by 1985 to 1990.
In coal gasification, coal is transformed into gas by heating
(to drive off vapors) and burning it with reduced oxygen and steam
TABLE 2-5: COAL-FIRED POWER PLANT DATA
Plant Size
Plant Efficiency
Load Factor
Environmental
Controls
Cooling
Nominally 3,000 megawatt-electric output using
4 boilers of 750 megawatts capacity each
34% including environmental controls
75% as an annual average. For worst-case anal-
ysis of daily or hourly quantities of pollu-
tants produced, 100% load factor is assumed.
99% effective electrostatic precipitator
80% effective flue gas desulfurization using
a wet limestone scrubber
500 foot stack height
Forced draft wet evaporative cooling towers
27
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TABLE 2-6: COAL GASIFICATION PLANT DATA
Plant Size
Plant Efficiency
Load Factor
Nominally 250 million cubic feet per day
of 1,000 British thermal units per cubic
feet synthetic natural gas
Lurgi process 73%
Synthane process 80%
90% as an annual average. For worst-
case analysis of daily or hourly quanti-
ties of pollutants produced, 100% load
factor is assumed.
to produce carbon monoxide and hydrogen (H). This mixture of gases
is then upgraded to synthetic natural gas (primarily methane) in
a separate reactor using a catalyst.
The Lurgi gasifier uses a moving grate and gasifies with
steam and oxygen at pressure of between 300 and 500 pounds per
square inch atmosphere (PSIA) and a temperature which varies be-
tween 1,800ฐ Fahrenheit (F) at the bottom of the gasifier and
1,000ฐF at the top (Figure 2-6). Because it uses a grate, the
Lurgi fasifier is small, and between 25 and 30 reactors eire needed
for a 250 million cubic foot per day plant.,
The Synthane process is a fluidized bed gasifier involving
three separate stages. The first stage pretreats the coal by
partly burning it at 1,000 pounds per square inch (psi) and 800ฐF
so that it will not stick together during gasification. The next
stage takes place at a slightly higher temperature (about 1,100-
1,450ฐF) and starts the gasification process, while the third
stage completes the process at about 1,750-1,850ฐF. Because it
is a pressurized fluidized bed, only one reactor vessel is required
for a commercial-size facility, and the Synthane process is expec-
ted to operate at 8 to 10 percent higher efficiency than the Lurgi
process.
Following both the Lurgi and Synthane basic gasification pro-
cesses, solids and undesirable byproduct gases are removed before
the methane is generated in its reactor. Byproduct gases include
carbon dioxide and hydrogen sulfide (H2S). The H2S is reduced to
elemental sulfur and water in a Claus plant.
Water rs used in these facilities both as an input to the
gasification process and for cooling. As with the steam-electric
power plant, wet, forced draft cooling towers are assumed, for
cooling. Wet-dry and all dry cooling are also examined.
Data on both gasification facilities are shown in Table 2-6.
28
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FEED COAL
DRIVE
GRATE\
DRIVE
STTAM
&OXYGEN
SCRUBBING
COOLER
GAS
WATER JACKET
FIGURE 2-6: SCHEMATIC OF A LURGI GASIFIER
29
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TABLE 2-7: COAL LIQUEFACTION PLANT DATA
Plant Size
Plant Efficiency
Load Factor
100,000 barrels per day of synthetic crude
with an energy of 5.8X106 Btu/barrel
Synthoil process 92%
90% as an annual average. For worst-case
analysis of daily or hourly quantities of
pollutants produced, 100% load factor is
assumed
Btu = British thermal unit
2.4.5 Coal Liquefaction
Coal liquefaction processes are currently at a much earlier
stage of development than gasification, and it is not anticipated
that liquefaction will be commercially available before 1995-2000.
Data on liquefaction processes is, therefore, somewhat limited and
uncertain. The liquefaction process assumed for this study is the
Synthoil process developed by the Bureau of Mines.
In the Synthoil process, H is added to the hydrocarbon (HC)
molecules in coal through the use of a catalyst so that a liquid
is produced. The process requires a pressure of 2,000 to 4,000
psi and high temperature (about 850 ฐF) .
In the presence of H, the sulfur in the coal is converted to
H2S gas, and this is removed and converted to elemental sulfur in
a Glaus plant.
Water is used both for cooling in wet, forced draft cooling
towers and as a source of H for the process.
Data on the Synthoil liquefaction facility are shown in Table
2-7.
2.4.6 Coal Transportation1
Two transportation options are analyzed for coal, unit trains,
and coal slurry pipelines. Unit trains are assumed to be 100 car
transportation alternatives are not described in the
ERDS Report. For a description of unit train and coal slurry pipe-
line technologies, see Szabo, Michael F. Environmental Assessment
of Coal Transportation. Cincinnati, Ohio: U.S., Environmental
Protection Agency, Office of Research and Development, Industrial
Environmental Research Laboratory, 1977.
30
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TABLE 2-8: UNDERGROUND OIL SHALE MINE DATA
Mine Size
Recovery
Nominally 24 million tons per year
60% of seam mined (lower grade shale
above or below that seam is not re-
covered)
trains with a capacity of 10,000 tons of coal each, powered by
six diesel-electric locomotives. Capacity of a unit train system
is variable, depending upon the number of trains, their frequency
of operation, and whether the right-of-way is single track, double
track, or a mixture of the two at various places along the route.
Unit trains are assumed to have no water requirements and operate
at above 95 percent efficiency.
Coal slurry pipelines utilize water flow to carry pulverized
coal. The coal slurry pipeline analyzed is assumed to carry 25
million tons per year of coal. Coal slurry pipelines do not oper-
ate economically either at partial capacity or with intermediate
delivery points, but they do operate at full capacity more eco-
nomically than unit trains.
2.4.7 Oil Shale Development Technologies
We have analyzed the impacts of underground oil shale mining
and surface retorting using the TOSCO II process, and of modified
in situ mining and retorting using the Occidental process.
2.4.8 Underground Oil Shale Mining
Conceptually, underground oil shale mining is similar to
underground coal mining, with the room and pillar method being
most likely to be used. However, oil shale mines are very large
as compared to coal mines, with roof heights of as much as 60 to
80 feet. These large rooms are mined in two zones. The top zone
is mined with equipment extracting the shale from the wall or face
of the resource, while the bottom zone is mined by extracting the
shale from the floor or bench.
The extraction process involves drilling, blasting, and pick
up of the loosened ore after which the walls are scraped, or
scaled, to remove loose material and the roof is bolted. Large
front-end loaders are used to load the mined shale into trucks
which transport it to a sizing and crushing facility. The extremely
large size of these mines results in the use of some equipment
more commonly seen in surface mines, such as large trucks and
drill rigs. A schematic of an underground oil shale mine is shown
in Figure 2-7, and data on underground mines is given in Table 2-8.
31
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ROOF
FIGURE 2-7: OIL SHALE ROOM-AND-PILLAR MINING
Source: Ashland Oil, Inc. and Shell Oil Co.
Detailed Development Plan and Related Materials
for Oil Shale Tract C-b. Volume Prepared for
Area Oil Shale Supervisor February 1976. p. 11-23,
(Originally reported in: Colony Development
Operation. An Environmental Impact Analysis for
a Shale Oil Complex at Parachute Creek, Colorado.
Volume I, 1974. p. 11)
32
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TABLE 2-9: SURFACE OIL SHALE RETORTING DATA
Plant Size
Plant Efficiency
Load Factor
Nominally 50,000 barrels per day of syn-
thetic crude with an energy of 5.8X106
British thermal units per barrel
100% of Fischer assay of oil in shale
recovered
90% as an annual average. For worst-case
analysis of daily or hourly quantities of
pollutants, 100% load factor is assumed
2.4.9 Surface Oil Shale Retorting
TOSCO II surface retorting is assumed to use the shale from
the underground mine. In the TOSCO II retort, one-half inch dia-
meter ceramic balls are heated to about 900ฐF and then put into
the retort with small pieces of raw shale. The retort vessel is
rotated so that the balls heat the shale by contact and, at the
same time, crush it to a powder. This heating process is done in
an inert gas atmosphere rather than air, so that the shale oil
released does not burn. The oil is collected, and the pulverized
spent shale is separated from the balls with moving screens and
carried away for disposal. The gas generated, which is a low
energy HC gas, is collected and used as a fuel in the heater for
the ceramic balls.
Because the energy content of shale is relatively low (only
about 25 to 35 gallons of shale oil can be obtained from a ton of
ore), a large quantity of spent shale must be disposed of. The
pulverized spent shale from the TOSCO II process can be set as a
cement with about 13 percent water; this cement is stable enough
for permanent disposal. Plans for shale disposal assume that a
small canyon in the vicinity of the retort will be used for dis-
posal and filled with the shale cement to depths of a few hundred
feet. The disposal area will then be covered with topsoil and
vegetated.
Data on surface retorting using the TOSCO II process are given
in Table 2-9.
2.4.10 In Situ Oil Shale Retorting
The Occidental modified in situ retorting process is assumed
as an alternative to surface retorting. In the modified iri situ
process, oil shale is mined from a region below a high quality ore,
33
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To GasTreatment
& Steam Plant
Process Air
To Oil/Water
\Separation
t.
Service Shaft
Note; Notdrawnto scste
FIGURE 2-8:
SIMPLIFIED DRAWING OF AN OPERATING MODIFIED
IN SITU OIL SHALE RETORT
Source: Ashland Oil, Inc., and Occidental Oil Shale, Inc.
Supplemental Material to Modified Detailed Development
Plan for Oil Shale Tract C-b, prepared for Area Oil Shale
Supervisor. June 1977.
34
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TABLE 2-10: MODIFIED IN SITU OIL SHALE FACILITY DATA
Plant Size
Plant Efficiency
Load Factor
Nominally 57,000 barrels per day of syn-
thetic crude with an energy of 5.8 X 10e
British thermal units per barrel
40% recovery of oil in place in mined
seams
90% as an annual average. For worst-
case analysis of daily or hourly quanti-
ties of pollutants produced, 100% load
factor is assumed
and this ore is discarded as a spoil. The high grade ore is then
broken into rubble with shaped charge blasting to form large in
situ retorts of over 100 feet on a side and nearly 300 feet high.
Air and steam are circulated through the shale rubble and the
shale is heated until it ignites in a burning front which burns
from the top down the retort, releasing shale oil ahead of the
combustion. The shale oil is collected in sumps, and the gases
produced are treated to recover additional energy and reduce emis-
sions. A much smaller quantity of shale must be handled with in
situ retorting than for surface retorting, and the disposed of raw
shale is more stable than processed shale from surface retorting.
A sketch of the modified in situ retorting is shown in Figure 2-8 ,
and data on the process are shown in Table 2-10.
2.4.11 Uranium Development Technologies
We have analyzed the impacts of surface, underground, and
solutional uranium mining, and of acid leach milling of the ore
from surface and underground mines to produce yellowcake (uranium
oxide [U308]).
2.4.12 Surface Uranium Mining
A surface uranium mine (assumed in the Gillette scenario) is
more similar to pit mining than to the area mining typically used
to recover coal. The uranium is located in veins which vary in
terms of the quality of ore and are irregular in location. Mining
is therefore carried out selectively, with lower quality ore left
as a spoil. In addition, as truckloads of ore leave the pit, ra-
dioactivity is measured to grade the ore for milling. The equip-
ment used for mining is similar to that used for coal but usually
smaller in size because of the smaller quantities or ore involved.
Reclamation of uranium mines includes layering the overburden
by composition to limit the potential for damage from trace
35
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TABLE 2-11: SURFACE URANIUM MINING DATA
Mine Size
Recovery
Nominally 440,000 tons per year of ore
generally expressed as 1100 metric tons
per day
95% of resource in place
TABLE 2-12: UNDERGROUND URANIUM MINING DATA
Mine Size
Recovery
Nominally 440,000 tons per year of ore
generally expressed as 1100 metric tons
per day
50% of resource in place
elements in the overburden leaching into groundwater and to assure
stabilization of materials which may be radioactive.
Data on' uranium surface mining are shown in Table 2-11.
2.4.13 Underground Uranium Mining
Underground uranium mining in the Navajo/Farmington scenario
is assumed to use a room and pillar method because of the antici-
pated nature of the uranium resource in this area. Additional
roof support using timbers is also assumed. Ore is mined using
continuous miners and removed by conveyors to the access shaft
where self-dumping buckets are used to haul the ore out of the
mine.
Reclamation is only assumed to be necessary for solid waste
from the mine. Thus reclamation will be limited to stabilizing
the solid wastes, placing topsoil over the landfill, and revegeta-
ting the area. The land area used for this landfill is small.
Data on underground uranium mining are shown in Table 2-12.
2.4.14 Solutional Uranium Mining
f
Solutional uranium mining was selected for one of the uranium
mines in the Gillette scenario in order to present a comparison
with surface mining, and also because the irregular seams or veins
and nature of the geology of the resource made this the most eco-
nomical mining technique. For solutional mining, an alkaline solu-
tion is injected into the ore formation through a group of injec-
tion wells. This solution dissolves the uranium compounds, and
36
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TABLE 2-13: SOLUTIONAL URANIUM MINING DATA
Plant Size
Plant Efficiency
Load Factor
250 tons per year of yellowcake
60 to 70% of resource in place
100%
TABLE 2-14: URANIUM MILLING PLANT DATA
Plant Size
Plant Efficiency
Load Factor
1,000 metric tons of yellowcake
per year
93%
100%
this "pregnant" solution of uranium is pumped out of the formation
in recovery wells. The solution is then processed to recover
yellowcake, so that the mining and milling processes are combined
in solutional mining.
Reclamation after solutional mining involves cleansing the
groundwater in the mined-out area to insure that uranium and other
heavy metal compounds do not remain. This is accomplished by
pumping clean water into the formation and recovering the remaining
alkaline solution and dissolved compounds. The recovered solution
is either cleaned or disposed of in an evaporative pond.
Data on solutional uranium mining are shown in Table 2-13.
2.4.15 Uranium Milling
Uranium milling is a process by which U3C>8 is extracted from
uranium ore and concentrated into a "yellowcake" which is about
90 percent UaOa. The milling process assumed in this analysis is
acid leaching. The ore is crushed, slurried (mixed with water and
carried along as the water flows) , and pumped into heated, agitated
tanks where sulfuric acid is added. The uranium ore dissolves in
the acid, and the solution is then separated from the waste mate-
rials, or tailings, which are discarded in a tailings pond. The
solution is concentrated with additional chemical processes, and
finally, the U3O8 is separated out of the solution and dried for
shipment.
Shipment of the yellowcake is assumed to be by truck. Data
on uranium milling are given in Table 2-14.
37
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TABLE 2-15: CONVENTIONAL OIL PRODUCTION DATA
Field Size
Recovery
Nominally 100,000 barrels per day of
crude with an energy content of 5.8 X 106
British thermal units per barrel; 400
wells required
50% of original oil in place
TABLE 2-16: STEAM FLOODING ENHANCED OIL RECOVERY DATA
Field Size
Recovery
Nominally 100,000 barrels per day of
crude with an energy content of 5.8 X 106
British thermal units per barrel; 400
wells required
10% of original oil in place
2.4.16 Oil Development Technologies
We have analyzed the impacts of conventional oil production
and enhanced production using steam flooding.
2.4.17 Conventional Oil Production
Oil production is assumed to include rotary drilled wells in
which water based mud is used as a drilling fluid and to remove
cuttings. The wells are assumed to be lined with steel pipe casing
cemented in place, and the oil is produced through tubing going
from the bottom of the well in the oil reservoir to the surface.
No wellhead processing of the oil is assumed except for water re-
moval after which the oil is piped out of the region to be refined.
Data on conventional oil production are shown in Table 2-15.
2.4.18 Enhanced Oil Recovery
The enhanced oil recovery method analyzed is steam flooding.
Two sets of wells are used, one to inject the steam and the second
to recover the oil and water mixture. The steam increases the
temperature of the oil so that its viscosity is reduced and it
flows more readily. The oil is then pushed by the steam pressure
to the recovery wells. Most of the steam injected is recovered as
water in a mixture with the oil, and this water must be disposed
of in evaporation ponds or cleaned and recycled to the steam
generators.
Data on steam flooding are shown in Table 2-16.
38
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TABLE 2-17: NATURAL GAS PRODUCTION DATA
Field Size
Recovery
Nominally 250 million cubic feet per day
of 1,000 British thermal units per cubic
foot gas
90% of gas in place
2.4.19 Natural Gas Development Technologies
Conventional drilling and production of natural gas are ana-
lyzed. As with oil, rotary drilling was assumed using water based
mud as a drilling fluid. Wells are assumed to be cased with a
heavy pipe cemented in place, and the gas is produced through
smaller diameter tubing from the production zones. Surface drying
is assumed for the gas using a glycol drying process in which a
combination of heat and the glycol vapor are used to dry the gas.
Data on natural gas production are shown in Table 2-17.
2.4.20 Geothermal Development Technologies
Electric power generation from both high temperature hot water
and hot dry rock geothermal resources are analyzed.
2.4.21 Hot Water Geothermal
Hot water geothermal development is analyzed because that is
one of the most likely geothermal resources to be developed in the
eight-state study area. The resources are assumed to have a tem-
perature above 150ฐC. Power production is assumed to use either
a flashed steam or binary cycle process.
In the flashed steam process, the hot, high pressure water
is expanded to a low pressure so that it vaporizes. The vapor is
then used to drive a low pressure turbine which in turn drives an
electric generator. If the hot water is of low quality, and has
salts or solid particulates entrained, the flashed steam must be
cleaned before entering the turbine.
In the binary cycle process, the hot water is used to heat
another fluid with a lower boiling point such as propane, which
is then vaporized and used to power a turbine. The binary cycle
has fewer problems with low quality water but is more complicated
than the flashed steam process. In both processes, cooling calls
for wet cooling towers which use the geothermal condensate as a
source of water.
39
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TABLE 2-18: HOT WATER GEOTHERMAL POWER PRODUCTION DATA
Facility Size
Efficiency
Load Factor
100 megawatts of electric power output;
60 wells for steam flashing cycle; 55
wells for binary fluid cycle
9-10% for steam flashing cycle; 10-11%
for binary cycle
70%
TABLE 2-19: HOT ROCK GEOTHERMAL POWER PRODUCTION DATA
100 megawatts of electric power output;
6 wells
16-18%
70%
Facility Size
Efficiency
Load Factor
Data on flashed steam and binary cycle geothermal power genera-
tion are shown in Table 2-18.
2.4.22 Hot Dry Rock Geothermal
The hot dry rock geothermal system uses two sets of wells,
one set for injection and one set for recovery of water. After
injection, the water is heated by the hot rock to a temperature
of 250ฐC. This hot water is used to heat a second working fluid
in a heat exchanger. The remainder of the power production pro-
cess proceeds the same as for the binary cycle process described
above for hot water resources. For hot dry rock development, how-
ever, water must be supplied both for injection to recover the
heat, and for cooling.
Data on hot dry rock geothermal power generation are given in
Table 2-19.
2.4.23 Summary
With the exception of enhanced oil recovery and geothermal,
the technologies described above are hypothesized to be placed at
specific sites in the eight western states. In the following
chapters, the impacts of those hypothetical developments are ana-
lyzed and described. In addition, impacts on the region from
overall levels of development are analyzed, and that analysis in-
cludes enhanced oil recovery and geothermal facilities.
40
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CHAPTER 3
THE IMPACTS OF WESTERN ENERGY RESOURCE
DEVELOPMENT: SUMMARY AND CONCLUSIONS
3.1 INTRODUCTION
This chapter summarizes the findings from our assessment
of the potential impacts from the development of coal, geothermal,
natural gas, oil, oil shale, and uranium resources in eight
western states. Although development alternatives for all six
of these energy resources have been considered, coal resource
development has been emphasized.1 As shown in Figure 3-1, coal
development alternatives include surface and underground mining,
on-site electrical power generation, conversion to synthetic
fuels (gasification and liquefaction), and the export of raw coal
by unit trairn and slurry pipeline. Electricity will be trans-
ported by extra-high voltage (EHV) transmission lines, and gases
and liquids by pipelines.
Underground mining and surface retorting, modified in_ situ
processing, and transport by pipeline make up the oil shale re-
source development alternatives considered. Oil and natural gas
development includes conventional drilling and transportation by
pipeline as well as enhanced recovery technologies. Uranium
development includes surface mining, underground mining, solu-
tional mining, milling, and then transportation. Geothermal
development includes drilling, production of hot water, and
conversion to electricity.
Development alternatives are summarized in the Introduction
to Part II and in Chapters 4-11. Detailed descriptions of the
technological alternatives for developing each of the six energy
resources were prepared as background and supporting materials
for the impact and policy analyses. These descriptions provide
baseline data on the technologies (demands, products, and re-
siduals) , characterize the resources, and describe the principal
laws and regulations that apply to the deployment and operation
of the technologies. See White, Irvin L., et al. Energy From
the West: Energy Resource Development Systems Report.Washington,
D.C.: U.S., Environmental Protection Agency, forthcoming.
41
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The organizing concept used to structure the impact analyses
is based on the fact that impacts occur when a technology inter-
acts with the conditions that exist at the location where the
technology is deployed. What these impacts are depends on: the
resource demands the technology creates; the unwanted by-products
or residuals it produces (e.g., air pollution); the physical
and social environmental conditions that exist at the site (such
as present population, lifestyle, topography, and climate); and
the scale, rate, pattern, and timing of the development.
Seven energy resource development scenarios were used to
organize various combinations of the development alternatives
depicted in Figure 3-1 and to structure the impact analyses. Six
of these scenarios are site-specific; they call for the deploy-
ment of typical energy development technologies at six repre-
sentative sites in the eight-state study area. The seventh
scenario is used to structure the analysis on a regional basis,
it calls for two levels of energy development within the eight-
state area from the present to the year 2000.
Table 3-1 identifies the six sites selected, lists hypo-
thetical energy developments at each, and indicates when each of
the facilities are to be operational. As Table 3-1 indicates,
several process mixes, development schedules, and scales of de-
velopment have been included in the scenarios. The number and
mix of technologies was chosen to provide for the analysis of
a variety of technology and location combinations.
Table 3-2 indicates the total quantities of energy required
from the Western U.S. at two national levels of energy consump-
tion in 1980, 1990, and 2000. This table also shows the role
of each of the six resources in producing these total quantities.1
To complete the picture of the regional development being assessed,
Table 3-3 identifies the number and kinds of facilities that
would be required in the Low Demand case for each resource in
each of two major subregions utilized in the study: Rocky
Mountain (which includes New Mexico, Utah, and Colorado) and
Northern Great Plains (which includes Wyoming, Montana, and North
Dakota).
Together, these seven scenarios provide an organizing analyt-
ical structure for estimating impacts likely to occur when typical
energy development technologies are deployed under representative
existing conditions. Results of the six site-specific impact
!The two levels of development were established using the
Stanford Research Institute's (SRI) interfuel competition model.
The model and the two cases are described in Chapter 11 and in
more detail in Cazalet, Edward, et al. A Western Regional Energy
Development Study; Economics, Final Report, 2 vols. Menlo Park,
Calif.: Stanford Research Institute, 1976.
43
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analyses are reported in Chapters 4-10. These results are the
basis for the conclusions concerning local impacts and generaliza-
tions about technologies and existing conditions included in this
chapter. Likewise, the levels of development, facilities, and
time frame outlined in Tables 3-2 and 3-3 provide the structure
for the analysis of regional impacts described in Chapter 11; the
results of those analyses are the basis for the summary discussion
of regional impacts and the factors which cause them. In the
summary of regional impacts that follows, the focus is on the
Low Demand case since this is felt to represent a more realistic
level of development for the region through the year 2000.
This chapter identifies the technological and locational
factors that produce significant impacts in seven categories:
air; water; social and economic; ecological; health effects;
transportation; and aesthetics and noise. Impacts within each
category are identified as being primarily a consequence of the
technology, conditions existing at the deployment location, and
the interaction of technological and locational factors. It
should be emphasized that the following discussions are summaries
of the impacts which are described in Chapters 4-11. For more
detailed explanations (including more extensive references) the
reader is referred to the appropriate following chapters.
3.2 AIR QUALITY
HIGHLIGHTS
CRITICAL FACTORS
' Two techno log-Leal fiacton* can *lgnifilcantly a&fiect aln
quality -impact* : em-i**-ion* quantit-ie* and laboft -inten-
A-ivene** .
Jhn.ee locational fiacton* can alto *lgn-ifiicantly
the*e -impact*: coal ckan.acten.-i* tic* , d-i*pen.*-ion potential,
and te.in.a-in &eatun.e*.
EMISSIONS
*ulfiu.n. dioKide (SO?), pan.t-icu.late* , oxide* ofi nltnogen
, and carbon di.ox.-ide (CO^l ax.e. nm-ittid by e.t
Le.64 oh thni>n. fiou.fi cK.ite.n-ia pollutant* ate emitted by
ImfiQi g a* -ifi-i cat-ion fiacil-it-ie* than by any otkei convex.* -ion
technology.
48
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On the basis o^ an equivalent amount ofi energy produced,
above ground oJUL shale into siting, and natural gas pro-
cessing emit the. gie.ate.At qu.ant-itj.eA oฃ hydn.oc.an.boM (HC);
af.thou.gh there is great uncertainty regarding oil shale
emission figures, em-LA A ion* o& HC by modified in_ situ
oil shale 6ac4.i4.ti.e-t> are estimated to be ten t4.mes let*
than ^rom an above ground facility.
AMBIENT AIR IMPACTS
Peak ground-lev el concentrations o & particulates, nitrogen
dioxide (NOf), and HC produced by energy related urban
development are usually higher than those produced by
the energy facilities themselves.
The state ambient air quality standard in Colorado is the
most restrictive standard limiting SO? emissions firom
power plants in that state.
fugitive HC emissions resulting ^rom oil shale retorting,
coal lique-^action, and natural gas production o& the size
modeled are expected to cause the federal 3-hour ambient
air quality standard to be exceeded.
facilities faor producing synthetic ^uels farom coal can
usually meet all federal and state standards except &or
HC in the case o & coal liquefaction and TOSCO II -6haฃe oil
production.
PREVENTION OF SIGNIFICANT DETERIORATION (PSD)
federal Clat>s II PSV standards are the most restrictive o&
all the standards faor SO? emissions firom power plants in
three o& the states studied (North Dakota, Wew Mexico, and
Utah].
Even when equipped with 80-percent evident scrubbers,
electric power plants o{> the size modele.d will sometimes
not be able to meet Class II PSV increments &or S02-
Required separation distances between Class I PSV areas
and power plants with BO percent SO^ removal and 99 percent
particulate removal ranged firom 5 to 75 miles.
NEW SOURCE PERFORMANCE STANDARDS (NSPS)
kt some sites, removing only the percentages o^ SOo and
particulates required to meet the existing federal NSPS
^or coal-^ired power plants can result in violations ofa
ambient air and PSV standards.
49
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h
-------
among types of conversion facilities but, in the case of electric
power plants, in air pollution environmental controls as well.1
(1) Emissions
Table 3-4 presents criteria pollutant emissions data for
energy facilities based on the range of conditions for the six
site specific scenarios. Table 3-5 represents these emissions on
equivalent energy basis for each conversion alternative. Data
for the electric power plant in Table 3-4 assume that 99 percent
of the particulates and 80 percent of the SO2 are removed by
emissions control technologies.2 In general, this degree of con-
trol is required to meet ambient air standards in the eight-state
study area. At several of our sites, a lower level of SO2 control
than this would meet NSPS3 but a higher level would be required
to meet PSD increments for Class II areas ."*
On the basis of both the size facility deployed in our sce-
narios and equivalent energy, electric power plants with scrub-
bers emit more of four criteria pollutants (S02/ particulates,
N02 and CO) than any other type of conversion facility (Tables
1 Emissions control is an integral part of the plant design
for synthetic fuel technologies.
2These analyses assumed that sulfur was removed after coal
combustion by scrubbers. However, the emissions would be the
same for a given removal efficiency regardless of whether sulfur
was removed prior to coal combustion (coal cleaning) or after
coal combustion.
3 In this report, NSPS refers to the emission standards in
effect prior to the 1977 Clean Air Act Amendments, Pub. L. 95-95,
91 Stat. 685. According to the new legislation, emissions stan-
dards for new facilities must now be defined in terms of the best
available system of continuous emission reduction. These newer,
more stringent standards, which have not yet been defined by' the
Environmental Protection Agency, will be referred to as best
available control technology.
^
Current PSD requirements are based on an area classification
system which divides the nation's "clean air" (i.e., areas where
the air quality is better than that allowed by ambient air stan-
dards) into three classes. Each class permits progressively
larger incremental additions (or "allowable increments") to concen-
trations of S02 and particulates. Class I areas are generally
pristine, such as national parks, but states or Indian tribes may
designate other areas as Class I. Class III areas permit deteri-
oration to national ambient secondary standards.
51
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TABLE 3-4:
AIR EMISSIONS FOR STANDARD SIZE ENERGY FACILITIES'
(pounds per hour)
CONVERSION FACILITY
Coal
Power Plant
(3,000 MWe) c
Largi Gasification
(250 MMscfd)
(250 MMscfd)
Synthoil Liquefaction
(100,000 bbl/day) c
Surface Mine
(12 MMtpy)
i Oil Shale1
TOSCO II Oil Shale
(50,000 bbl/day)
Underground Oil Shale
Mine (26 MMtpy)
Modified In Situ Oil
Shale Processing
(57,000 bbl/day)
Modified In Situ Oil
Shale Processing3 with
Surface Retort
(57,000 bbl/day)
Crude Oil
Conventional Oil
Extraction
(50,000 bbl/day)
Enhanced Oil Extrac-
tion Steam In]ectlon
(100,000 bbl/day)
Enhanced Oil Extrac-
tion CO: Miscible
(100,000 bbl/day)
Natural Gas
Natural Gas Production/
Processing (250 MMscfd)
"Jranium
Underground Mine
(1,100 mtpd ore)
Surface Mine
(1,100 mtpd ore)
Mill
(1,000 mt yellowcake
per year)
Solutional Mine-Mill
(250 tons, yellowcake
per year) n
Secthermal '100 MWe)
PARTICULATES
1,110 - 5,020
Nd
3d
480 - 1,250ฐ
13 - 24
360
125
74
362
0.3
353-1,187
120
2
0.16
361
40
N
NA
so,0
^,800-14,000
520
3,520
940-1,170
8-16
350
N
174
343
21.7
10,125
3,420
463
0.36
8.9
1.03
N
2101
NOX
14,320-35,140
650
5,050
4,620-5,770
0.5-210
1,900
270
538
1,777
17.6
308
1,040
655
5
123
0. 3
N
NA
KC
400 - 650
47<*
94d
1,350 - 1,690
17 - 180
1,020
54
120
130
4.3
108
35
1,000
0.5
u
0.05
N
NA
CO
1,330 - 2,130
N
130
180 - 230
13 - 87
30
480
34
U
1.3
208
70
2
3
93.4
U
N
NA
SOi = sulfur dioxide
NOX 3 oxides of nitrogen
HC = hydrocarbons
CO - carbon monoxide
MWe ซ megawatt-electric
MMscfd = million standard cubic feet per day
N * negligible
bbl/day - barrels per day
MMtpy * million tons per year
U * unknown
CO2 * carbon dioxide
mtpd ป netric tons per day
fit * metric ton
NA - not applicable
52
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TABLE 3-4: (continued)
aThese numbers represent the range of emissions found in the site-specific scenarios; and
facilities are assumed to be operating at a full load.
Had scrubbers not been hypothesized for the power plants, these numbers would be about
five times larger.
C99 percent particulate removal and RO percent SO; removal.
These values do not include fugitive participates or fugitive MC.
cThis value does not include fugitive particul.ites.
No range is available for oil shale because the processes were hypothesized at only one site.
^Assumes mined-out shale is processed by surface retorting facility.
''Emissions from the Bolutional uranium mine mill consist of ammonium, ammonium chloride, and
uranium oxide.
This number is for hydrogen sulfide (H2S) and assumes 90 percent HjS removal.
53
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55
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3-4 and 3-5).l Coal gasification plants emit fewer pollutants
than electric plants in all categories, and Synthoil liquefaction
produces more HC emissions than other coal and oil shale synfuels
facilities of the size deployed in our scenarios.
The results of our impact analyses indicate that fugitive HC
emissions from liquid processing facilities (above-ground oil shale
retorting and coal liquefaction) and from natural gas production
can be expected to result in ambient HC concentrations that greatly
exceed the federal 3-hour standard of 160 micrograms per cubic meter
(yg/m3). Because they are emitted at or near ground level, the
total amount of fugitive HC emitted need not be large to produce
the high concentrations often associated with these facilities.
Leaks in valves and fittings and from fuel oil storage tanks account
for most fugitive HC emissions. The highest concentrations are
expected to be produced by above-ground oil shale retorting (up to
38,500 yg/m3), followed by coal liquefaction (17,300-25,100 yg/m3)
and natural gas production (1,000 yg/m3). Conventionally produced
natural gas affects short-term ambient levels of HC more than the
Lurgi and Synthane coal gasification processes (which range from
47 to 94 yg/m3). However, these short-term violations of the HC
standard are not expected to block development since the HC standard
is interpreted by the Environmental Protection Agency (EPA) as a
"guideline" ฃor assessing potential oxidant- problems rather than
as a rigidly enforced maximum.
1 To provide a basis for comparing power plants with synthetic
fuel plants, emissions are expressed on both an electrical output
basis, and a per British thermal unit (Btu) of thermal input to the
plant basis. However, comparing electrical energy to energy in oil
or gas can be misleading since electricity has high quality uses
not possible with oil and gas (such as electric home appliances
and lighting). Hence, if electricity were used only for high qual-
ity demands, it would be worth about three times as much as thermal
energy in oil and gas. Only about half of electricity is used this
way, however, and the remainder is used for heat, for which a direct
comparison with oil and gas can be justified. Numerically, on a
Btu thermal basis, electricity is valued as the energy content of
the coal which feeds the power plant. On a Btu-electrical basis,
the electricity is valued by the energy content of the electrical
energy. In the power plant, the energy produced when measured in
Btu-electrical is about three times less than the energy as measured
in Btu-thermal. Neither measure is exactly comparable to the energy
content of oil or gas. A Btu-electrical is more valuable than a
Btu of oil and gas; but a Btu-thermal in the power plant case is
less valuable than oil and gas made from coal.
56
-------
(2) The Effect of Control Technologies on Emissions from Power
Plants
Under the Best Available Control Technology (BACT) provisions
of the 1977 Clean Air Act Amendments, some percentage sulfur re-
duction will be required on all newly constructed power plants,
which practically means that flue gas scrubbers will probably be
required. Power plants without S02 scrubbers will emit about
five times more S02 than indicated in Table 3-4.l Without a BACT
requirement, NSPS could be met without scrubbers at some locations
due to the low sulfur content of the coal (Kaiparowits/Escalante,
Rifle, and Gillette).2 However, our analyses of impacts at these
sites indicate that at least one federal ambient S02 standard
could be violated.3 Further, at the three other sites (Farmington,
Colstrip, and Beulah), plants equipped with scrubbers that remove
only enough S02 to meet NSPS will exceed at least one federal and
some state standards. In addition, plumes at all sites will
generally not meet the 20 percent opacity standard without a very
high level of particulate removal (99.3-99.8 percent).
(3) Emission Levels and PSD Requirements
Our site specific analyses indicate that coal gasification
and liquefaction plants can meet all Class II PSD increments in
these locations. However, oil shale retorts and power plants
(with 80 percent efficient S02 scrubbers and 99 percent efficient
particulate controls) may cause Class II increments to be exceeded
locally and Class I increments to be exceeded in nearby national
parks. In three of the locations (Kaiparowits/Escalante, Rifle,
and Beulah), power plants exceed either one or both of the Class
II 24-hour particulate and S02 increments.
Allowable increments for Class I areas apply to all new
sources whether located within or outside the Class I area. This
effectively establishes a "buffer zone" around Class I areas within
which new facilities cannot be sited since pollutants from the
facility must be diluted by atmospheric mixing to achieve the low
concentrations allowed. The distance required for this dilution
to take place determines the size of the "buffer zone," which
!The values in Table 3-4 assume 80 percent S02 removal.
2The NSPS standard for S02 for large power plants is 1.2 Ibs,
of S02 per million Btu's of fuel burned.
3A11 the above conclusions are based on dispersion modeling
results that are inherently approximate. The accuracy of the
Gaussian-type dispersion models used in this study is generally
accepted to be ฑ100 percent. However, evidence is beginning to
accumulate that the models may be as accurate as ฑ50 percent.
57
-------
varies by facility type, size, the effectiveness of emission con-
trols, and local topographical and meteorological conditions. In
this study, the distance from Class I PSD areas that facilities
must be sited ranges from 5 to 75 miles. By far, the largest dis-
tance is required for electric power plants,1 an average of about
52 miles. Distances required for Lurgi , Synthane, and Synthoil
are roughly equivalent, ranging from 9 to 14 miles. The most re-
strictive standard for all conversion technologies is either the
3- or 24-hour S02 increment. Buffer zones are a siting consider-
ation only in areas where there are numerous Class I PSD areas.
(4) Pollution Control Alternatives
The effect on ambient air concentrations of S02 by power
plants equipped with scrubbers with different efficiencies and
stack heights is illustrated in Table 3-6. When the base case
assumptions (80 percent SC>2 removal and 500 foot stack height)
are used, three plants (Rifle, Beulah, and Kaiparowits/Escalante)
will violate at least one federal Class II PSD standard for S02 . 2
If 95 percent efficient scrubbers are used, no federal standards
will be violated by any of the plants (assuming a 500 foot stack
height). If a 1,000 foot stack height is assumed (with an 80 per-
cent efficient S02 scrubber) , none of the power plants will fail to
meet Class II PSD increments for S02 ambient air concentrations.
Other air pollution control alternatives considered include
reduction of plant size and relocation of the plant site from
complex to flat terrain. At Rifle, plant capacity would have to
be reduced from 1,000 to 500 megawatt-electric (MWe) to meet
applicable federal standards (with an 80 percent efficient S02
scrubber), but if moved to a site with flat terrain, the 1,000
MWe facility would meet those standards. Assuming 80 percent
S02 removal and 500 foot stack height, the 3,000 MWe power plants
at Beulah and Kaiparowits/Escalante could meet Class II PSD in-
crements by reducing plant capacity to 1,500 and 500 MWe, re-
spectively. The 3,000 MWe Escalante plant would meet applicable
standards if moved to a site with a flat terrain.
In summary, the 80 percent efficient SO2 scrubbers for power
plants assumed in this study are predicted to meet federal Class
II PSD standards at half of the six scenario locations. At two
other sites the state standards will be more restrictive. For
these three power plants which fail to meet PSD Class II standards
for S02 , compliance could be achieved with a 95 percent efficient
assumes a 3,000 MWe power plant (except the Rifle plant
is 1,000 MWe) with 80 percent S02 and 99 percent particulate re-
moval.
2State standards would require additional emission controls
on the facilities at Gillette and Colstrip.
58
-------
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59
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SOa scrubber. Reduced plant size, utilizing 1,000 foot stacks,
and relocating plant sites from complex to flat or elevated ter-
rain are other alternatives which can reduce ambient air concen-
trations from energy conversion facilities. At the locations
where scrubbers are not needed to meet NSPS because of the low
sulfur content of the coal, at least one federal ambient SOs
standard could be exceeded.
B. Labor Intensiveness
The second technological factor that significantly affects
air quality impacts is the labor intensiveness of a technology.
Our impact analyses indicate that peak ground-level concentrations
of particulates, N02, and HC produced by energy related urban de-
velopment can be higher than those produced by energy facilities
themselves.1 For example, based on our six site specific sce-
narios, annual particulate concentrations from urban sources
ranged from 7 to 30 ug/m3, which exceed those from the energy
facilities (0.4-4.0 yg/m3). These high concentrations result from
the release of pollutants at or near ground level in urban areas
by such sources as automobiles and home heating. Total emissions
of pollutants in the urban area are small in comparison to those
emitted by an energy conversion or production facility; in fact,
less than 10 percent of the total pounds per year emitted come
from urban sources. However, because pollutants from urban sources
are released close to the ground, and thus experience little or
no mixing and dilution, high ground-level concentrations result.
Table 3-7 summarizes the projections from our six site-
specific scenarios for peak ground-level concentrations of pol-
lutants originating from urban sources and from energy facilities
in 1990. Note that the peak concentrations of particulates, N02,
and HC produced by urban sources nearly always exceed those from
the energy facility.
The models used to estimate air impacts also suggest that
these concentrations are not likely to increase consistently
as urban population increases, but rather to increase rapidly
as the total urban population rises to about 15 to 20 thousand
Section 3.4 for details on the increases in population
that can be attributed to energy resource development
60
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people and at a progressively slower rate thereafter.1 Thus,
small or new towns in the West are likely to experience a high
percentage increase in ambient pollutant levels as population
increases, while larger towns (such as Farmington) will experience
relatively little change.
C. Other Technology-Related Impacts
Other air impacts analyzed included long-range visibility,
cooling tower fogging and icing, cooling tower salt deposition,
fine particulates, oxidants, and weather modification. Of these,
visibility reduction appears to be the most significant problem
area. Visibility reductions due strictly to sulfate formation
were examined for each of the six sites. Based on a conversion
rate of S02 to sulfates of one percent per hour, visibility during
a worst-case meteorological episode could be reduced downwind
of an energy facility from present values of 60-70 miles to 8-60
miles. The greatest visibility reductions are associated with
power plants. These worst-case conditions are expected to occur
from one to a few times per year.
Energy development could also produce oxidant (i.e., smog)
problems. Background or emitted HC, in combination with NOx in
plumes, provides the potential for oxidants downwind of a facility.
As indicated previously, several of the technologies emit re-
latively large amounts of HC, NOx, or both. However, the serious-
ness of the problem is unknown since present knowledge of the con-
version processes forming oxidants is insufficient to predict con-
centrations based on residuals emissions.
3.2.3 Variations in Existing Conditions
Air quality impacts can vary widely in the eight-state study
area due to variations in existing conditions. Many of these
existing conditions are geographical or meteorological in nature,
Projected concentrations from urban sources are derived
from both emission rates and dispersion potential. The projec-
tion that peak concentrations increase rapidly up to a point (15-
20 thousand people) and progressively slower thereafter is based
on several important and debatable assumptions. First, emission
rates from urban sources are assumed to be directly (or linearly)
proportional to the number of people in the town. Secondly, the
population densities of different-size towns are assumed to remain
relatively constant. Thus, since urban emission concentrations
are measured at a point in the center of town, pollution sources
more than 1 or 2 miles from the center will have little effect
on concentrations measured there. For towns larger than 15-20
thousand, it is assumed that new pollutant sources will be located
increasingly further from the center of town and thus have only
marginal impact on concentration levels.
62
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such as rugged terrain, poor dispersion potential, and the
proximity of resources or sites to Class I areas. Other existing
conditions affecting air quality include characteristics of the
coals found in different locations, the size of communities
located in the vicinity of the resource development, current
ambient air quality, and state air quality standards.
A. Coal Characteristics
Although low sulfur is an advantage commonly attributed to
western coals, many western coals also have low heating values.
The sulfur content of the coals used in our analyses range from
0.5 to 1.0 percent by weight and heating values range from 6,950
to 11,300 British thermal units (Btu's) per pound. As a result
of these variances, sulfur emissions on a per-million Btu's basis
are not necessarily low. Assuming that 100 percent of the sulfur
in the coal is converted to S02, the Kaiparowits, Rifle, and
Gillette coals meet the NSPS of 1.2 pounds of S02 emitted for
every one million Btu's of coal burned. For the other coals to
meet the NSPS standard, only 52-73 percent of the sulfur could
be converted to S02 in the boiler; that is, 27-48 percent of the
sulfur would have to be retained in the ash. However, sulfur
retention in the ash of more than 20 percent is not usual.
B. Terrain and Dispersion Potential
Another significant existing condition influencing air quality
in the eight-state area is terrain, most notably the complex
terrain found in western Colorado and southern Utah. Our impact
analyses suggest that the complex terrain in southern Utah can
contribute to high ground-level concentrations of pollution as
a consequence of plume impaction. In northwestern Colorado,
ambient levels of SO2 are predicted to exceed Colorado's ambient
standard (3-hour average) when the plume from the 50,000 barrel
per day (bbl/day) TOSCO II oil shale plant impacts on the rugged
terrain features in the area. These S02 violations are likely to
occur less than 30 percent of the time. In the Kaiparowits/
Escalante area, predicted ambient levels produced by plume im-
paction approach but do not exceed ambient standards.
At our other site-specific scenario locations, the terrain
is less rugged and plume impaction does not normally occur. In
1 These results were obtained using a modified Gaussian air
dispersion model. Although other routines, such as potential
flow model-s, have been used to project impacts in rough terrain,
no consensus exists regarding the most appropriate model. However,
the modifications made in this analysis were designed to account
for previous limitations of Gaussian-type models in rough terrain.
63
-------
these cases, increased concentrations are predicted to result
from other conditions such as plume looping and limited vertical
mixing.l
Dispersion meteorology is variable over the eight-state area.
By itself, poor dispersion does not cause violation of standards
at any one site. However, when combined with other factors, such
as complex terrain, it can exacerbate what already may be a
problem.
An overview of the effect of site specific variations is
presented in Table 3-8. This table shows the level of control
required for power plants to meet all SO2 standards at our six
sites. To meet all federal ambient air S02 standards, Class II
S02 increments, and applicable state standards, 78-96.2 percent
of the S02 would have to be removed. The specific requirement
depends on the site. Due to Colorado's strict S02 standards, any
facility located in that state will require the removal of more
S02 than in any of the other states. A higher percentage of SO2
removal is required to meet Colorado's standard than to meet
federal Class II PSD increments. The Montana Air Quality Bureau
determines the SC2 removal required according to that state's
NSPS. In Wyoming the state NSPS for power plants is the most
restrictive for' SO2 emissions. In the other three states the
federal Class II PSD (24-hour and 3-hour) increments are the
most restrictive.
C. Other Site Specific Variations
Two other factors that vary by site can exacerbate air qual-
ity problems: the size of the community in which the facility
is located, and the proximity of a facility to potential Class I
PSD areas. As noted previously, the relative change in air
quality will be greater when a facility is located in a small
community than when it is located in a large town. As a result,
in sparsely populated areas such as southern Utah, the change in
air quality will be relatively greater even though the absolute
level of ambient concentrations may be the same as in more
densely populated areas.
1 Plume looping (i.e., when plumes sink to the earth, flow
up and down, or roll in response to breezes, air currents, or
eddies in the area) occurs during periods of light wind speeds of
3-5 knots and strong incoming solar radiation (summertime, mid-
day, clear sky). Large thermal eddies cause plumes to assume a
rolling configuration thus transporting undiluted plume segments
rapidly to ground level. Limited mixing occurs when a strong in-
version exists slightly above the plume height and stops the up-
ward mixing of the plume. The plume is constrained vertically
between this "lid" and the ground.
64
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TABLE 3-8:
SULFUR REMOVAL EFFICIENCIES REQUIRED FOR COAL-FIRED
POWER PLANTS TO MEET ALL FEDERAL AND STATE SULFUR
DIOXIDE STANDARDS
STATE
SULFUR REMOVAL
REQUIRED (%)
GOVERNING
REGULATION
Colorado
Rifle 1,000 MWe
and Mine
96.2
State Category
II Ambient
Montana
Colstrip 3,000 MWe
and Mine
(State NSPS maximum
control capability
technically practicable
and economically feasible
as determined by Air
Quality Bureau); or
80
Federal 24 hr,
Class II PSD
North Dakota
Beulah 3,000 MWe
and Mine
85
Federal 24 hr,
Class II PSD
New Mexico
Farmington 3,000
MWe and Mine
78
Federal 24 hr,
Class II PSD
Utah
Escalante 3,000
MWe and Mine
94
Federal 24 hr,
Class II PSD
Wyoming
Gillette 3,000
MWe and Mine
82
State NSPS
S02 = sulfur dioxide
MWe = megawatt-electric
NSPS = New Source Performance Standards
hr. = hour
PSD = prevention of significant deterioration
65
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Class I PSD areas (such as national parks) may present some
problems where they are widespread or occupy large amounts of
land (as in southern Utah), but very few are located in the coal
regions of the Northern Great Plains. Proximity to Class I PSD
areas will make development siting more difficult, particularly
in the case of electric power plants where large buffer zones are
required.
3.2.4 Regional Impacts
Air quality impacts for the region are dependent on the
existing air quality and meteorological conditions as well as the
overall level of energy development.
The existing ambient air quality in the study area appears
to be good when considered on the basis of annual averages. How-
ever, due to windblown dust, the federal 24-hour primary standard
for particulates is periodically violated. Also short-term
oxidant and HC concentrations, apparently from natural sources,
approach federal standards. Geographically, the southeastern
part of the study area has the best pollutant dispersion potential
because of typically high mixing depths and high wind speeds.
The sharp terrain differences in the Rocky Mountain area can cause
wintertime air stagnation and thus dispersion problems. The Nor-
thern Great Plains area, in contrast, has much less air stagnation
because of higher winds and less rugged, terrain.
Table 3-9 gives the projected emissions from the energy
facilities and associated population for the Northern Great Plains
subregion (Wyoming, Montana, and North Dakota) and the Rocky
Mountain subregion (Colorado, Utah, and New Mexico). These
emission levels are based on the Low Demand scenario for the
year 2000. Emissions in tons per yerar of the four criteria
pollutants are shown as well as the increases above the 1975
levels due to energy development. Except for HC, emissions
associated with the population are only 0.7-3.2 percent of those
associated with the energy facilities. The population related
HC emissions are due primarily to motor vehicles.
Overall, emission levels in the Northern Great Plains are
projected to be higher than in the Rocky Mountain Region. This
is due primarily to the scenario projection that more coal fired
power plants will be sited in the Northern Great Plains than in
the Rocky Mountain states. In the Northern Great Plains, the
largest increase above the 1975 level is NOX which is predicted
to be 4.73-6.47 times greater in the year 2000. The range in
NOX emissions results from the uncertainty associated with how
much NOX will be removed by scrubbers; a range of 0 to 40 percent
removal is assumed. Increases in the Rocky Mountain Region range
from 1.02 (HC) to 1.36-1.51 (NOX) times the 1975 levels.
66
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Emissions from the energy facilities disaggregated by state
are given in Table 3-10. As in the analysis of subregions, the
cause of the relatively high emissions in North Dakota, Montana,
and Wyoming is the large numbers of coal fired power plants sited
there. The largest relative increases above 1975 levels for all
pollutants except HC are in North Dakota. These range from 1.69
(particulates) to 8.41 (NOX) times the 1975 emissions. Montana
is projected to have the largest total emissions of particulates,
S02, and HC. Utah shows essentially no change from the 1975 level
because the only new energy facilities in the Low Demand case
scenario for Utah are two uranium mines and mills.
3.2.5 Summary of Technological and Locational Factors
This summary identifies technology-location combinations
that cause critical air quality problems. By so doing, it also
suggests combinations that could mitigate these problems. The
problems that can arise because of technology-location combina-
tions are identified in Table 3-11. The table also indicates
the technological and locational factors that cause the problem.
Note that the most critical problems are caused by either electric
power plants or oil shale retorting facilities (above-ground).
In some locations in the West, NSPS (generally the least
restrictive federal standards for conditions in the eight-state
area) cannot be met by electric power plants without scrubbers.
This problem is a consequence of the heat and sulfur contents of
the coal.
At some locations, 80-percent efficient scrubbers on power
plants of the size modeled will not be adequate to meet the most
restrictive ambient air quality standards. The existing ambient
air quality, dispersion potential, terrain characteristics, and
tight state standards make it particularly difficult to meet all
standards in southern Utah, Colorado, North Dakota, and Montana.
To overcome this problem, Class II PSD increments would have to
be relaxed, scrubbers with a higher removal efficiency would
have to be employed, smaller plants would have to be built, or
the coal would have to be exported for conversion elsewhere.
Terrain characteristics in southern Utah and western Colo-
rado are such that regular violation of several federal ambient
air standards would occur as a result of emissions from power
plants and from oil shale retorting facilities if the projected
type and level of development occurs. Mitigation will require
very high levels of pollution control or exporting the coal.
The labor intensity of conversion facilities, particularly
the operating labor requirements of synthetic fuels facilities,
results in greater ambient concentrations of particulates, NOz,
and HC being caused by urban sources than by the energy facilities.
If the community in which development takes place is small (e.g.,
68
-------
TABLE 3-10:
PROJECTED EMISSIONS IN SIX WESTERN STATES:
LOW DEMAND SCENARIO3
(thousands of tons per year)
Colorado: 1975
Increase: 2000
Total: 2000
New Mexico: 1975
Increase: 2000
Total: 2000
Utah: 1975
Increase: 2000
Total: 2000
Wyoming: 1975
Increase: 2000
Total: 2000
Montana : 1975
Increase: 2000
Total: 2000
North Dakota: 1975
Increase: 2000
Total: 2000
PARTICULATES
222
22.1
244.1 (1.10)
113
21.0
134.0 (1.18)
79
0.3
79.3 (1.0)
83.1
17.6
100.7 (1.21)
301
48.0
349.0 (1.16)
87.1
59.7
146.8 (1.69)
SO 2
54.2
37.4
91.6 (1.70)
490
28.3
518.3 (1.06)
168
N
168.0 (1.0)
76.5
107.0
183.5 (2.40)
960
305.3
1,265.3 (1.32)
86.6
376.4
463.0 (5.34)
NOX
163
127.5
290.5 (1.78)
220
68.0
288.0 (1.31)
89
N
89 (1.0)
80
282.1
362.1 (4.52)
164
533.2
697.2 (4.25)
94.5
700.1
794.6 (8.41)
HC
213
35.7
248.7 (1.16)
168
-37. 5b
130.5 (.77)
108
N
108 (1.0)
61
11.0
72.0 (1.18)
300
16.4
316.4 (1.05)
77.5
16.4
93.9 (1.21)
S02 = sulfur dioxide
NO = oxides of nitrogen
HC = hydrocarbons
N = negligible
The numbers in parentheses represent the fractional increase (or decrease)
in the year 2000 relative to 1975 levels; i.e., they are the 2000 levels
divided by the 1975 levels.
This number is negative because HC emissions decline through the year 2000.
The increased HC emissions from synthetic fuel facilities are more than offset
by declines in crude oil and natural gas production.
69
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most communities in southern Utah) , the percent change in ambient
air quality as a result of urban sources will be great.
In general, this summary suggests that facilities in Wyoming
and New Mexico are likely to have the fewest air quality problems.
In these states, applicable federal and state standards can be
met with the least percentage removal of S02 and particulates by
emission control technologies. Montana might also be included in
this group except for the uncertainty of how the state NSPS may
be interpreted. But in no case can all standards be met with the
size facilities projected without the use of some emission control,
specifically scrubbers for SOa control.
Facilities located in southern Utah and western Colorado
will present the greatest problems unless removal percentages are
quite high. In Colorado, this is largely due to state SO2 stan-
dards and, to some extent, the terrain in the oil shale area of
western Colorado. Southern Utah appears to have the most restric-
tive combination of factors affecting air quality: a combination
of poor dispersion potential, complex terrain, and Class I areas
that are in close proximity to development sites that make it
necessary for facilities located here to install the most efficient
emission controls.
3.3. WATER AVAILABILITY AND QUALITY
HIGHLIGHTS
CRITICAL FACTORS
Fou/z. ^acton* that vany among te-cknotog-ie.*1 can -ft-ign-L^tca
afifizct wate.fi -Impact* : wate.fi fitiqu.'ifie.me.nt-i,; tabon
-------
WATER REQUIREMENTS
I ฃ wet cooling Is used, electfilc powefi plant* ie.qu.-iin mom
watefi than any otken. conversion technology examined.
Syntholl llque fiactlon fiequln.es less watefi than any otken.
coal synfiuel technology.
Cooling aacounts fiofi 45 to 95 percent o ฃ the. total uiate.fi
fiequlfiements o ฃ coal convex-ton technologies (not includ-
ing wate.fi needed fion. mining the. coal}.
Watefi fie.qmlne.me.nti> fion. enefigy- Delated population Increases
afie, on the. average, one.-te.nth that fion. convzulon ^a-
cllltle.* .
Wate.fi fie.quilfie.me.nti> ^oft e.ne.fLgy-fie.late.d population lncfie.at>e.&
afie., on the. average., one.-te.nth that fiofi conve.ulon
WATER AVAILABILITY
Le-6-6 wate.fi ^on e.ne.figy de.ve.lopme.nt l& available. In the.
Uppe.x. Colorado Rlve.fi Batln (UCRB) than In the. Uppe^
Ml&&oufil Rlve.fi Ba*ln (UMRB); unquantlฃle.d fie.de.fial and
Indian wate.fi filght* , the. &tatu.i> ofi unused allocated
and othe.fi qu.e.i>tlont> make. the. availability ofi wate.fi unce.fitaln
In both
By the. ye.afi 2000, a tow-de.ve.iopme.nt *ce.nafilo would fie.qulie.
12-15 pe.fice.nt ofi the. Aufifiace. wate.fi not pfie.Ae.ntly being
a4ed In the. UCRB; a hlgh-de.mand bcinafilo would fie.qulfie.
59-64 pe.fice.nt.
dJate.fi consumption fiofi cooling by e.le.ctfilc powe.fi plant*
could be. Deduced by 70-79 pe.fice.nt Ifi a combination ofi we.t
and dfiy fiathe.fi than we.t cooling we..ie. u*e.d.
Wate.fi consumption vafile.6 significantly by location fiofi
the. same, coal conv&fislon technology.
EFFLUENTS
The. quantity and composition ofi e,f,filue.nts fifiom the. coal
conve.fislon plants vafiy with location. fofi a glve.n pn.oce.ss,
the. quantity o fi waste. e.{,{jlue.nts vaile.s by a fiactoi ofi fi
ofi filve. depending upon location.
The. ash and sulfiufi conte.nt ofi coal afie. lan.Qe.ly fie.sponslble.
fiofi the. site, variation In the. quantity ofi waste. e.fifilue.nts;
the. highest ash coals afie. fiound In the Southwest.
72
-------
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Assuming the use of wet cooling, coal-fired electric power
plants require more water than synthetic fuel technologies, both
in terms of absolute water requirements, about 24,000 to 30,000
acre-feet per year (acre-ft/yr), and the amount of water required
to produce one million Btu's of energy. Comparing both sets of
estimates, water requirements for synthetic fuel facilities range
from about 5,000 to 17,500 acre-ft/yr, with Synthoil liquefaction
requiring the most (9,230 to 17,460 acre-ft/yr) and Lurgi requir-
ing the least (4,890 to 7,130 acre-ft/yr). Note that minimizing
water requirements in the design and operation of these facilities
as discussed in the following section makes a significant differ-
ence in water consumption. In terms of gallons of water required
to produce one million Btu's of synthetic fuel, Synthoil requires
the least and Synthane gasification requires the most water. In
situ oil shale retorting requires about half as much water as
above ground retorting.
In comparison, a surface coal mine requires only about 5
gallons of water per million Btu's of coal mined (about 3,000
acre-ft/yr).1 Some of the water requirements of coal mines can
be met with water from mine dewatering operations. The water
requirements of coal mining are about one-tenth of that required
by coal-fired power plants. If coal is mined for export only,
additional water requirements for coal export by slurry pipeline
are significant (18,000-19,000 acre-ft/yr or 240-250 gallons per
ton) .
(2) The Effect of Wet/Dry Cooling on Water Requirements
As shown in Table 3-13, water for cooling represents 45.1-
92.3 percent of the total water requirements of coal conversion
facilities. With the exception of oil shale retorting, cooling
is the largest single water user for energy conversion facilities.2
Water requirements for three cooling alternatives were considered:
all wet cooling (high wet cooling in Table 3-13), intermediate wet
cooling, and minimum wet cooling. As indicated in Table 3-13, the
use of intermediate cooling rather than high wet cooling can re-
duce cooling water requirements by 70.3-78.5 percent for power
plants to 18.4-19.4 percent for Synthoil plants. While the water
savings are the greatest for the power plant, the added cost (0.1
assumes that the mine is sized to supply a 3,000 MWe
power plant and that water is used for dust suppression and recla-
mation. See White, Irvin L., et al. Energy From the West; Energy
Resource Development Systems Report. Washington, D.C.: U.S.,
Environmental Protection Agency, forthcoming.
2Spent shale disposal is the largest consumer of water for
above ground oil shale processing. Cooling water accounts for
only 20 percent of the total.
76
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to 0.2 cents per kilowatt hour [kWh])1 would be passed to the con-
sumer.2 The cost of intermediate cooling for coal synthetic fuels
facilities (about one cent per million Btu's of energy produced)
is a much smaller proportion of consumer costs. Variations in
water savings for Lurgi gasification are due to variations in coal
moisture content among sites; unlike other technologies, Lurgi
uses the water in the coal directly.
(3) The Effect of Labor Intensity on Water Requirements
Table 3-14 gives estimates of the additional water required
by the population increases associated with facility construction
and operation. While this water demand averages an order of
magnitude lower than demands for energy conversion facilities, it
is not insignificant. Treatment and distribution systems will be
required to supply water to meet increased demands. In the case
of a technology such as gasification, where water requirements by
the population during peak construction are 4.5 times that required
during operation, overbuilding of treatment and distribution
systems for the construction work force is a potential problem.
B. Water Effluents
Water effluents from energy facilities and population in-
creases are discussed below.
(1) Effluents from Energy Facilities
Effluents removed as dissolved, wet and dry solids are
listed in Table 3-15 for each technology. Effluents from surface
retorting of oil shale are the largest, over 16 million tons per
year (MMtpy) , most of which is dry solids in the form c>f spent
shale. Of the coal conversion facilities, Synthoil liquefaction
produces the highest volume of total effluents and about twice
as much as other synthetic processes. If valued on a Btu-electric
basis, electric power generation produces more effluents per
million Btu's produced than any other facility.
Dissolved and wet solid effluents will be diverted to evap-
orative holding ponds and later deposited in a landfill. Dry
solids may be treated with water to prevent dusting and deposited
in a landfill. As a result, water quality problems from effluent
disposal do not arise from direct discharge to surface water but
Assuming water costs $0.25 per thousand gallons.
2This would increase costs to consumers from about 3 to 6
percent. Gold, Harris, et al. Water Requirements for Steam-
Electric Power Generation and Synthetic Fuel Plants in the Western
United States^Washington, D.C.:U.S., Environmental Protection
Agency, 1977, p. 101.
78
-------
TABLE 3-14:
WATER REQUIREMENTS ASSOCIATED
WITH POPULATION INCREASES3
WATER REQUIREMENTS
(acre-feet per year)b
TECHNOLOGY
Coal
Surface Mine
Underground Mine
Gasification
Liquefaction
Power Plant
Oil Shale
Surface Mine
Underground Mine
Retort and Processing
Modified In Situ
PEAK CONSTRUCTION
71
275
1,570
1,750
853
119
119
450
975
OPERATION
323
1,490
350
1,800
260
194
347
191
941
Assumes 150 gallons per capita per day, a multiplier of
2 to account for added service personnel during construc-
tion, and a multiplier of 3.5 to account for families and
service personnel during operation. Labor intensities
are taken from Section 3.4.
To convert acre-feet per year to gallons per day, multiply
by 893.
indirectly from runoff to surface water and seepage to groundwater.
Runoff from spent shale and water leaching through the shale rep-
resent major potential water quality problems, particularly if
spent shale is dumped into ravines. Total quantities are large,
thus the potential for contamination is great. In no case is
wastewater to be discharged directly into surface or groundwater
systems; wastewater will be treated and recycled on-site.
The content of effluents from power plants and coal synthetic
fuels facilities varies according to the elemental content of
1Under the provisions of the Federal Water Pollution Control
Act Amendments of 1972, Pub. L. 92-500, งง 301, 402; 33 U.S.C.A.
งง 1311, 1342 (Supp. 1976), a permit may be required for this.
Research is continuing into disposal methods for spent oil shale.
Officials of TOSCO contend that after the addition of about 14 per-
cent moisture and proper compaction the spent shale takes on
cement-like qualities and leaching is negligible.
79
-------
TABLE 3-15: SOLID EFFLUENTS FROM ENERGY CONVERSION TECHNOLOGIES'
TECHNOLOGY
Coal
Power Generation
Per Btu electric
Per Btu thermal
Lurgi Gasification
Synthane Gasification
Synthoil Liquefaction
Mine (Power Plant)
Oil Shale
TOSCO II Oil Shale
Underground Oil Shale Mine
Modified In Situ Oil Shale
Processing
Modified In Situ Oil Shale
Processing with Surface Retort
Oil
Conventional Crude Oil
Extraction
Enhanced Crude Oil Extraction
Gas
Natural Gas Wells Production
Uranium
Underground Mine
Surface Mine
Mill
Solutional Mine-Mill
Geothermal
SIZE
3,000 MWe
250 MMscfd
250 MMscfd
100,000 bbl/day
12 MMtpy
50,000 bbl/day
26 MMtpy
57,000 bbl/day
57,000 bbl/day
50,000 bbl/day
100,000 bbl/day
250 MMscfd
1,100 mtpd
(ore)
1,100 mtpd
(ore)
1,000 mtpy
(yellowcake)
250 tpy
100 MWe
TOTAL EFFLUENTSb
(million short tons/year)
0.526-2.554
0.448-1.680
0.447-1.964
0.827-3.651
0.00
16.187
0.00
U
8.8
U
U
0.00
N
N - 0.002
0.367
0.003-0.004
U
(pounds/108 Btu)
15.63-79.04
5.48-26.60
10.91-40.91
10.88-47.83
8.99-39.69
0.00
365
0.00
U
176
U
U
0.00
N
N - 0.01
2.45
0.08
U
Btu = British thermal units
MWe = megawatt-electric
MMscfd = million standard cubic feet per day
bbl/day = barrels per day
MMtpy = million tons per year
U = unknown
mtpd = metric tons per day
N = negligible ,
mtpy = metric tons per year
tpy = tons per year
These data are from Radian Corporation. The Assessment of Residuals Disposal for Steam-Electric
Power Generation and Synthetic Fuel Plants~in the Western United States. Austin,Tex.:Radian
Corporation, 1978. This report extends and is based on earlier analyses conducted by Water Purifi-
cation Associates and reported in Gold, Harris, et al. Water Requirements for Steam-Electric Power
Generation and Synthetic Fuel Plants in the Western United"States. Washington, D.C.: U.S., Envi-
ronmental Protection Agency,1977.
Effluents include dissolved, wet, and dry solids.
sites analyzed.
The range of values is that found at the six
80
-------
the source coal. Accumulations of wet-solids containing heavy
metals, trace elements, and aromatic HC in holding ponds could
produce acute effects in local surface waters, if they are re-
leased accidentally.1 The quantities involved can be quite large.
For example, at a typical site, such as Gillette, Wyoming, the
operation of a power plant, Lurgi, Synthane and Synthoil synthetic
fuel facilities would produce more than 68 million tons of solid
effluents over a 25-year period.
In addition to possible berm failures which would allow pol-
lution of surface waters, seepage from holding ponds can contami-
nate groundwater. The degree of contamination depends on the
composition of materials in the ponds, holding pond design, liner
design, pond management techniques, and the characteristics of
nearby aquifers and of the soil overlaying the aquifer. In turn,
contaminated aquifers may introduce pollutants into local springs,
saeps, and streams. The quality of water in a polluted surface
stream will usually improve dramatically within one to two years
after pollution sources are eliminated; however, polluted aquifers
require much longer periods to cleanse themselves, depending on
local geologic and soil conditions.2
The disposal of effluents from scrubbing or ash removal is
regulated under the Federal Water Pollution Control Act Amend-
ments (FWPCAO of 1972,3 and the Clean Water Act of 1977. * Ground-
water quality is regulated under state laws in Colorado and New
Mexico and, if it is used as a source of drinking water, under
the Safe Drinking Water Act of 1974.5 State solid waste disposal
laws and regulations may also apply to on-site evaporative holding
ponds. As noted earlier, the FWPCA may also apply to the disposal
of spent shale.
folding pond berm design must be site-specific, and failures
are common in areas where previous design experience is not avail-
able. See Smith, E.S. "Tailings DisposalFailures and Lessons,"
in Aplie, C.L., and G.O. Argall, eds. Tailing Disposal Today.
San Francisco, Calif.: Miller Freeman, 1973, p. 358.
2PettyJohn, Wayne A. Water Quality in a Stressed Environment.
Minneapolis, Minn.: Burgess, 1972, p. 96.
3Federal Water Pollution Control Act Amendments of 1972, Pub.
L. 92-500, งง 301, 402; 33 U.S.C.A. งง 1311, 1342 (Supp. 1976).
"Clean Water Act of 1977, Pub. L. 95-217, 91 Stat. 1566, 33
U.S.C. งง 1251 et seg.
5Safe Drinking Water Act of 1974, Pub. L. 93-523, งง 1424,
42 U.S.C.A. งง 300h-3.
81
-------
(2) Effluents From Population Increases
The population increases associated with energy development
will impose increased demands on wastewater treatment facilities.
Assuming that half of the water used must later be treated,1
sewage treatment plants capable of treating 0.03-0.8 million
gallons per day (depending on the technology) will be required
to serve the additional population for each energy facility
constructed. The total solids content of raw domestic sewage
usually ranges from 500 to 1,000 milligrams per liter (rng/&),2
so that the wet-solids generated by population increases range
from 0.06 to 3.3 tons per day (depending on the technology and
solids content of the sewage). A portion of this is usually
disposed of as sludge; it can either be buried in a landfill,
used as a soil conditioner, or fermented to produce methane.
These quantities are at least one thousand times less than the
solids generated by energy facilities. As a result, the water
quality problem associated with population increases is not one
of the quantity of the wastes generated but of providing adequate
treatment facilities.
Even in the quantities projected, untreated or poorly treated
effluents can cause degradation of surface waters. Treatment
facilities in many communities in the eight-state area are already
unable to meet federal and state effluent standards. Since the
need for sewage treatment is highest during the construction phase
of conversion facilities, it may be impractical or infeasible for
many communities to build sewage treatment plants to serve peak
construction work forces that would be underutilized later.
C. Aquifer Disruption
Underground and surface coal, oil shale, and uranium mining
can produce both surface and groundwater impacts. Underground
and surface mines intercept groundwater aquifers, requiring mine
dewatering operations that may deplete aquifers and, in some
cases, create an excess water disposal problem.3 In the area
!In urban areas, the percentage of water use which must later
be treated as sewage is 75-80 percent; we have assumed 50 percent
since some of this population will be rural and served by septic
tanks.
2McGauhey, P.H. Engineering Management of Water Quality.
New York, N.Y.: McGraw-Hill, 1968.
3Sometimes the water obtained from dewatering operations can
be used to supply water for mining, reclamation, and facility
needs.
82
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near Rifle, the oil shale being mined is an aquifer that supplies
Piceance Creek. Mine dewatering can nearly eliminate the base
flow of Piceance Creek (see Section 6.3).
3.3.3 Variations in Existing Conditions
Existing conditions at individual sites and for the region
as a whole will affect the type and degree of water impacts. The
most important variables are the quantity, quality, and asses-
sibility of water, the characteristics of the energy resource
(particularly coal), aquifer characteristics, and climatic con-
ditions. With the exception of water availability, the effect
of these and several other less important variables on water im-
pacts are identified in this section. Water availability issues
are discussed at the regional level in Section 3.3.4.
A. The Quality of Available Water
Table 3-16 gives an indication of the water quality in rivers
which will supply energy facilities. Only total dissolved solids
(TDS) are included because this is the variable that most affects
pretreatment for use by energy facilities or populations. Other
water quality conditions can be important locally. For the six
sites studied, the White River near Rifle has the lowest TDS
(181 mg/ฃ), while Lake Powell near Kaiparowits has the highest
(475-677 mg/ฃ). Portions of the Green River in the UCRB and of
the Powder River in the UMRB have the highest levels of the sur-
face waters studied as shown in Table 3-16.
Groundwater is often higher in dissolved solids than surface
water but concentrations can vary considerably. Quality is gen-
erally better close to the sources of recharge. Because recharge
sites are usually in the mountains, quality generally decreases
as elevation decreases.
The EPA National Interim Primary Drinking Water Regulations
do not specify a maximum level for dissolved solids. However,
EPA has developed "water quality criteria" as one basis to inform
state stream water quality programs and discharge permit applica-
tions. Criteria for domestic use recommend a TDS below 250 mg/i.
The U.S. Geological Survey Classification System calls water
fresh if the dissolved solids content is less than 1,000 mg/Jl;
water is considered suitable for livestock if dissolved solids
are less than 2/500 mg/&.
B. Coal Characteristics and Climate
The coal characteristics at a site determine the quantity
of wet solids in the effluent. In general, the coal character-
istics have only a small effect on process water requirements
83
-------
TABLE 3-16:
TOTAL DISSOLVED SOLIDS IN SURFACE AND GROUNDWATER
(milligrams per liter)
BASIN
Upper Colorado River Basin
Green River
Upper Mainstem
San Juan
Upper Colorado River
Region Outlet
Upper Missouri River Basin
Bighorn3
Tongue3
Powder3
Yellowstone3
Knife3
Missouri Mainstem3
Madison Aquifer
Montana
North Dakota
SURFACE
WATER
307-1,688
207-621
159-447
558
585
380
1,425
525
970
440
GROUNDWATER
1,000-40,000
500-1,000
3,000-10,000
Measured in the Fort Union Coal Region.
except, for the Lurgi process where coal moisture is important.
Climatic conditions affect cooling water requirements and mine
reclamation requirements and thus can affect total plant water
consumption.
(1) Water Requirements
Table 3-17 summarizes water requirements by site. The data
indicate that water requirements for conversion facilities in the
Northern Great Plains (Beulah, Colstrip, and Gillette) are less
than those in the Four Corners Area (Navajo/Farmington and
Kaiparowits/Escalante). Facility water requirements at Beulah
are the smallest, averaging 19 percent lower than those at Navajo/
Farmington. A Lurgi gasification facility at Beulah will use
32 percent less water than at Farmington.
The moisture content of the coal is the principal cause of
these site variations in the case of synthetic fuels. Lurgi
makes direct use of the water derived from the coal, thus account-
ing for the large variations in this process's water use by site;
for other synthetic fuel processes, the water in the coal is
84
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85
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assumed to be lost. The moisture content of coals at the six
sites ranges from 13 percent at Rifle to 36 percent at Beulah.
Variations in the water requirements among sites for elec-
tric power generation result from differences in flue gas de-
sulfurization water requirements (due to differences in the
sulfur content of coal) and differences in the average tem-
perature and humidity at each site; the hotter and more humid
the air, the less cooling water it can absorb via evaporation.
Water requirements for mine irrigation depend on the climate,
seam thickness of the coal, and Btu content of the coal.1 Mine
irrigation water requirements are high at Farmington (Table 3-17)
because of the arid climate and at Beulah because of the low Btu
content of the coal. They are low at Gillette primarily because
of the thick seams characteristic of that area.
(2) Water Effluents
The ash and sulfur content of coal are largely responsible
for site variations in quantities of effluent. At the six sites
studied, coal ash content ranges from 5 percent at Rifle to 19
percent at Navajo/Farmington, and sulfur content ranges from
0.5 percent*- at Kaiparowits/Escalante to 1.0 percent at Colstrip.
Coal with a high ash content will produce larger bottom or fly
ash effluent streams, and coal with a high sulfur content will
produce larger quantities of scrubber sludge effluent.
Table 3-18 indicates the variation by site in the quantity
of solid effluent from four conversion technologies. Similar
patterns are found for each technology; effluents can be more than
four times higher at Kaiparowits/Escalante and Navajo/Farmington
than at Gillette. The large quantity of effluent at Navajo/
Farmington is associated with the high ash content of the coal
(19 percent). Coal at Rifle has the lowest ash content (5 per-
cent) , and power generation there results in the smallest amount
of solids, less than one-fifth of that at Navajo/Farmington.
C. Other Variables
Other factors that vary by site and affect water impacts are
the water requirements of reclamation and the soil and aquifer
characteristics at a site. Water requirements for reclamation
depend largely on climate and coal seam thickness. These require-
ments are expected to be higher in the arid Southwest where average
rainfall is lowest, particularly during the summer growing season,
and where coal seams are generally thinner (10.3 feet at Kaiparowits/
Escalante).
xThe lower the Btu content of the coal the larger the amount
of land disturbed and needing revegetation, all other fcictors being
equal, to supply a given amount of energy.,
86
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Soil and aquifer characteristics are important to the fate
of effluents. Those characteristics vary widely both regionally
and locally; thus, they are particularly important when locating
a disposal pond. Low soil permeability (as in clay) is desirable
to prevent seepage of effluents. More permeable, loamy soils
are desirable in septic tank drain fields to provide higher capac-
ity and better filtration of sewage effluents.
3.3.4 Regional Impacts
Water impacts in the region are dependent on the existing
quantity and quality of the supply and on the kind and level of
energy development. Estimates of the amount of water available
and future requirements are discussed for the UCRB and the UMRB.
Projected wastewater and solid waste generation are given, followed
by a general discussion of impacts.
A. Water Supply Availability and Demand
Surface water availability estimates and the requirements
for the hypothesized energy development (in the year 2000) are
given in Table 3-19. The allocation of water rights and the
legal/political problems surrounding them will be important in
determining whether a portion of the unused water (about 1.5 to
3 million acre-ft/yr in the UCRB) can be used for energy develop-
ment.
As indicated in Table 3-19, by 2000 water requirements for
the energy conversion facilities, assuming wet cooling, and
associated population increase in the UCRB are predicted to be
311.5-1348.8 thousand acre-ft/yr, for the Low Demand and Nominal
Demand cases, respectively. Use of intermediate wet cooling
instead of high wet, at all facilities would reduce this regional
water demand by 19 percent in the Low Demand case, or about 60
thousand acre-ft/yr. Population related water requirements are
about 10 percent of those for the energy facilities. Water demand
will also come from mining operations.
Large quantities of groundwater exist in the UCRB. They are
more evenly distributed than surface water and generally have a
higher TDS content. The most important aquifers in the UCRB
are in alluvial deposite along rivers and streams. These aquifers
are recharged at a rate of 4 million acre-ft/yr (twice the water
available from surface streams) and store a total of 115 million
acre-ft at a depth of less than 100 feet.l Greater quantities
occur in deeper reservoirs.
1Price, Don, and Ted Arnow. Summary Appraisals of the
Nation's Ground-Water ResourcesUpper Colorado Region, U.S. Geo-
logical Survey Professional Paper 813-C. Washington, D.C.:
Government Printing Office, 1974.
88
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In the UMRB, water availability does not appear to be a
problem as a whole; the water not already allocated is well in
excess of anticipated requirements (Table 3-19). However, water
supplies may be inadequate in parts of the UMRB. A great deal
of uncertainty exists with regard to water rights in the UMRB.
These uncertainties appear likely to be less significant than in
the UCRB because a greater excess flow is available. However,
allocations in the Yellowstone River Basin are currently under
review, and the Montana Fish and Game Department and State Health
Department have applied for instream flow allocations of 6.6 and
8.2 million acre-ft, respectively. If granted, these uses would
curtail major diversions in Montana for either energy or agricul-
tural use. Agricultural demands, particularly for irrigation, are
also expected to increase in the future.
Projected water use by the energy facilities in the year 2000,
if high wet cooling is employed, is 882 thousand acre-ft/yr for
the Low Demand scenario and 1216.6 thousand acre-ft/yr for the
Nominal (or 7-10 percent of the total available). A reduction
in water demand of about 40 percent may be realized if inter-
mediate wet cooling is used in the Low Demand case. Potential
reduction in water demand by wet/dry cooling is higher in the
UMRB because oil shale facilities are located, in the UCRB and
the water requirements for oil shale technology can not be re-
duced substantially by the use of intermediate wet cooling.
There are numerous aquifers in the UMRB. A total of 860
million acre-ft is estimated to be stored in the upper 1,000 feet
of rock in the basin.1 However, withdrawal rates are often con-
strained by low permeability.
B. Effluents
Table 3-20 shows total solids and wastewater estimated to be
generated by the energy facilities and related population increases
in the year 2000. The range of values represents differences be-
tween the Low and Nominal Demand cases.
In general, population-related production of solids (almost
entirely as sewage sludge) is negligible compared to those pro-
duced by the energy facilities. The quantity of wastewater
generated by the population, however, is not negligible, being
about 50-90 percent as large as that generated by the energy
facilities.
In the UCRB, oil shale development (both TOSCO II and mod-
ified in situ) contributes 85 percent in the Low Demand case and
Missouri Basin Inter-Agency Committee. The Missouri River
Basin Comprehensive Framework Study, 7 vols. Denver, Colo. : OTs. ,
Department of the Interior, Bureau of Land Management, 1971.
90
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95 percent in the Nominal case of the total solids produced by
energy development in the Basin. This is due primarily to the
spent shale generated. Overall solid effluents in the Nominal
case are more than four times those in the Low Demand case, and
wastewater is more than two times greater in the Nominal Demand
case. In the UCRB, 37-58 percent of the total wastewater from
energy facilities is from the uranium mills.
In the UMRB, solid effluents generated by the energy facili-
ties are estimated to range from 39.06 to 56.91 MMtpy. The quan-
tity of wastewater produced ranges from 119.06 to 171.54 thousand
acre-ft/yr, 80 percent of which is attributed to power plants and
gasification facilities.
3.3.5 Summary of Technological and Locational Factors
Some technology-related problems, in combination with certain
site characteristics, cause water impacts to be particularly
severe. These severe impacts can often be mitigated by choosing
a different technology for the problem site, a different site for
the problem technology, or an entirely different technology-site
combination. Table 3-21 lists the problems that can arise because
of technology-site combinations and indicates the technology-
and site-related factors which cause the problems.
Water for energy conversion facilities is less clearly avail-
able in the UCRB than in the UMRB. Water for energy development
in New Mexico is particularly limited. Since electric power
generation requires more water than any other conversion tech-
nology, a worst-case combination in terms of water impacts is to
site an electric power plant in New Mexico. Further, the generally
low moisture content of southwestern coals and the hot climate
means that energy conversion will require more water in that area.
Groundwater availability for energy conversion is highly un-
certain in both the UCRB and UMRB. There is undoubtedly more
groundwater in the UMRB than in the UCRB, but the amounts in the
Upper Colorado cannot be ignored as a source for energy develop-
ment. Mitigation of water use shortages and conflicts may require
the use of wet/dry cooling (particularly in the Southwest) or the
export of coal from the UCRB.
If groundwater contamination through seepage from evapora-
tive holding ponds (which retain the liquid wastes from power
generation and coal-synthetic fuels) is to be prevented, careful
siting and construction of these ponds will be required. Preven-
tion of groundwater contamination via seepage through spent shale
remains an unsolved problem since spent shale will not be held in
92
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lined ponds. 1 In the vicinity of evaporative holding ponds and
spent shale disposal sites, soil permeability should be low and
aquifers at great depth. The longer any seepage remains in the
soil prior to migrating to an aquifer, the more contaminants that
can be absorbed 'by the soil. Given the uncertainties surrounding
the probable increase in seepage rates over time, migration
calls for strict design standards for evaporative holding ponds
and new approaches to spent shale disposal.
Surface water contamination from untreated or poorly treated
domestic sewage is a potential problem wherever and whenever
population increases outstrip the capacity of sewage treatment
plants. The problem can be critical when construction work forces
are larger than operating work forces, as in the case for an
electric power plant and coal gasification plant. Small commu-
nities, where the capacity of sewage treatment facilities is
limited and effluent quality is marginal, are particularly sus-
ceptible to sewage overloads. Mitigation calls for policies
that require sewage treatment expansion prior to the construction
of a conversion facility or for temporary sewage treatment arrange
ments during the construction phase.
Aquifer disruption, with concomitant reduction in groundwater
flow to surface streams, is a potential problem wherever mining
takes places 'within an aquifer. Although aquifer characteristics
cannot be fully restored, mitigation may require reclamation of
the mined areas as mining proceeds rather than reclamation after
the life of the mine. This may reestablish groundwater flow and
keep to a minimum the length of time flow is disrupted.
3.4 SOCIAL AND ECONOMIC
HIGHLIGHTS
CRITICAL FACTORS
' Thie.e. te.chnotog-i.cat dactoi* can Aign-i^cantty a^e.ct the.
Aoc-iat and. economic -impact* ofi e.ne.igy dave.topme.nt: taboi
cap-itat -intent J,ty; and Ac.ne.du.t-i.ng.
S-cx tocatJ-onat fiactoiA can at&o A^gn-ifi-icantty a^ec-t tke.-!>e.
-impact* ' community ixizn and tocat-ion; capab-it-it-ie.* o&
e.x.-iAti.ng -in* ti.tu.t-Lo n* ; h-i* to tipcat ou.t-m-igiatA.on; chaiacte.1-
-iAt-ic* o& the. tocat taboi faoice.; tocat ^-inanc-ial conduit-ion* ;
and the. cuttuie. and t-i&z*tyte.* o ฃ an ai&a.
:As noted earlier, TOSCO officials contend that moisturizing
and properly compacting spent shale causes a cementation that
greatly reduces leaching problems.
94
-------
LABOR INTENSITY
The. ie.qa-iie.me.ntA fioi housing, AchootA, and othe.1 pmbt-ic and
pitvate. ^actt-it-ie-A and Ae.iv4.ce.A aie. laH.ge.ly de.te.im-ine.d by
the. taboi -inte.nA4.ty o ฃ the, e.ne.igy te.chnotog-ie.A de.ptoye.d.
On an e.qu.4.vate.nt e.ne.igy baA-iA, taboi ie.qa-iie.me.nt A fioi coat
gaAi.6-Lc.at4.on aie. gie.ate.1 than fioi the. otke.fi conve.iA-ion te.ch
notoQ-ie.A conA4.de.ie.d; TOSCO II o-it bnate. tie.tontt (on a pe.fi-'Btui tke.fi-
mat
be.twe.e.n c.on&tfiuc.t4,on and ope.fiat4.nQ
fie.qu.4.fie.me.nti> e.xace.ibate. popu.lat4.on-fie.tate.d 4.mpac.t& . In
c.a&e.t>, Ae.iv -ice. A and ^ac4,l4,t4.e.A w-itt be. 4.nade.qu.ate. du.fL4.ng
the. conAtfiu.ct4.on pkaAe. on o v e.fib u.4.tt ฃ01 the. ope.fiat4.onA pkaAe.,
' Among conve.fiA4.on te.cknotoQ4.e.A , coat gaA4.fi4.cat4.on kaA the.
tafige.At d4.fi fie.fie.nce. be.twe.e.n conAtfm.ct4.on and ope.fLat4.on pkaAe,
tabofL fie.qu.4.fie.me.ntA ; coat ttqae. fiact4.cn haA the. Amatte.At.
SCHEDULING
' S4.muttane.ou.A Ache.dat4.ng ofi tabon. 4.nte.nA4.ve. te.cknotoQ4.e.A -in
an afie.a vottt e.x.ace.fibate. Aoctat and economic -impactA by con-
ce.ntn.at4.nQ the. nu.mbe.fL ofi Moike.fLA and e.x.agge.>Lat4.ng d4.fifie.fL-
e.nce.A -in conAtfLuct-ion and ope.iat4.ng phaAe. tabon. n.e.qvi-in.e.me.ntA .
?iotong
-------
lฃolate.d commu.n
-------
to operational personnel requirements (Table 3-22). A high ratio
indicates that more workers are needed during construction than
during operation. This results in excess requirements for housing,
schools, and other public and private services during the con-
struction phase, and increases the likelihood that services and
facilities will be inadequate and that quality of life will de-
cline. Coal gasification, electric power generation, geothermal
facilities, and oil shale retorting have the highest ratios,
indicating that demands on local communities will be large during
construction and much smaller during operation. Conversely, coal,
uranium, and oil shale mining will have a larger population after
construction is finished.
Obviously, if an energy resource development requires a sub-
stantially greater labor force during construction, a local
building program designed to meet construction population needs
will result in an excess of permanent facilities over the long
term. Likewise, when the construction phase of a development
lasts for several years, facilities designed primarily for the
population size expected over the long term may result in in-
adequate facilities for most of the construction period. In such
a case, some problems can be alleviated rather easily, but others
cannot. For example, schools can schedule double sessions and/or
erect temporary facilities to accommodate additional pupils, but
medical facilities may become overloaded and attracting additional
medical personnel to the area may be difficult. Most doctors
would probably be unwilling to establish practices in these areas,
knowing that they might be forced to relocate within a few years.
Similarly, local landlords and investors would not be likely to
build adequate housing for the short-term population, knowing
that the demand for housing should drop markedly within a few
years.
A second indicator of labor intensity is the sum of peak
construction and operation manpower requirements (Table 3-23).
This indicator suggests that coal liquefaction, crude oil pro-
duction, and coal gasification are the most labor-intensive tech-
nologies for the energy outputs of the facilities assumed in our
scenarios. However, this ordering changes somewhat when a uniform
energy output of 1015 Btu's per year is assumed; under this
assumption, coal gasification, crude oil production, and geothermal
require the most labor. The labor intensity of electric power
generation depends on how the energy produced is measured. If
measured as electricity output, its labor intensity is similar
to that for coal synthetic fuels; if measured as thermal input,
its labor intensity is similar to that of an underground coal
mine. By both measures, uranium mining and milling and surface
coal mining are low in overall manpower requirements.
Larger work forces contribute both directly and indirectly
to population increases in communities near energy development
97
-------
TABLE 3-22: CONSTRUCTION AND OPERATIONAL MANPOWER REQUIREMENTS
FOR ENERGY FACILITIES
FACILITY
Coal
Surface Mine
Underground Mine
Gasification
Liquefaction
Power Plant
Oil Shale
Underground Oil Shale Mine
Modified in situ Oil Shale
Processing^
Modified in situ Oil Shale
Processing with Surface Retort
TOSCO II Oil Shale Processing
Oil
Conventional Crude Oil Production6
Enhanced Crude Oil Production6
Gas
Natural Gas Production6
Uranium
Surface Mine (open pit)
Underground Mine
Solutional Mine
Mill
Geothermal
MANPOWER REQUIREMENTS*
CONSTRUCTION
DURATION
(YEARS)
5
7
5
7
8
4
6
U
6
7
U
4
5
8
2
3
PEAK EMPLOYMENT
210
820
4,680
5,000C
2,540
360
1,950
U
1,340
3,920
U
1,700
80
80
50
90
290
OPERATION
550
3,000
590
2,930C
440
590
510
U
330
2,050
U
790
180
930
60
110
28
RATIOb
0.4
0.3
7.9
1.7
5.8
0.6
3.8
U
4.1
1.9
U
2.1
0.4
0.1
0.8
0.8
10.3
U = unknown
aThe listed requirements are for the typical size facilities shown in Table 3-7. Data
are from Carasso, M., et al. The Energy Supply Planning Model. San Francisco, Calif.:
Bechtel Corporation, 1975, vol~1, pp. 6-JO to 6-31, and involve uncertainties of -10 to
f2C percent; data for developing technologies (coal liquefaction, gasification, and oil
shale processing) involve uncertainties of -30 to -1-75.
bThe ratio expressed is Construction/Operation.
employment decline when construction ends.
The ,larger the ratio, the greater the
cCarasso et al. Energy Supply Model, pp. 6-7 to 6-15. This figure is among those with
the greatest uncertainty. In addition, economies of scale are not incorporated into coal
liquefaction facilities over the 21,700 barrels per day plant assumed by Bechtel. Recent
pilot plant studies have indicated that approximately half the number of operation
personnel will be required.
White, Irvin L., et al.
Washington, D.C.: U.S.,
Energy From the West; Energy Resource Development Systems Report.
Environmental Protection Agency, forthcoming, Chapter 4.
elncludes exploration (including dry holes), development,
et al. Energy Supply Model, pp. 6-7 to 6-15.
and production. See Carasso
98
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TABLE 3-23: MANPOWER REQUIREMENTS FOR ENERGY FACILITIES
FACILITY
Coal
Surface Mine
Underground Mine
Gasification
Liquefaction
Power Plant
Btu electric
Btu thermal
Oil Shale
Underground Oil Shale Mine
Modified in situ Oil Shale
Processing
Modified in situ Oil Shale
Processing With Surface Retort
TOSCO II Oil Shale Processing
Oil
Conventional Crude .Oil Production
Enhanced Crude Oil Production
Gas
Natural Gas Production
d
Uranium
Surface Mine (open pit)
Underground Mine
Solutional Mine-Mill
Mill
Geothermal
Btu electric
Btu thermal
ASSUMED
FACILITY
SIZE
12 MMtpy
12.7 MMtpy
250 MMcfd
100,000 bbl/day
3,000 MWe
26 MMtpy
57,000 bbl/day
57,000 bbl/day
50,000 bbl/day
50,000 bbl/day
100,000 bbl/day
250 MMcfd
1,100 mtpd
(ore)
1,100 mtpd
(ore)
250 tpy
(yellowcake)
1, 000 mtpy
(yellowcake)
100 MWe
MANPOWER REQUIREMENTS*
FOR ASSUMED
FACILITY
760
3,820
5,270
7,930
2,980
950
2,460
U
1,670
5,970
U
2,490
260
1,010
110
230-310
320
FOR PRODUCTION
OF 10 ! 5 Btu/yearb
3,960
19,900
64,170
43,100
44,280
15,520
5,690
24,330
U
18,830
64,910
U
30,320
870
3,370
1,470
772-1,040
141,760
49,690
Btu/year = British thermal unit per year
MMtpy = million tons per year
MMcfd = million cubic feet per day
bbl/day = barrel per day
MWe = megawatt-electric
U = unknown
mtpd = metric tons per day
tpy = tons per year
mtpy = metric tons per year
Source: Carasso, M., et al. The Energy Supply Planning Model, 2 vols. San Francisco,
Calif.: Bechtel Corporation, 1975.'
alncludes both peak construction and operation employment requirements (see Table 3-22),
'10'
Btu's per year in the product.
cRecent pilot plant studies have indicated approximately half the operating personnel
will be required.
Assumes ore contains approximately 0.2 percent yellowcake.
99
-------
sites. Larger populations mean larger demands for housing,
public facilities, and public and private services, as well as
greater stress on roads and streets and law enforcement agencies.
Thus, any large and rapid increase in population creates a sub-
stantial demand for additional services and facilities from local
governments.
B. Scheduling
The construction schedule for the energy facilities within
a local area is an important technological factor which influences
the extent of local population impacts. When several facilities
are constructed at the same time small, rural communities will
probably be unable to accommodate the population growth.1 For
example, simultaneous scheduling of technologies that are labor
intensive in their construction phase will cause the workers for
two or more projects to be located in the same area at the same
time. Currently, no means exist to coordinate the scheduling of
several energy developments in an area, and such a goal might
only be met by limiting the rate of development of western re-
sources. Institutional inadequacies impede joint public and
private sector planning. At the least, industry and local govern-
ment often fail to communicate with each other in advance of
development. Also, both are affected by federal policy and
associated uncertainties.
Conversely, if construction is prolonged, so is the period
of population instability. It may be easier for communities to
deal with temporary construction-related impacts if the period
of instability is minimized.2 If construction of successive
projects involves large gaps of time with no construction, com-
munities may become dependent on construction projects to reduce
unemployment and add to local economic stability. Thus, service
shortages may take place each time construction occurs and unem-
ployment when it does not.
Walton, Barry L. "Population Growth Constrained Synthetic
Liquid Fuel Implementation Scenarios," Chapter 22 in Dickson,
Edward M., et al. Impacts of Synthetic Liquid Fuel Development:
Automotive Market, Vol. III. Menlo Park, Calif.: Stanford
Research Institute, 1976.
2Planning for stability would require adequate information
from all energy developers in the area as well as an adequate pro-
fessional planning capability. See White, Irvin L., et al.
Energy From the West: Policy Analysis Report. Washington, D.C.:
U.S.,Environmental Protection Agency,forthcoming.
100
-------
C. Capital Intensity
A community benefits economically from energy development
primarily through increases in its tax base and revenues beyond
the expenditures needed to meet expanded facilities and services
requirements, and increases in personal incomes. Given the tax
structure in most communities, an expanded property tax base and
increased revenues are the most important sources of benefit; the
extent of the community's benefit from both depends on the capital
intensity of energy facilities. Large conversion facilities, in
particular, are contributors to local revenues and can produce
substantial excess revenues in the long term.
In the short term, however, even capital-intensive facilities
cause problems because property taxes generally are not available
during construction when the demands on local governments are often
greatest. Further, there is a jurisdictional division between mu-
nicipalities experiencing most of the population impact and service
demands and the counties and school districts receiving the taxa-
tion benefits. This is discussed further in Section 3.4.3.
Local merchants and local residents employed by energy
developers tend to gain most economically during the construction
phase. However, the majority of construction workers usually
come from outside the local area.1 This, of course, reduces the
benefits that residents often anticipate before construction be-
gins. During operation, a relatively large number of workers
tend to be local residents, and new opportunities open up in
local service industries.
3.4.3 Variations in Existing Conditions
The conditions that exist at an energy development site play
a large part in determining the actual type and degree of social
and economic impacts. For example, impacts will vary depending
upon such factors as community size and location, capabilities
of existing institutions, historical out-migration, characteristics
of the local labor force, local financial conditions, and the
.culture and lifestyle of an area.
A. Community Size and Location
The most important existing condition that influences the
extent of population impact is the size of a community before
energy development begins. Larger cities have more diversity
and capacity for growth in both the public and private sectors.
Our research suggests that communities of less than 2,000
JFor documentation of this, see Mountain West Research. Con-
struction Worker Profile, Final Report. Washington, D.C.: Old
West Regional Commission, 1976.
101
-------
population will almost always have inadequate services and
planning capabilities.1 Communities of up to 5,000 also may
fall into this category. Conversely, cities of 10,000 or more
(especially those greater than 25,000) usually have a developed
community service system and planning professionals.2 Thus,
in most larger communities, lead-time problems are reduced because
they generally have plans for expansion, although acquiring funds
for expansion may be a problem regardless of city size.
In addition to size, the number of communities in the vicin-
ity of an energy development will affect the relative impacts on
each town. An isolated town that is the only possible place for
workers and their families to live will receive much greater im-
pacts than one town in an area where the new population is more
widely distributed.3 Construction of a new town is a partial
solution to the inability of any single community to absorb new
population. A similar solution is for an energy developer to
provide housing and community services by expanding an existing
village or town.4 However, developers do not always do so,
leaving the cost of streets, water, sewer, and other services
to very small, unincorporated towns. In many cases, state and
county laws and regulations are not adequate to control growth
in these settlements. Large cities of 25,000 population or more
can more easily absorb population growth, simply because the
growth represents a smaller proportion of their initial size.
Planning and growth management capabilities consist primar-
ily of a full-time staff of professional planners, good knowledge
of existing facilities in the town, and a. plan of future develop-
ments in anticipation of growth.
2For documentation of recent energy-related growth in western
towns of all sizes, see U.S., Federal En>rgy Administration, Region
VIII, Socioeconomic Program Data Collection Office. Regional Pro-
file: Energy Impacted Communities. Lakewood, Colo.: Federal
Energy Administration, Region VIII, 1977.
3For example, Gillette's isolation in northeastern Wyoming
has resulted in greater impacts for Gillette than have occurred
in Rifle, Rangely, Meeker, and Grand Valley in western Colorado,
where several towns share the impacts. See Chapters 6 (Rifle)
and 7 (Gillette).
4For information on the activities of energy developers in
this area, see Metz, William C. "Residential Aspects of Coal De-
velopment." Paper presented at the Meeting of the American Insti-
tute of Planners, Kansas City, Missouri, October 1977; and White,
Irvin L., et al. Energy From the West; Policy Analysis Report.
Washington, D.C.: U.S., Environmental Protection Agency, forth-
coming.
102
-------
Although the private sector often is slow in responding to
increased demands for goods and services in rapid-growth situa-
tions, the reaction of local governments has tended to be even
slower, especially in smaller towns.1 Availability of funds is
a major cause of this lag for all communities, but the time span
is usually greater in small communities because of their lack of
planning capabilities. Moreover, outside entities, rather than
local businesses, are more likely to meet private service needs
in smaller communities, with the result that much of the economic
benefit can flow out of the local area.
B. Capabilities of Existing Institutions
As the site-specific analyses in Chapters 4-9 indicate,
growth leads to demands for housing and essential public facili-
ties and services, for professional services, and ultimately for
social and cultural opportunities. Many western rural communities
are not accustomed to providing such a full range of services and,
in any case, are severely strained by the rate at which these
demands escalate. Moreover, the manageability of these problems
is often reduced by inadequate tax bases and planning capabilit-
ities.2
Besides governmental service problems related to growth,
most small communities affected by energy development will more
than double in size, resulting in newcomers outnumbering natives
(including former residents who return because of the employment
opportunities energy developments offer). Not only will community
leadership probably shift from the small businessmen and ranchers
who presently lead these communities, but the dominant attitudes
and values of the townspeople will probably change. Thus, the
new majorities and leaders may force communities to make changes
and undertake programs that current residents presently oppose.
For example, many of these communities have an antipathy to plan-
ning and are reluctant to seek or accept assistance from other
levels of government.3 Yet, regardless of leadership or values,
most of these communities must develop a planning capability and
Creese, Gerald, et al. The Impact of Large Installations
on Nearby Areas; Accelerated Urban Growth. Beverly Hills, Calif.
Sage, 1965, p. 589.
2See the discussion of community facilities and services in
White, Irvin L., et al. Energy From the West; Policy Analysis
Report. Washington, D.C.IU.S.,Environmental Protection Agency,
forthcoming, Chapter 9.
3See Christiansen, Bill, and Theodore H. Clack. "A Western
Perspective on Energy: A Plea for Rational Energy Planning."
Science, Vol. 194 (November 5, 1976), pp. 578-84.
103
-------
accept intervention and assistance from state and federal govern-
ments. In fact, these communities may even play a leading role
in bringing pressure to bear on state and. federal governments
to provide assistance.1
Increased strain in intergovernmental relations is another
impact of rapid population growth. The sources of strain can be
found in almost every problem area that has been discussed in
this chapter, but particularly in the problems of: the benefits
of public revenue increases accruing to jurisdictions other than
the ones which must provide expanded municipal services; the
pressure on the states and the federal government to provide
assistance to impacted areas; and uncoordinated regulatory and
policy roles assumed by various levels of government.
C. Historical Out-Migration
Some areas, particularly in the Northern Great Plains, have
seen their populations decline gradually for several decades.2
In some ways, historical out-migration puts those areas in a
better position to accommodate rapid energy development. First,
excess capacity in adequately maintained community facilities,
such as schools and water supply, could allow time before new
facilities must be constructed. This is a luxury not available
in most parts of the West, where medium-size cities have ex-
perienced recent growth and generally have no excess capacity.3
Another advantage of recent out-migration is that many of
the people who had moved away may want to return to work in energy
development. This could reunite many families and, from a com-
munity point of view, less social readjustment will be necessary
than with a work force completely unfamiliar to the area.
D. Local Labor Force
Another existing condition that influences the extent of
population impact is the size and composition of the local labor
force. If local unemployed and underemployed persons are afforded
^.S., Congress, Senate, Committee on Environment and Public
Works. Inland Energy Development Impact. Assistance Act of 1977.
Hearings before the Subcommittee on Regional and Community Devel-
opment, 95th Cong., 1st sess., August 2 and 27, 1977.
2For example, North Dakota has faced net declines in three
of the last four decades.
3U.S., Federal Energy Administration, Region VIII, Socio-
economic Program Data Collection Office. Regional Profile;
Energy Impacted Communities. Lakewood, Colo.: Federal Energy
Administration, Region VIII, 1977.
104
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the opportunity of training programs, the number of nonlocal
workers required might be significantly lowered. This is more
easily accomplished for operation than for construction trades,
which often require years of specialized experience. Of all
construction occupations, those most likely to be filled by
local residents are laborers, cement finishers, and carpenters,
but even those occupations have involved 40 to 50 percent nonlocal
workers. The proportion is up to 80 percent for some skills.1
Energy employment represents an opportunity for Indian
nations to share in industrial development if they wish it, al-
though the lack of training among Indians is a barrier to employ-
ment. However, many Navajo workers have acquired training, es-
pecially in coal mining operations, and have joined labor unions,
at least in part because of the higher earnings associated with
union jobs.2
Unless lease terms or training programs are focused on local
residents, the largest category of new employment for local re-
sidents tends to be in relatively low-paying service jobs, perhaps
in new businesses established by local entrepreneurs. Profes-
sional and other more specialized service jobs (such as in medi-
cine and education) induced by population growth also commonly
go to outsiders. Larger communities will experience more job
switching to new employment opportunities, but even in these towns
specialized skills are unlikely to be available in great numbers.
E. Local Financial Conditions
Two major site-specific variables are the legal and financial
capacities of local governments to respond in a timely manner.
Some state governments have passed legislation enabling communi-
ties to act decisively on their own and have established programs
!Mountain West Research. Construction Worker Profile, Final
Report. Washington, D.C.: Old West Regional Commission,1976.
2The United Mine Workers operate the Black Mesa Mines, and
the Operating Engineers man the Utah International Mine at Four
Corners. Locals of both unions have approximately 70 percent
Navajo membership. Robbins, Lynn A. Navajo Participation in
Labor Unions, Lake Powell Research Project Bulletin No.15.Los
Angeles, Calif.: University of California, Institute of Geophysics
and Planetary Physics, 1975.
3Gray, Irwin. "Employment Effect of a New Industry in a
Rural Area." Monthly Labor Review, Vol. 92 (June 1969), pp. 26-
30; Summers, Gene F., et al. Industrial Invasion of Nonmetro-
politan America. New York, N.Y.: Praeger, 1976.
105
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to provide funding assistance from taxation on energy resources
specifically aimed at impacted communities.
The adequacy of new revenue for impacted communities will
depend primarily on timing and distribution; that is, funds for
the expansion of community facilities and services will not al-
ways be available at the proper times or in the most appropriate
jurisdictions. Four of the states in the study area (Montana,
North Dakota, Utah, and Wyoming) have taken special actions to
deal with the initial capital requirements of cities and counties.
Their programs are described in the impact analyses reported in
Chapters 4-9. Briefly, these programs provide impacted commun-
ities "front-end" money with which to meet facility and service
requirements. Utah permits the prepayment of taxes for state-
related public improvements; and Montana, North Dakota, and
Wyoming have statutory formulas for earmarking a portion of
revenues from mineral leasing and severance taxes for payment
directly to the impacted communities. The effectiveness of these
programs depends on distribution formulas and policies, as dis-
cussed in Chapter 9 of our Policy Analysis Report.1
However, state programs resolve only part of the timing
problem associated with getting funds to local governments and
do even less to resolve completely the larger distribution prob-
lem. For example, county governments, the principal recipient
of ad valorem property taxes, are often major beneficiaries of
new revenues produced by energy development but, as noted earlier,
cities and towns normally must provide most of the services and
facilities. In Utah, Wyoming, and Colorado, special districts
for water, sewers, schools, fire protection, and other purposes
can bridge the city/county jurisdictional boundary and insure
that new revenues are used at the impacted locations.
Based on the results of the regional impact analysis reported
in Section 11.4.4, long-term energy-related revenues at the state
and local levels will exceed in the aggregate the new revenues
required to serve the expanded populations. However, the types
of legislation discussed here (and conscientious administration
of the programs by the designated state boards) will be necessary
to insure that the revenues are used when and where they are
needed. The present programs in some wesstern states have the
opposite effect and, in fact, cause a lag between the time when
impacts are experienced and when revenues are available.
LWhite, Irvin L., et al. Energy From the West; Policy
Analysis Report. Washington, D.C.: U.S., Environmental Protection
Agency, forthcoming.
106
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F. Quality-of-Life, Lifestyle, and Culture
"Quality-of-life" is largely a subjective attribute composed
of a variety of factors. Usually though the availability of
medical care, professional services in general, and adequate
housing play an important role in residents' opinions on the
quality of their lives. When public and private services are
unavailable, the local quality-of-life is generally considered
to be low.!
The capability to plan adequately for local population im-
pacts will largely determine the quality-of-life impacts in the
West. Service infrastructure, such as utilities and streets,
are common concerns for local residents. In the private sector,
housing shortages handled by mobile homes are not very satisfac-
tory either to those living in them or to others in the community.
For a variety of reasons, doctors tend not to locate in small,
isolated towns, making medical care a particular area of concern
for energy impacted communities.2 Industry response in these
service areas is variable, and cooperation with local governments
will doubtless be needed to maintain quality of life.
Lifestyle and cultural differences influence the way in
which individuals perceive local attributes. Long-time residents
in some isolated areas tend neither to expect nor to need the
same set of services as newcomers, although in some areas new-
comers and long-time residents have held similar opinions about
local conditions.3 Generally, opinions are affected by the con-
trasts in the lifestyles of ranchers and townspeople, energy
development workers and farmers, Mormons and non-Mormons, and
Indians and non-Indians. The clear-cut contrast between Indian
and non-Indian values and communities is the most noticeable
example of cultural differences.1*
JMountain West Research. Construction Worker Profile, Final
Report. Washington, D.C.: Old West Regional Commission, 1976;
and Gilmore, J.S., and M.K. Duff. Boom Town Growth Management.
Boulder, Colo.: Westview Press, 1976.
2Coleman, Sinclair. Physician Distribution and Rural Access
to Medical Services, R-1887-HEW.Santa Monica, Calif.:Rand
Corporation,1976.
3See Mountain West Research. Construction Worker Profile,
Final Report and Community Reports.
**See U.S., Department of the Interior, Bureau of Indian
Affairs, Planning Support Group. Draft Environmental Impact State-
ment; Navajo-Exxon Uranium Development. Billings, Mont.: Bureau
of Indian Affairs, 1976.
107
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3.4.4 Regional Impacts
Region-wide social and economic impacts discussed in this
section are population and economic impacts, and the effects of
the personnel and capital requirements of energy development.
A. Population Impacts
One of the most important factors that will influence popula-
tion change is the number and location of energy development per-
sonnel. Table 3-24 shows construction-related, operation-related,
and total population increases for the eight state study region
using low energy demand projections.1 By the year 2000, the data
in Table 3-24 indicate that the population will increase by
662,000 or about a 7 percent increase over the 1975 population
of 9,551,000. Of this total increase, operation-related popula-
tion is about 72 percent and construction-related is 28 percent.
The population impacts are not evenly distributed over the
region. For example, the coal areas of the Northern Great Plains
region (Montana, North Dakota, and Wyoming) are expected to have
a considerably larger population increase than the other states
in the West. This is due to the large scale and type of develop-
ment as well as an estimated net in-migration of workers of 66
percent.2 Further, the impacts vary by state. For example,
within the Northern Great Plains, increases in population^ aboye_
the 1975 level, are predicted to be from 27 percent (North Dakota)
to 36 percent (Wyoming). In general, although the population
increases from energy development will not be large region-wide,
the development will largely take place far from metropolitan
areas and will impact small towns and rural areas the most.
B. Economic Impacts
(1) Personal Income
Because of job opportunities, energy development is expected
to generate new income for current residents and newcomers.
Energy development is expected to increase the total real (constant
dollar) income in the six state area by about 16 percent during
the 25 year period (1975-2000). This is in addition to income
growth from other sources. Most income growth will occur during
the 1990's, when energy development alone would induce an annual
growth rate of income of 1.06 percent.
1 Refer to Section 11.1.
2Refer to Section 11.4.2.
108
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TABLE 3-24: POPULATION" INCREASES IN WESTERN STATES
AFTER 1975 DUE TO ENERGY DEVELOPMENT
1
YEAR
1980
1985
1990
2000
CONSTRUCTION-
RE LATED3-
31,600
32,400
20,900
187,300
OPERATION-
RELATED
45,000
118,200
157,200
474,600
OVERALL
INCREASE
76,700
150,600
178,100
661,900
Based on the average annual construction
employment for the construction period of
each facility and the projected number of
facilities.
As with population, income gains are not evenly distributed
among states. Over the 25 year period, Wyoming would experience
the greatest relative gain (49 percent) and Utah the least (1.3
percent). By the per capita measure, the greatest absolute gain
is expected in Montana ($630 per year), while Utah would have
the least ($30 per year). These increases in per capita income
would be due in large part to the construction phase of energy
development.
Finally, additional impacts due to inflation are expected to
occur. Increased wages will usually more than compensate for
increased prices, but retirees and individuals with fixed incomes
are likely to be adversely affected.
(2) Secondary Industries
Energy development will also affect the economic structure
of the region by attracting secondary industries. Growth is
expected for large industries linked directly to the energy
facilities and for local and regional services industries re-
sponding to population growth.
Industrial expansion for "supplier" industries is expected
to occur primarily outside the region, in existing northeastern
or west coast industrial complexes; Salt Lake City is the most
likely city in the study area to be affected. "User" industries
(or those associated with processing the by-products of the
energy facilities) are also expected, but are highly unpredictable
in size and location. Some possible by-products for processing
109
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Industries including sulfur, nahcolite (naturally occurring
sodium bicarbonate), tar, and ammonia.1 Whether user industries
will be established ,in the region depends on the quantity of
by-product produced. If there is not an adequate amount gener-
ated, they will tend to be transported out of the region for
processing. For example, a minimum of 3-4 Lurgi plants is cur-
rently considered necessary to attract firms that would use their
by-products.
Two types of service industries will evolve and expand as
a result of energy developments: those that serve the needs of
energy developers (e.g., machine shops, accounting firms, and
supply houses) and those that are related to the population
growth. In the case of service industries serving the energy
developers, expansion is very difficult to predict since many
energy developers and construction contractors provide these
services themselves. However, impacts will probably occur in
the larger cities such as Casper and Grand Junction. The second
type of service industry (wholesale and retail trade) responds
primarily to the growing population. In general, although the
retail sector in small towns grows with population, the largest
absolute growth will tend to concentrate in large centers.
(3) Expenditures and Revenues
Since much of the development of energy resources will occur
in sparsely populated areas, small communities will face greatly
expanded demands for services. Table 3-25 shows predicted invest-
ments for public facilities by the year 2000, for the Low Demand
case. These range from $14.9 million (Utah) to $426 million
(Montana) and are mostly for water supply, sewage treatment and
school buildings. Local and state operating expenditures (above
1975 costs) for the year 2000 (Low Demand case) are also given
in the table. The total new local operating expenditures for
the region are expected to be $344.2 million; school districts
account for 75 percent of this total. Local and state increases
in annual expenditures are most extreme in Montana and North
Dakota, and the Northern Great Plains states account for about
78 percent of the total state expenditures predicted for the
region by 2000.
Estimated revenues, above the 1975 level, are also shown for
the six states and the region in Table 3-25 for the year 2000.
A total of $2.95 billion is likely to be collected in the six
a further discussion of the various by-products from
energy development facilities and their uses, see Section 11.4.3,
110
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state region, but revenues collected in Montana amount to 45
percent of the total.*
With the additional revenues from taxes levied on energy
production and conversion, most state and local governments can
be expected to derive more funds from new revenues than they
expend on new costs. As emphasized above, the determinant of
actual surplus or shortage, however, is the timing and distribu-
tion of funds. If states do not distribute revenues to local
governments (particularly municipalities), or if impacted local-
ities do not receive property tax benefits, then an overall sur-
plus of funds at the state level is meaningless at the local
level.
C. Personnel Availability
The question of personnel availability is addressed primarily
on the regional and national levels because it is unlikely that
local communities will be able to fill the skilled positions
required by the energy technologies. The key point is whether
rapid energy development could be delayed by a nationwide shortage
of certain skilled personnel. Although shortages are not expected
in broad engineering and managerial categories, the demand from
energy development will tighten markets for specialized profes-
sions, such as mining engineers, boilermakers, and welders. The
demand for certain personnel may also noticeably raise salaries.
In general, the demand for all personnel can be met, but will'
require expanded training programs, either as formal education
or in the form of apprenticeships.
D. Capital Availability
The development of western energy resources would require
large investments. The four energy technologies which contribute
most to capital demands are surface coal mining, mine-mouth power
generation, coal gasification, and oil shale processing. By the
year 2000, the gross investment for these facilities in the West
is expected to be over $70 billion.
The capital requirements for the proposed energy facilities
are not a large fraction of the total capital required nationally
for plant and equipment (1.5 percent over the 25 year period with
a maximum of 3.7 percent from 1991-2000).. However, joint ventures
and outside financing will likely be required because single
companies are unlikely to have adequate capital to cover individual
facilities.
'This is due largely to Montana's relatively high coal sever-
ance tax of 30 percent.
112
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3.4.5 Summary of Technological and Locational Factors
When a technology-related, impact-causing factor interacts
with certain site-related conditions, social and economic impacts
can be magnified. Potentially critical problems caused by energy
technologies being located in the West are listed in Table 3-26
together with the combinations of technology and site related
factors that cause them.
Coal synthetic fuels technologies (and to a lesser extent
oil shale retorting and electric power generation) are relatively
labor intensive. High labor intensity and high peak construction
to operation labor ratios, in combination with small, isolated
communities where institutional planning capacity and financial
capabilities are inadequate, cause social impacts to be magnified
into critical problems (e.g., inadequate housing, schools, roads,
and health care).
A substantial number of the impacts on these communities can
be alleviated (or even eliminated) if the development choice is
to "strip and ship" the coal rather than to convert it to some
other energy form at the mine-mouth. In fact, local communities
might escape most of the stresses and strains associated with
energy resource development if more of the raw resources were
exported from, rather than converted within, the region. However,
important fiscal disadvantages are associated with the export
option. The most obvious disadvantage is that taxes based on the
assessed valuation of large-scale conversion facilities and activ-
ities would accrue to nonwestern areas. If that tax gap is to
be filled, the typical fiscal alternative would be to develop an
extraction or severance tax that falls either directly or indi-
rectly on mining activity. This would tend to raise the price of
energy delivered to the conversion facility (e.g., a power plant
near Chicago), perhaps putting the exporting state at a competi-
tive disadvantage with states that have lower severance taxes.
The extreme effect could be to drive mining companies to other
states.
When mining is relatively labor intensive, as underground
coal mining is, the negative economic impacts on state and local
governments may be magnified. In such a case, the increased pop-
ulation would haye to be served, but, as stated above, much of
the tax base would have been exported together with the coal.
Scheduling multiple labor intensive technologies so that
the rate of increase in demand for services escalates rapidly
causes the same impact problems as those described above. However,
the scheduling factor causes the problems to become critical for
larger communities as well as small, isolated ones. Avoiding
simultaneous scheduling of several energy developments, especially
several conversion facilities, in an area may only be possible by
slowing the overall rate of development of western resources.
113
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The extent to which the local labor force can be tapped by
the energy facility will largely determine the distribution of
income benefits between long-time westerners and newcomers. Be-
cause of the specific skill mix and overall labor requirements,
mining can generally draw on the local labor force for a signifi-
cant percentage of labor requirements. On the other hand, the
skills required for conversion facilities (especially during
construction) are quite specialized and overall labor requirements
are high. The percentage of newcomers required by them will be
much greater than those for mining. Training programs aimed at
the local labor force can alleviate the problem to some degree.
The combination of the capital intensity and labor intensity
of a technology determines the relationship between financial
benefits from development (in the form of tax revenues and personal
income increases) and financial costs (in the form of housing,
schools, and other services) . While the financial benefits which
accrue from conversion facilities generally exceed their financial
cost, the jurisdictions which must bear the costs (usually cities
and towns) often do not receive the benefit. Jurisdictional
arrangements for distributing financial benefits vary by location.
In states that do not have legislation enabling communities to act
on their own or programs to provide funding assistance aimed at
impacted communities, this income distribution problem will be
critical and lead to strained intergovernmental relations.
3 . 5 ECOLOGICAL
HIGHLIGHTS
CRITICAL FACTORS
F-iue te.chno logical ^acton.& can ^Ign-i^lcantly a^e.ct the.
e.coloQ4,cal 4.mpactA> o& e,ne.figy development: land tie.qu4.fie.-
n\e.ntt> , wate.fi tie.qu.4.tie.me.nt-t> , wate.fi e.^f,lu.e.nt-!> , labofi 4.nte.nt>4.ty
and a4.fi e.m .
Tou.fi Ioc.at4.onat ฃactofiA can al&o
Impact* : cl-imate., topography, &o-il&, and plant and animal
LAND REQUIREMENTS
V4.fie.ct land u4e by Aufi&ace. m4.n4.ng can be. 10 t4.me.& gfie.ate.fi
than faofi u.nde.sigiound m-tne.6 and coal co nv e.tiฃ> -to n
Suifiace. coal mi.x. t-ime.t> mote land than do Auifiace. m^cne-i -in Wyoming to pfio
duce the. 4ame amount o ฃ eneigt/. Potent-Lai ^on. ne.tabl4.i>k-
4,ng ve.ge.tat4.on 4.n ne.cla4.me,d land* i.t> h4.ghe.fi -in the. Nofitke.fin
Gfie.at Plaint than In the. Rocfet/ Mou.nta4.nA ofi
115
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Land uAe. to me.e.t the. ne.e.dA o& e.ne.rgy~re.late.d population
growth Qe.nnn.ally produce.* more. Aignifiicant e.cological
impacts than doe.A land uAe.d dire.ctly by the. energy
faacilitie.* .
Land ate. by any Aingle. de.ve.topme.nt ge.ne.rally disturb*
only a small pe.rce.ntage. o ฃ a habitat type.} hou)e.ve.r, even
a small disturbance. can be. significant i& the. habitat is
a rare. type., a* aquatic habitat is Jin. the. study are.a.
WATER REQUIREMENTS
Withdrawals oฃ local ^a^jjace u)ate.i by any A^ingle. conve.u an e,x.ce.ption.
o& local &u.fi^ace. wate.ni> ^on multiple,
at the. -dame, location could eliminate. Aome. &po>it
Attie.am& , alte.n. the. plant communitie.A Auppotiting othe.fi
and sie.du.ce. >iipan.ian habitat.
LABOR INTENSITY
The. mote labon inte.nt>ive. a te.chnology, the. mone. like.ly
that e.cological impact* Mill be. significant a* a ne.&ult
o^ land uAe., habitat fiiagme-ntaticn, wate,n withdrawals, and
tLeb; ^or Aome. AubAtance.A Auch aA
me.rcury, conce.ntrationA in the. tiAAue. o& carnivore.A alre.ady
exceed
3.5.1 Introduction
The severity of ec61ogical impacts depends on the technology
deployed and the type of ecosystem affected. For example, tech-
nologies differ in their land, water, and labor requirements, and
sites differ in their climate, topography, soils, and plant and
animal communities. Although many uncertainties exist regarding
ecological impacts from energy development, several technological
and site specific factors are identified which apparently can con-
tribute to impacts.
116
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3.5.2 Variations by Technologies
Six factors that vary among technologies can negatively
affect ecosystems: land use, labor intensiveness, water require-
ments, water effluents, air emissions, and type of transportation
system for the energy products.
A. Land Use
Direct ecological impacts are caused by land disturbances
at mine and plant sites. These disturbances result in the tem-
porary removal of vegetation and, therefore, animals dependent
on the vegetation. Variations in land use by technology are com-
pared in Table 3-27 for facilities deployed in our scenarios.
Although land requirements for most conversion facilities are
very similar on an energy-equivalent basis, a typical size power
plant requires about three times more land than gasification
facilities, and Synthoil liquefaction requires about twice as
much as gasification. Land requirements are also large for
TOSCO II oil shale retorting, largely because of spent shale
disposal. Land use for underground coal mines is similar to that
for conversion facilities; however, surface coal mines can require
10 times more land, depending on the seam thickness and heating
value of the coal.
By eliminating, reducing, or changing vegetation, direct
land use reduces the overall carrying capacity of an area, frag-
ments habitat types, and may increase erosion. When carrying
capacities are lowered, animal populations, such as deer and
elk, may also be reduced. Fragmentation also reduces animal
populations that range or migrate over large areas. Increased
erosion will speed nutrient and runoff losses from affected areas
within ecosystems. Thus, where nutrients or water already limit
vegetation growth, erosion and limited water retention further
reduce both plant growth and carrying capacity for animals.
Generally, the amount of land disturbed directly by any one
mine-plant combination is small compared to the area of entire
counties or the total amount of habitat in a region. Thus, the
impacts resulting from direct land use occur locally; they have
regional importance only when the habitat disturbed is rare or
supports endangered species. For example, riparian ecosystems
are rare in the West; five percent reduction in riparian habitat
in a location has much greater impacts than eliminating five per-
cent of a desert shrub community which is very common. Similarly,
eliminating black-footed ferret habitat (an endangered species)
has different implications than eliminating mule deer habitat.
117
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TABLE 3-27: LAND USE BY TECHNOLOGY
TECHNOLOGY
Coal
Power Plant
Per Btu electric
Per Btu thermal
Lurgi Gasification
Synthane Gasification
Synthoil Liquefaction
Surface Mineb
Underground Minec
Oil Shale
TOSCO II Oil Shale Processing
Underground Oil Shale Mine
Modified in situ Oil Shale
Processing
Modified in situ Oil Shale
Processing with Surface Retort
Oil
Conventional Crude Oil Extraction
(well field) Enhanced Crude Oil
Gas
Natural Gas Production/Processing
Uranium
Underground Mine
Surface Mine (open pit)
Mill
Solutional Mine-Mill
Geothermal
Per Btu electric
Per Btu thermal
SIZE
3,000 MWe
250 MMscfd
250 MMscfd
100,000 bbl/day
12.2-19.2 MMtpy
12 MMtpy
50,000 bbl/day
26 MMtpy
57,000 bbl/day
57,000 bbl/day
50,000 bbl/day
250 MMscfd
1,100 mtpd
(ore)
1,100 mtpd
(ore)
1,000 mtpy
(yellowcake)
250 tpy
(yellowcake)
100 MWe
LAND USE:
TYPICAL SIZE*
(acres per 30 year life
of facility)
2,400
805
805
2,060
3,300-25,200
1,760
2,150d
500e
180f
1,2408
1,000
850
70
3,450
280
200
4-37
ENERGY EQUIVALENT
(acres per 10 lz
Btu in product)
1.2
0.4
0,3
0.3
0.4
0.6-4.4
0.3
0.8
0.1
0.06
0.4
0.4
0.3
0.01
0.03
0.06-0. 5
0.02-0.2
Btu - British thermal unit
MWe * megawatt-electric
MMscfd = million standard cubic feet per day
bbl/day = barrels per day
MMtpy - million tons per year
mtpd = metric tons per day
mtpy * metric tons per year
tpy = tons per year
For facilities, this is the land required for the facility site. For surface mines, the 30 year
life value was obtained by multiplying the number of acres stripped in 1 year by 30 years.
This represents the size range for mines required to supply coal to a 3,000 MWe power plant.
clncludes only that portion of the mine site to be permanently occupied. At Kaiparowits, 30,000
acres will be subject to subsidence over the 30-year life of the mine. It is expected that nearly
all of this land will be reclaimed and returned to productive use.
-------
B. Labor Intensiveness
If reclamation attempts are successful, variation in the
labor intensity of technologies may be more important than land
used by the facilities or mines. Increased population contributes
to air and water pollution, as well as increased land requirements
for housing, transportation, service needs, and recreation. Con-
version technologies are more labor intensive than mining. Sur-
face mining is the least labor intensive energy technology de-
ployed in our scenarios and gasification and crude oil production
are the most labor intensive.1
The types of ecological impacts from population increases
are similar to those caused by land use for facility siting. More
housing, roads, and service activity fragment habitat into small
parcels that are less usable by either resident or migratory
species. Easier access to recreational areas often results in
increased hunting. Recreational use can also increase erosion,
damage vegetation, degrade aquatic habitat, and disturb ter-
restrial wildlife. Habitats which are most at risk are high
alpine ecosystems (particularly lakes), high and middle-elevation
streams and riparian habitats in deserts. Where public land is
accessible to new urban populations, back-country recreation in
the form of camping, hunting, fishing, and off-road vehicle (ORV)
use will be extensive and can cause major ecological changes.
C. Water Requirements and Aquifer Interruption
The most pervasive ecological changes due to energy resource
development will occur in streams and rivers that experience
severe reductions in flow resulting from reservoirs, consumptive
water use, groundwater depletion, and runoff interception. Dif-
ferences in water requirements among technologies and opportunities
to minimize water use can significantly affect ecological impacts.
As indicated in Section 3.3, electric power generation con-
sumes the most water, and cooling represents the single largest
part. Synthoil liquefaction requires less water than other
conversion facilities; surface mining requirements (including
irrigation) are an order of magnitude less than conversion facil-
ities. Minimizing cooling water requirements by using combina-
tions of wet and dry cooling can minimize the threat to aquatic
ecosystems.
Water savings from the use of combinations of wet and dry
rather than wet cooling were discussed in Section 3.3. Total
*Data on the labor intensiveness of the technologies deployed
in our scenario are presented in Section 3.4.
119
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consumptive water use by these technologies in the UCRB can be
reduced by about 20 percent with the use of wet/dry cooling. The
largest percentage reductions can be obtained for electric power
plants; up to 20,340 acre-ft can be saved per year for a 3,000
MWe plant. While the water saved for synthetic fuel facilities
is not nearly as much, it can be large enough to reduce impacts
to aquatic ecosystems at some sites in our eight-state study
area. When the savings are aggregated for several facilities in
the same watershed, the benefits to aquatic ecosystems are even
more important.
Impacts caused by flow reductions will vary seasonally.
Normal flows in spring will be sufficient for fish migration and
spawning; lower flows during summer will reduce habitat and water
quality, thereby interfering with the growth and survival of
some fishes; and low flows in winter can cause ice-scouring,
thereby reducing the population of aquatic: invertebrates that
support fish in spring and summer. Flow reductions also narrow
the margin of marshlike habitat which parallels many streams.
This riparian habitat supports large and diverse communities of
waterfowl and shorebirds. Since riparian habitat is particularly
scarce in the eight-state area, any reduction constitutes a large
percentage loss in its availability.
Both coal and oil shale mines require dewatering as mining
progresses. The marsh habitat along stream margins may be the
interface of groundwater with surface water, or may be affected
by springs. To the extent that aquifers are dewatered, habitat
will be narrowed or eliminated.
D. Wastewater Effluents
Wastewater for conversion facilities is generally impounded
in on-site evaporative holding ponds. Both the quantity and
content of the effluent discharged to these ponds will vary by
technology (see Section 3.3). Of coal conversion technologies,
Synthoil liquefaction produces the largest quantities of effluents
and Lurgi gasification the least.
Impounded effluents from power plants are primarily scrubber
sludge and ash, while effluents from synthetic fuel facilities
are primarily ash. Effluents from synthetic fuels facilities
also contain heavy metals such as nickel, zinc, and lead as well
as potentially cancer-producing polynuclear aromatic hydrocarbons
(PAH). If the dikes around impoundments fail or erode, the wastes
could destroy some stream communities, reducing productivity for
several years.1 Additionally, some metals may seep or leak through
^.S., Department of the Interior, Bureau of Land Management.
Draft Environmental Impact Statement: Proposed Development of Oil
Shale Resources by the Colony Development Operation in Colorado.
Washington, D.C.: Bureau of Land Management, 1975.
120
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the liners of the ponds even if they are properly designed and
maintained, thus contaminating groundwater and surface water.
Heavy metals and organic compounds can also be a problem.
Heavy metals can contaminate stream ecosystems where they are
cycled in and through food webs. Both aquatic plants an animals
have low tolerance to heavy metals. If water is used for drinking
and/or fish taken from the streams are eaten by people, contamina-
tion carries with it potential health hazards. However, the
extent to which contamination and food web uptake is likely to
occur is uncertain.
E. Air Emissions
The most ecologically dangerous criteria pollutants produced
by energy facilities appear to be S02 and NOX. Maximum ground-
level concentrations of SO2 produced by conversion facilities are
known to cause both chronic and acute damage to sensitive native
and crop plants.1 Although maximum worst case concentrations
will occur infrequently, S02 emissions from electric power plants
in areas of rugged terrain, such as southern Utah, and sulfur
emissions from oil shale facilities in western Colorado can sub-
ject vegetation to acute damage.
ป/
Mercury is contained in some stack gases from power plants
and coal synthetic fuels facilities. While the amount of mercury
emissions is uncertain, any additional levels could worsen ecologi-
cal problems in some areas. For example, in the Lake Powell area,
mercury concentrations in some predatory fish already exceed Food
and Drug Administration standards for safe human consumption.2
Projections based on Lake Powell studies indicate that energy de-
velopment might cause mercury increases between 10 and 50 percent,
Hertzendorf, M.D. Air Pollution Control Guidebook to
U.S. Regulations. Westport, Conn.: Technomic, 1973, pp. 154-55;
U.S., Department of Health, Education, and Welfare, Public Health
Service. "Effects of Sulfur Dioxides in the Atmosphere on Vegeta-
tion," in Air Quality Criteria for Sulfur Oxides. Washington,
D.C.: Public Health Service, 1969, pp. 61-69; and Benedict, H.M.,
C.J. Miller, and R.E. Olson. Economic Impact of Air Pollution on
Plants in the United States. Menlo Park, Calif.: Stanford Re-
search Institute,1971, pp. 40-46.
2Standiford, D.R., L.D. Potter, and D.C. Kidd. Mercury in the
Lake Powell Ecosystem, Lake Powell Research Project Bulletin No.17
Los Angeles, Calif.: University of California, Institute of Geo-
physics and Planetary Physics, 1973, p. 16.
121
-------
depending on the number of facilities and the composition of the
coals being used.1
F. Transportation Technologies
Transportation systems for the technologies considered in
this study include unit trains, slurry pipelines, gas and oil
pipelines, and EHV transmission lines. Each of these transporta-
tion modes can produce ecological impacts. Unit trains are
potentially the most destructive to biological resources. Rail
lines built for heavy unit train traffic pose a hazard to large
animals (e.g., antelope) which move in herds over large areas
during the year. Since some railroad right-of-way is likely to
be fenced on both sides to protect -livestock, the migration of
some herds over their accustomed ranges will be restricted if
new lines are built. Thus, crossings may have to be constructed
to allow them to pass. If fences are not built, animals can be
killed by the trains.2
Other transport modes are less disruptive to wildlife. Pipe-
lines result in negligible impacts.3 EHV transmission lines alter
habitat types, reducing forested area for example. However, this
alteration may add beneficial ecological diversity in some regions.
At present, there is inadequate information about electric fields
from EHV lines to assess impacts.
3.5.3 Variations by Existing Conditions
The severity of impacts summarized in the previous section
will also depend on the ecological characteristics of the site
where technologies are deployed. Important site specific variables
are grouped into three categories in this discussion: physical
and biological characteristics, such as climate, soils, and plant
and animal communities, which determine ecosystem stability and
resiliency; present land use characteristics, such as the extent
to which a region is pristine or wilderness and the extent of
public land ownership; and instream flow, which affects dilution
of polluted runoff.
^tandiford, D.R., L.D. Potter, and D.C. Kidd. Mercury in the
Lake Powell Ecosystem, Lake Powell Research Project Bulletin No.IT
Los Angeles, Calif.: University of California, Institute of Geo-
physics and Planetary Physics, 1973, p. 16.
2See Sections 3.7 and 11.6 for a more extensive description
of levels of unit train traffic and the problem trains can pose
for animals.
3Slurry pipelines require 740 acre-ft of water per ton of
coal and can contribute to the water impacts discussed above.
122
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A. Ecosystem Stability and Resiliency
Both the reclamation potential of a site and the response
of an ecosystem to exposure to chronic air pollutants depend on
the ecosystem's stability and resiliency. Stability is the ability
of a system to remain unchanged under stressful conditions, where-
as resiliency is the ability of a system to recover following a
stress-induced change. The response of ecosystems in the West
to impacts such as fragmentation, addition of mineral elements,
nutrient losses, and chronic exposure to air pollutants is largely
a function of their stability. Reclamation potential is largely
a function of resiliency.
(1) Climate
Average rainfall data for three areas within the eight-state
study area are given in Table 3-28. Both total amounts and the
seasonal distribution are included. The Southwest receives the
least amount of rainfall overall. In the Rocky Mountain and
Northern Great Plains, total rainfall is similar, but rainfall
during the summer growing season in the Northern Great Plains
is twice that of the Rocky Mountains. Since the amount of rain-
fall during the growing season is probably the single most im-
portant factor affecting reclamation potential, reclamation will
be most easily accomplished in the Northern Great Plains and most
difficult in the Southwest. Moreover, reclamation problems will
be worsened in some areas of the Southwest, where land require-
ments for surface coal mines can be very large. As shown in
Table 3-29, land requirements for a typical size mine at Navajo/
Farmington are much larger than those at Colstrip or Gillette;
hence, water requirements for reclamation will also be higher.
Using present reclamation techniques, areas averaging 10 or
more inches of rainfall per year can generally support plant re-
growth without supplemental irrigation.1 In most of the semiarid
Southwest, rainfall is regularly less than 10 inches and varies
widely from year to year. Periodic dry periods lasting up to
several years further curtail successful revegetation. The
seasonal distribution of rainfall is perhaps the most critical
variable; for example, a lack of precipitation shortly after
planting can reduce seedling success, and a difference of only
1-2 inches over the entire growing season will have significant
consequences. Because most reclamation studies have been initiated
National Academy of Sciences. Rehabilitation Potential of
Western Coal Lands, a report to the Energy Policy Project of the
Ford Foundation. Cambridge, Mass.: Ballinger, 1974; and Packer,
Paul E. Rehabilitation Potentials and Limitations of Surface-
Mined Land in the Northern Great Plains, General Technical Report
INT-14. Ogden, Utah: U.S., Department of Agriculture, Forest
Service, Intermountain Forest and Range Experiment Station, 1974.
123
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TABLE 3-28: RAINFALL AVERAGES IN THE WEST
REGION
Northern Great Plains
Rocky Mountains
Southwest
RAINFALL3
(inches)
WINTER
<5
5-10
<5
SUMMER
10-20
5-10
<5
ANNUAL
10-20
10-20
<10
< = less than
aEspenshade, Edward B., ed. Goode's World Atlas,
13th ed. Chicago, 111.: Rand McNally, 1971;
winter corresponds to November I/April 30; summer
corresponds to May I/October 31.
TABLE 3-29: LAND USE FOR SURFACE COAL MINES BY SITE'
SITE
Navajo/Farmington
Gillette
Colstrip
Beulah
TYPICAL SIZE MINEb
(acres over 30 years)
24,900
3,300
10,200
25,200
ENERGY EQUIVALENT
(acres per 10 12 Btu)
4.3
0.6
1.7
4.4
Seam thickness and heating values assumed: Navajo/Farmington
10.3 feet, 3,600 Btu per pound; Gillette64 feet, 8,000 Btu per
pound; Colstrip28 feet, 8,600 Btu per pound; Beulah13 feet,
6,950 Btu per pound.
In all cases, the mine size assumed supports a 3,000-megawatt-
electric power plant.
124
-------
since 1970, there has been no opportunity to observe precisely
how rainfall variations, affect long-term reclamation success.
(2) Soils
Natural surface soils vary greatly within the eight-state
study area; even a single mine site may contain several soil
types that differ in suitability for reclamation. In the Northern
Great Plains, soils are generally well developed with adequate
nutrient and organic matter. These soils have a high potential
for use in mine-spoil revegetation.
Three major soil types are found in coal-producing regions
of the Central Rocky Mountains: soils of dry sagebrush areas
which are generally poor in organic matter; rocky or barren bad-
lands soils which are less than 20 inches deep and subject to
water erosion; and loamy, easily tilled soils which are rich in
organic matter. These latter soils are usually found on western
Colorado coal lands and are often farmed for dryland crops. All
three types of soils will probably require irrigation for success-
ful reclamation.
Soils in Arizona and New Mexico are generally poorly devel-
oped, have an unsatisfactory moisture-holding capacity, and have
a high salt content. Moreover, these soils have become sandy and
eroded through overgrazing. Drifting and blowing soils in these
areas can easily bury seedlings or reduce plant cover by abra-
sion.
(3) Plant and Animal Communities
The dominant plant communities found in three areas of the
eight western states are given in Table 3-30. For each area,
these communities are listed in increasing order of structural
complexity and productivity. In the Rocky Mountains and Southwest,
increased productivity generally corresponds to higher elevation
and rainfall. For example, in the Southwest, the desert shrub
community is located at low elevations where rainfall is often
less than five inches, whereas the pinon-juniper woodland is
located at higher elevations where rainfall is often greater
than 10 inches.
In general, the more complex a plant community is, the more
stable but less resilient it is. A grassland is generally not as
stable as a forest and its ability to remain unchanged in the face
of stresses is not as great as that of the forest. Thus,
farmer, E.E., et al. Revegetation Research on the Decker
Coal Mine in Southeastern Montana, Research Paper INT-612. Ogden,
Utah: U.S., Department of Agriculture, Forest Service, Intermoun-
tain Forest and Range Experiment Station, 1974.
125
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TABLE 3-30: PLANT COMMUNITIES AND THEIR PRODUCTIVITY
REGION
PREDOMINANT
PLANT COMMUNITIES
PRIMARY PRODUCTION3
(grams per square
meter per year)
Northern Great
Plains
Rocky
Mountains
Southwest
Short grass prairie
Midgrass prairie
Bottomland forest
Pine savanna
Desert shrub
Pinon-juniper woodland
Mountain shrub
Mountain meadows
Coniferous forests
Desert shrub
Desert grassland
Pinon-juniper woodland
600-900
600-1,100
1,000-2,000
1,000-2,000
100-200
500-1,000
600-700
700-1,100
900-2,000
0-200
200-500
500-1,000
aRanges given represent rounded estimates from Cooper, J.P., ed.
Photosynthesis and Productivity in Different Environments, Inter-
national Biological Programme 3. London, England: Cambridge
University Press, 1975. In this context, primary production
refers to the "net" production of organic matter (including root
and shoot growth) by the plant community; that is, it measures
the rate at which solar energy is converted to organic matter.
overgrazed grasslands often revert to desert shrub communities.
On the other hand, a grassland can more readily reestablish it-
self after surface mining than forest can. Similarly, it is
easier to reestablish a desert shrub community than a grassland.
The productivity of 'a plant community measures the rate at
which plants produce organic matter and support animals. Soil
characteristics and the seasonal distribution of rainfall are the
most critical factors limiting this rate. Irrigating reclaimed
land allows higher primary production rates and faster revegeta-
tion. However, an irrigated reclamation site may be limited by
soil nutrients or by unusually high concentrations of salts.
This appears more likely in the Southwest.
126
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B. The Character of Present Land Use
Changes in wilderness areas can occur rapidly as new popula-
tions enter a development area. Energy developments in northern
Wyoming, western Colorado, and southern Utah are particularly close
to national parks and scenic and wilderness areas. Particularly
in southern Utah and western Colorado, both residents and visitors
generally expect to encounter native plant communities, wildlife,
and scenic vistas. On the other hand, land in the Northern Great
Plains is largely agricultural. Thus, the nature of the ecological
impacts will be different than those of the Rocky Mountain areas.
Availability of public land (such as national forests and
parks, wildlife refuges, and wilderness areas) in the vicinity
of energy development also influences ecological impacts. The
federal government owns 87 percent of the land in the area around
Kaiparowits/Escalante, 70 percent around Rifle, 39 percent around
Navajo/Farmington, an additional 60 percent around Gillette, and
5 percent around Colstrip and Beulah. Public access to national
forests has few restrictions. Where public land is accessible
to populations associated with energy development, back-country
recreation in the form of camping, hunting, fishing, and ORV use
will increase. Although valued by residents, unrestricted or
unenforced recreation potentially can cause ecological damage,
including damage to wildlife habitat and alterations in the
natural state of wilderness areas.
C. Stream Flow
Impacts on aquatic ecosystems will probably occur in the San
Juan Basin, in the Utah-Colorado oil shale area, and, in the
Yellowstone River Basin. Growth in agricultural irrigation and
energy developments may add nutrient-, pesticide-, and silt-laden
runoff to these river basins. Increased withdrawals for agricul-
ture and energy development will reduce flows and concentrate
existing pollution levels.
The Yellowstone River Basin could experience withdrawals
from the river itself or its tributaries amounting to about 22
percent of typical low flows, depending on the use of reservoirs
to regulate discharge. From Billings, Montana to the Missouri
confluence, the Yellowstone River is free-flowing; there is now
strong public sentiment in favor of keeping it free of dams and
restricting industrial uses.1 Impoundments on tributaries to the
Yellowstone are likely to interfere with the spawning movements
of several fish indigenous to the UMRB (e.g., the paddlefish,
shovelnose sturgeon, and pallid sturgeon).
1Montana, Department of Natural Resources and Conservation,
Water Resources Division. Which Way? The Future of Yellowstone'
Water, Draft. Helena, Mont.: Montana, Department of Natural Re-
sources and Conservation, 1976.
127
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3.5.4 Regional Impacts
Development poses two major ecological stresses on the re-
gional level: consumptive water use, and changes in land-use
patterns.
Regional impacts on aquatic and riparian habitats are most
likely to result from water shortages. As discussed in Section
3.3, total demands for water in the UCRB by the year 2000 are
likely to exceed that not currently used (approximately two mil-
lion acre-ft/yr) . If this occurs, or if large percentciges of
available flows are withdrawn, damage to aquatic specie's could
occur throughout the basin because concentrations of pollution
would increase. These problems are much less likely for the Upper
Missouri, where total basin flows are well in excess of expected
withdrawals.
Use of land for energy conversion facilities, surface mines,
and increased population could also damage terrestrial ecosystems
on a regional level. Table 3-31 shows regional land requirements
for energy facilities (not including mines) and for urban growth.
About 70,000 acres of land will be required in the Rocky Mountain
area. Energy conversion facilities account for about 73 percent
of this and urban land about 27 percent. About 130,000 acres will
be disturbed in the Northern Great Plains. Energy facilities
and urban growth account for about equal proportions of this.
Population increases will be larger in this area because more
labor-intensive synfuel facilities are expected.
At the aggregate level, as many facilities are sited in one
location, direct land use can affect or eliminate a large per-
centage of habitat types and result in significant reductions
in carrying capacity. For example, development of one TOSCO II
oil shale retorting facility disturbs only 0.3 percent of the
150 square mile area between Parachute Creek, Rifle, and the
Colorado River in Garfield County. Construction of 10 such
facilities would disturb more than 30 percent. Ecological im-
pacts tend to increase exponentially with such expansion. Entire
populations of animal species such as deer and elk could be
eliminated in these locations, and their range in the West will
be reduced.
3.5.5 Summary of Technological and Locational Factors
This summary identifies technology-location combinations
that cause significant ecological problems (Table 3-32) . Overall
ecological degradation is increased when the land use affects
habitat that is not .abundant (e.g., riparian or unique habitat
used by endangered species or by wildlife during some part of
their life cycle). These habitats will be most threatened by
labor-intensive technologies, primarily liquefaction and gasifica-
tion, which result in the largest population increases and by
128
-------
TABLE 3-31:
LAND USE BY REGION IN THE" YEAR 2000
(Low Demand case)
USE
Energy facilities
Urban land
Total
ROCKY MOUNTAIN REGION3
(39,726,720 acres)
51,175 (0.13%)
18,805 (0.05%)
69,980 (0.18%)
NORTHERN GREAT PLAINS b
(150,282,880 acres)
65,615 (0.13%)
63,301 (0.13%)
128,916 (0.26%)
aArea includes Garfield, Mesa, Rio Blanco, and Huerfano counties
in Colorado; Kane, Garfield, Uintah, and Grand counties in Utah;
and San Juan, McKinley, Valencia, Lea, Eddy, Roosevelt, and
Chavez .counties in New Mexico.
includes Bighorn, Powder River, and Rosebud counties in
Montana; Campbell, Johnson, Sheridan, Converse, Natrona, Carbon,
Fremont, and Sweetwater counties in Wyoming; and Dunn, Mercer,
McLean, Oliver, Billings, Bowman, Hettinger, McKenzie, Slope,
Stark, and Williams counties in North Dakota.
surface coal mining in areas where coal seams are thin (e.g.,
Farmington) and where the coal has a low heating value (e.g.,
Beulah). Land use by multiple surface coal mines and oil shale
facilities at a site can affect a large percentage of total habitat
at that site, resulting in habitat fragmentation which can elimi-
nate wildlife and endangered species. These impacts will be less
likely if land is successfully reclaimed. Although much uncer-
tainty exists about reclamation potential throughout the study
area, the most difficulty will apparently occur in the arid
Southwest because of low average rainfall. Expanding energy
development and related population growth will threaten natural
wilderness areas, particularly around areas which have not ex-
perienced previous rapid growth. Energy developments in southern
Utah, western Colorado, and northern Wyoming present the biggest
threat to wilderness areas and natural ecosystems.
Water-intensive technologies, particularly electric power
generation, located where stream flows are marginally adequate
(the San Juan Basin, western Colorado, and to a lesser extent the
Yellowstone Basin) will reduce or eliminate sport fish populations.
Domestic wastewater discharged into streams can change plant and
animal populations, and runoff or seepage from on-site eavporative
holding ponds can further degrade stream and lake habitat.
129
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Episodic ground-level SC-2 concentrations from air emissions
by electric power plants and oil shale facilities can be high
enough to cause chronic and acute damage to plant communities
in areas where the terrain is rugged, most notably in southern
Utah and western Colorado.
Railroads cause more ecological impacts than any other trans
portation alternatives. Where rail transport crosses migratory
mammal routes, changed migration patterns will occur and acciden-
tal kills will increase.
3.6 HEALTH EFFECTS
HIGHLIGHTS
CRITICAL FACTORS
' Two main te.chno logical fiactorA can Algnl&lcantly a^e.ct
the. public, he.alth ImpactA ofi e.ne.rgy de.ve.lopme.nt: The.
quantity and compoAi.t4.on o& air e.mlAAlonA, and the. quan-
tity and compoAltlon o & wate.r e.^lue.ntA . The. type, ofa
e.Ktractlon technology, principally mining, a^e.ctA the.
A to worke.r Aaฃe.ty.
locatlonal fiactorA can alAo significantly a^e.ct the-&e.
: compoAi.ti.on and type. o& the. e.ne.igy n.e.&ou.n.ce.,
popalat'ion chasiacte.titAtฃc , topography, me.te.ono logical
e.x.i*Ati.ng health cafie. de.JLtve.tiy t>yAte.mA, and
POTENTIAL PUBLIC HEALTH RISKS
Coal-&tie.d potoei plant* and t>ynthe.ti.c fiu.e.1
the. A-lze. hypothe.Ai.znd and wi.th attainable. e.m^AAi.on contnolA
do not cauAe. ฃe.de.sial pfitmatiy ambte.nt SO 2, pait-iculate.,
NO?, and CO AtandaidA to be. vi.olate.d.
!{, a 3 pe.fice.nt AiLl^afi to Aul&ate-A conve.fiAi.on fiate. i.A
aAAume.d, Animate. le.ve.lA attributable, to e.ne.figy de.ve.lop-
me.nt are. not e.x.pe.cte.d to exceed the. conce.ntrati.onA known
to canAe. di.Ae.aAe.. Howe.ve.r, i,^ a 5 pe.rce.nt conve.rAi.on
rate. i.A aAAume.d, Aul^ate. le.ve.lA at Aome. Ai.te.A Mill be.
hi.gh e.nou.gh to aggravate. aAthmati.cA . A conve.rAlon rate.
ofa JO pe.rce.nt could re.Ault In chronic and acute. re.Aplra-
tory dlAe.aAe..
The. &e.de.ral AtandardA fior WOf are. not proje.cte.d to be.
vi.olate.d; hou)e.ve.r, Ahort te.rm pe.ak conce.ntratlonA firom
powtr plantA and aAAoclate.d urban growth are. pro j e.cte.d
to exceed conce.ntrati.onA that have, been re.late.d to In-
cre.aAe.d re.Api.ratory lllne.AA.
131
-------
The. kide.fia.Jt pfii.ma.tiy ai.fi bta.nda.fid. ^oti HC wi.ll be. violated
by the. hypothe.bi.ze.d coal lique. faction, o-il bhate, ie.totiti.ng,
natufial gab ^aclti.ti.e.b , and by utiban boutice.b. Concun-
ttiatlonb could be. ab much ab 240 ti.me.b the. Ata.nda.tid.
Qt-idantb pfioduce.d fitiom the.be. HC e.m
-------
emission rates largely account for the potential public health
impacts of energy development. This section summarizes the dis-
cussion in Chapter 10 concerning the implications for human health
of S02 and sulfates, particulates, HC, oxidants, NOX, trace
elements, and radioactive materials. They will be discussed
separately, although adverse health effects often result from a
complex of emitted pollutants rather than from a single pollutant
acting by itself.
(1) S02 and Sulfates
Energy conversion facilities, particularly power plants, will
contribute to higher S02 levels. However, in the scenarios studied,
the increase in SQz caused both by energy facilities and associated
population growth will generally be below the federal primary
ambient air standards designed to protect human health. Never-
theless, due to sulfate formation, which is currently not covered
by federal ambient air standards, these levels of SOa emissions
could represent a health hazard. Evidence is accumulating that
the sulfates into which S02 is transformed pose the greatest
potential for harmful health effects. Estimates of conversion
rates vary from 1 to 20 percent per hour;1 however, rates of
from 1 to 3 percent per hour are commonly estimated for SO emis-
sions from coal-fired boilers. Table 3-33 gives the sulfate con-
centrations projected for the six site-specific scenarios, assuming
four different conversion rates. For perspective, sulfate levels
known to cause disease are also included in the table. As indi-
cated, conversion rates of less than three percent do not cause
sulfate concentrations to be in excess of those which are known
to cause a health effect. Conversion rates of 5 percent result
in concentrations at three sites which exceed those known to ag-
gravate asthmatics, and conversion rates of 10 percent would
clearly result in health hazards.
(2) Particulates
Particulate emissions can vary widely by technology. Even
with 99 percent particulate removal, electric power plants emit
more particulates than any other conversion facility. However,
in no case examined does a power plant alone cause primary ambient
air standards for particulates to be violated.
Nevertheless, because particulate removal systems trap
larger particles more efficiently than smaller particles, coal-
fired power plants can still represent a significant health risk.
With 99 percent efficient particulate removal, particles will
^.S., Congress, House of Representatives, Committee on Sci-
ence and Technology, Subcommittee on Environment and the Atmosphere.
Review of Research Related to Sulfates in the Atmosphere, Committee
Print.Washington,D.C.:Government Printing Office,T976.
133
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TABLE 3-33:
SULFATE CONCENTRATIONS AND THEIR
HEALTH EFFECTS
(micrograms per cubic meter)
CASE
Scenario3
Kaiparowits/Escalante
Nava jo/Farming ton
Rifle
Gillette
Colstrip
Beulah
Health Effectsb
Aggravation of asthma
'Increased chronic
bronchitis
Increased acute
respiratory disease
CONVERSION RATES
(% per hour)
1
2.2
0.8
1.5
0.5
0.9
1.1
3
6.6
2.4
4.5
1.5
2.7
3.3
5
11.0
4.0
7.5
2.5
4.5
5.5
10
22.0
8.0
15.0
5.0
9.0
11.0
6-10
14
10-25ฐ
Based on highest peak concentration including
existing ambient concentration (see Chapters 4-9).
U.S., Environmental Protection Agency. Position
Paper on Regulation of Atmospheric Sulfates, EPA
450/2-75-007.Research Triangle Park, N.C.: National
Environmental Research Center, 1975.
GFinklea, J.F., et al. Health Effects of Increasing
Sulfur Oxides Emissions, Draft~.Washington, D.C.:
U.S., Environmental Protection Agency, 1975. Cited
in U.S., Council on Environmental Quality. Environ-
mental Quality, Sixth Annual Report. Washington,
D.C.: Government Printing Office, 1975, p. 332.
134
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have a mean diameter of 1-3 microns. These particles can
penetrate deeply into the respiratory tract, and about 30 percent
of those penetrating will be deposited in the pulmonary alveoli
where they can have the greatest adverse effects.1 In addition,
these fine particulates are especially amenable to absorption
of toxic materials (particularly trace metals) which pose an
additional health hazard.
(3) N02
The major contributors of NO2 and other NOX in the scenarios
of this study are power plants. Peak 24-hour concentrations of
N02 in the vicinity of power plants in the six scenario locations
are given in Table 3-34. Peak concentrations (24-hour average)
projected in 1990 for urban areas are also included. It should
be noted that the federal primary standard is only on an annual
average basis and is set at 100 yg/m3. However, acute health
effects (lung irritations) are possible when N02 concentrations
are 1000 yg/m3 (projected to be exceeded only at the Escalante
power plant). Increased respiratory illness, however, may occur
at average 24-hour concentrations of 100-200 yg/m3. Concentra-
tions predicted to occur around urban areas exceed this limit in
1990 at Farmington and Gillette. Peak 24-hour N02 concentrations
in the vicinity of power plants are all above the 100 yg/m3 level
indicating the possibility of adverse health affects for popula-
tions living in the vicinity of large power plants.
(4) HC and Oxidants
As indicated in Table 3-35, the federal primary ambient air
standard for HC is exceeded as a result of emissions from Synthoil
liquefaction, TOSCO II oil shale retorting, and nautral gas pro-
duction facilities as well as from urban sources. Contributions
from power plant operations are minor. HC emissions from the
hypothesized conversion facilities exceed the primary standard
by seven times (natural gas) to 240 times (TOSCO II). The popula-
tion related HC emissions (mainly from automobiles) are projected
to exceed the primary standard after 1980 at all sites.
The extent to which these HC emissions represent a health
risk is very uncertain. Some of the HC emitted are carcinogenic,
such as PAH, and others can become carcinogenic in combination
with other compounds in the atmosphere (e.g., SO2 and particulates)
Since these HC emissions are primarily "fugitive" (from valves,
fittings, and seals) they are difficult to control.
for example, Southern Research Institute. A Survey of
Technical Information Related to Fine Particulate Control. Spring-
field, Va.:National Technical Information Service,1975.
135
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TABLE 3-34:
PEAK OXIDES OF NITROGEN CONCENTRATIONS FOR
SCENARIO LOCATIONS
(24-hour average measured in micrograms
per cubic meter)
LOCATION
Kaiparowits
Escalante
Farmington
Rifle (Grand Valley)
Gillette
Colstrip
Beulah
SOURCE
URBAN (1990)
88
NC
163
57
140
54
42
POWER PLANT3
130-220
760-1260
125-210
380-630
115-190
120-200
170-280
NC = not calculated
aRange indicates 0-40 percent removal of NOX by
scrubber.
In addition, HC contribute to the formation of oxidants that
can cause irritation to the eyes and throats of humans. Oxidants
are one of the reactants in the formation of photochemical smog
(a reaction of HC, NOx, and other compounds, activated by solar
energy).
(5) Radioactivity
Exposure to radiation from energy facilities considered in
this study may originate from coal, uranium, and oil shale fa-
cilities. Current information is available only for exposures
to radioactive materials from coal and uranium facilities.
Radioactivity in coal is highly variable. The major source
of radioactivity is Radium 226. After the coal is burned, it
becomes concentrated in the ash. If the ash is accumulated in
piles, it may contaminate surface water or be blown as dust.
In addition, other radioactive gaseous products are released
into the air. Inhalation of airborn radioactive substances is
suspected of causing lung cancer. However, based on the levels
136
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TABLE 3-35:
SELECTED AMBIENT 3-HOUR HYDROCARBON
CONCENTRATIONS WHICH RESULT FROM URBAN
EXPANSION AND ENERGY FACILITIES
(micrograms per cubic meter)
o
Urban Expansion
Kaiparowits
Farmington
Rifle
Gillette
Colstrip
Beulah
Conversion Facilities
Synthoil Liquefaction
Farmington
Gillette
Colstrip
TOSCO II Oil Shale
Rifle
Natural Gas Production
Gillette
Federal 3-hour Primary
HC Standard
PEAK CONCENTRATIONS
1980
NC
750
102
660
210
180
1990
481
871
571
780
270
210
2000
NC
900
NC
871
351
NC
21,500
25,100
17,200
38,540
1,087
160
NC = not calculated
HC = hydrocarbon
Urban expansion represents that expected in the
years indicated (except Beulah which is 1985,
1995) as a result of the energy development
assumed at six sites (see Chapters 4-9).
137
-------
of radioactivity emitted from coal-fired power plants and its
widespread distribution, the health risks due to radioactivity
are believed to be very small.
On the other hand, radioactivity emissions from uranium
mining and milling operations pose a more serious public health
problem. One study indicated that a significant health risk
from radioactivity exposure exists up to distances of one kilo-
meter from uranium tailing piles. In the vicinity of mines and
mills near Grants, New Mexico, radon levels are up to 10 times
the accepted standards.1 Uranium mills also release uremium
particulates into the atmosphere, and are the source of the major
uranium exposures to nearby populations.
(6) Trace Materials
The development of western energy will result in a wide range
of trace materials being emitted to the atmosphere and discharged
in effluents to holding ponds or receiving waters. Some of these
trace materials are much more toxic on a by-weight basis than are
criteria pollutants. When inhaled or injested, they may cause
problems that vary in seriousness from irritation to death.
The sources of potentially toxic trace substances include
mine wastes and the waste streams and emissions from combustion
and conversion facilities. While they may occur in small quanti-
ties in fuels, trace elements may become more concentrated in
waste streams. Additional concentration of these elements may
occur as they are assimilated into food webs in the environment.
Intake levels of some trace elements by certain animals (for
example, cadmium, mercury, and lead) already exceed tolerable
limits2 and increased trace element emissions and discharges can
significantly affect the likelihood of health problems.
B. Impact on Occupational Safety and Health
Many of the factors discussed above that affect public health
can be considered occupational health hazards as well. In addi-
tion, workers are exposed to job related hazards such as high
pressure vessels, complex machinery, and close contact with toxic
substances. These and related health and safety risks vary among
jobs and technologies. Two major categories of risk exist:
safety risks that may result in acute or immediate trauma that
produces death or injury; and longer term health risks from chronic
exposure to residuals within the boundaries of energy facilities.
Evaluation of this problem and health risk is being conducted
by the New Mexico Environmental Improvement Agency.
2As defined by World Health Organization/Food and Agriculture
Organization.
138
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(1) Safety
Safety risks occur in all phases of western energy develop-
ment. Existing,data (Table 3-38) indicate that the frequency of
death in underground coal mining is several times greater than
other phases of energy development, both on a per worker and on a
per Btu produced basis. However, existing data are difficult to
compare. Accident rates depend on type and location of the coal
mine and on definitions used to differentiate among different as-
pects of mining. Coal extraction, for example, frequently in-
cludes workers in coal cleaning facilities, a less hazardous en-
vironment. In addition, specific coal extraction technologies
differ; a number of western mines, for example, use longwall min-
ing, whereas more eastern mines use room and pillar mining. Thus,
comparable quantitative safety information on western energy occu-
pational risks are not available.
Also, occupational health statistics are gathered by dif-
ferent agencies of government for different fuel cycles, making
comparisons among technologies difficult. Thus, conclusions
based on statistical accident data should be made cautiously.
Although not shown in Table 3-36, transporting coal results
in more workdays lost (2,340 workdays lost per 1,000 MWe capacity
each year) than surface coal mining (499). The long transporta-
tion distances associated with western energy development make
this significant accident rate data even more critical.
The comparisons in Table 3-36 also indicate that nonfatal
accidents in uranium mills can be significant, as these mills are
apparently among the most injury prone environments on a per
worker basis. Data are not available for many other phases of
energy development, but in. situ oil shale development presumably
would be safer than "conventional" oil shale development as fewer
workers per Btu produced are exposed to the hazards of mining.
(2) Chronic Health Risks
The principal chronic occupational health risks considered
in this study were respiratory diseases and cancer. Data are
not available that link energy development technologies with
other health problems such as psychological disturbances, or
circulatory or endocrine disorders.
The best known and best documented occupational health risks
are respiratory disorders (black lung disease) in underground
coal miners and lung cancer (from radiation exposure) in under-
ground uranium miners. Black lung disease affects more than one-
third of underground coal miners and lung cancer was reported in
one out of 23 uranium miners from 1950-1973. Recent exposure
standards are expected to reduce both of these risks.
139
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TABLE 3-36:
SAFETY RISKS ASSOCIATED WITH ENERGY
FACILITIES EXPRESSED PER INDIVIDUAL
FACILITY
Coal
Surface mining (12 MMtpy)
Underground mining (12 MMtpy)
Gasification (250 MMscfd)
Liquefaction (30,000 bbl/day)
Power plant (3,000 MWe)
Oil (100,000 bbl/day)
Gas (250 MMcfd)
Oil Shale
Underground mine (66,000 tpd
crushed shale)
Surface retorting
Uranium
Mill (1,200 tpy)
FREQUENCY
PER WORKER
PER YEAR
DEATH
0.0011
0.0024
0.0008
0.0004
0.0017
0.0002
0.0003
0.0014
0.0004
0.0003
INJURY
0.034
0.090
0.002
0.007
0.007
0.021
0.024
0.062
0.045
0.104
MMtpy = million tons per year
MMscfd = million standard cubic feet per day
bbl/day = barrels per day
MWe = megawatt-electric
MMcfd = million cubic feet per day
tpd = tons per day
tpy = tons per year
140
-------
Although the raw materials for coal conversion and oil
generally contain very small quantities of carcinogenic sub-
stances, the processes of gasification and liquefaction result
in the formation of substances which have been demonstrated to
cause cancer. Although data for coal synthetic fuel technologies
are not available due to the newness of the technology, workers
in similar environments (e.g., oil refineries and coke plants)
have shown a higher incidence of cancer.
Exposure to free silica in underground oil shale mines may
cause silicosis (a lung disease), and like other synthetic fuel
technologies, retorting processes produce a variety of carcinogens.
3.6.3 Variations in Existing Conditions
Several existing conditions are important to the public and
occupational health impacts of energy development. For public
health, these variables include composition of resources, popula-
tion characteristics, terrain and atmospheric conditions, and
existing health care delivery systems. For occupational health,
variables primarily include the characteristics and composition
of the resource and safety practices and regulations.
A. Composition of Resources
Quantities of trace elements in coals vary greatly over the
eight-state region and even within a given locality. For example,
coal in the Gillette region contains mercury in amounts ranging
from 0.06 to 0.28 parts per million (ppm) (Chapter 7), and
Kaiparowits coal contains 0.05-1.2 ppm mercury. The high concen-
trations of mercury in Kaiparowits coal are of particular concern
since the contamination of some speqies of fish by mercury in
nearby Lake Powell already constitutes a health hazard. The lead
content of Gillette coals (1.5-40 ppm) is two to three times higher
than that of the Northern Great Plains lignites.
Other resource characteristics related to health include
seam thickness, major element composition (e.g., sulfur) and
amount of radioactivity. Sulfur content was discussed earlier
in air impacts. Seam thickness is related primarily to the extent
of occupational health risk per Btu produced. For example, thin-
ner seams in the Southwest (including underground mines in Utah
and Colorado) make occupation risk greater (on a Btu basis) than
mining thick seams in thp Fort Union Formation in Montana and
Wyoming.
The amount of radioactivity in a resource is important as
a public and occupational risk primarily for uranium development.
In this case, the higher the quality of the resource, the less
the risks of mining on a per Btu produced basis. Although the
level of radioactivity varies considerably for other resources
141
-------
(such as coals), as indicated previously the levels do not appear
to represent a significant health risk.
B. Population Characteristics
Populations especially susceptible to health problems include
the aged, infants, women of childbearing age, and people suffering
from pulmonary or cardiovascular deficiencies. For example,
children are more susceptible to respiratory ailments, caused
by high concentrations of S02 and NOX. Older people have a higher
risk of heart and lung disease aggravation due to sulfate aerosols
than younger members of the population. For example, generally
the Northern Great Plains has the largest percentage of the popu-
lation over 65 (over 10.6 percent in North and South Dakota).
New Mexico and Utah have the youngest populations with less than
7.5 percent of the population over 65.
C. Terrain and Atmospheric Conditions
Terrain, temperature, and humidity all can contribute to the
concentration of air pollutants. Rough terrain traps pollutants
during atmospheric inversions, and the effect of the S02/parti-
culate mix appears to be most pronounced when prolonged periods
of moderately cold temperatures (around 30ฐF) and high relative
humidities (above 70 percent) occur simultaneously. All these
conditions occur in the winter in western Colorado; thus, other
factors being equal this area would be more likely than other
areas to experience high levels of pollution concentration and
the consequent health problems as a result of energy resource
development.
D. Existing Health Care Delivery Systems
As indicated in Section 3.4, rural areas and communities im-
pacted by energy resource development frequently lack the infra-
structure to support health care facilities and attract physicians,
These problems will be especially acute for energy development in
remote areas and in areas that experience rapid population growth.
Particular problems with health care delivery exist in the rural
Southwest such as southern Utah, northern Arizona, and north-
western New Mexico. Some disease problems may be increased unless
community health services are improved.
E. Safety Practices and Regulations
Worker practices and the design and operation of the work
environment are a critical factor affecting both acute and chronic
worker disabilities. Although specific comparative data are not
available, the practices of different companies and the safety
standards enforcement programs of states and the federal govern-
ment are related to variations in accident occurrences. Accidents
in underground coal mines have been significantly reduced with
142
-------
the passage of coal mine safety acts, including the Mine Health
and Safety Act of 1969. Practices and regulations on working con-
ditions in coal mines have also apparently affected the incidence
of black lung disease. Changes in accepted exposure levels to
radon gas are likely to reduce the incidence of lung cancer in
underground uranium miners.
3.6.4 Summary of Technological and Locational Factors
Technological and locational factors that can result in health
problems are summarized in Table 3-37. Respiratory disease is a
threat as a result of the SOa, particulate, and NOX emissions from
conversion facilities, especially electric power plants. Sulfate
concentrations approach those causing disease at a three to five
percent S02-to-sulfates conversion rate and can be expected to
increase the incidence of disease, especially in the aged, infants,
and persons with pulmonary and cardiovascular deficiencies.
Locating labor-intensive conversion facilities in rural areas,
such as the Southwest, will result in population increases that
exceed the capacity of health care delivery systems. This can
have a variety of adverse health implications unrelated to the
emissions from energy facilities.
Emissions of trace materials from various energy facilities
could have long-term, chronic effects although the seriousness
is highly uncertain. For example, burning coal with a high mer-
cury content in the vicinity of aquatic ecosystems with sport
fish may increase the mercury content of fish. Mercury concentra-
tions in some biota in Lake Powell in the vicinity of Kaiparowits,
Utah, currently exceed Food and Drug Administration standards.
The incremental addition from the combustion of coal in the area
would aggravate this problem.
Occupational health hazards in western underground coal
mines, while similar in all underground coal mines regardless
of location, is a significant occupational hazard. Mortality as
a result of accidents and respiratory disorders as a result of
particulate inhalation can constitute significant health problems.
Exposure to radiation in underground uranium mines is also a
serious problem. Recent improvements in the regulations and
standards affecting these working environments have substantially
reduced, but not eliminated, the risks.
143
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3 . 7 TRANSPORTATION
HIGHLIGHTS
CRITICAL FACTORS
Thne.e. te.chno logical faactonA can afafae.ct tnanApontati.on i.m-
pactA : ca.p-ita.-i i.nte.nAity, wate.n ne.qm-ine.me.ntA , and the.
unique. Ae.t ofa ne.Ai.du.atA chanacte.ni.Atic ofa e.ach mode..
Two to cati.o nat faactonA can afafae.ct the.Ae. imp act A '. the.
location and capac-ity ofa e.KiAting tnanApontat-ion AyAte.mA,
and the. avai.ฃabie, lasige. i.nve.Atme.nt* .
A k-iak&n pfiopont-ion oฃ the. cott* oฃ a fiaLL t>yt>te.m
o p &?iattQ n co 4 1& .
(VC) ttiant>m4.t>&j,on -i-& ne.tatJ.ve.ty mon.e. e.conom>L
cat than atte.nnati.nQ cu.nne.nt (AC) ฃon tanae. votume.t> and
tong di.& tance.* ; AC -t.4 mone. e.conom-icat faon &matte.n volume.*
and Ahonte.n di&tance.^ and whe.n the. pow&n Jit> nou.te.d to
t>e.ve.nat de.bt-inat4.ont>,
FLEXIBILITY
A ane. mone, fate.Ki.bte. than Atunny -!>yi>te.mt> Jin te.nmA
ofa {tuctuat-ing de.mand& , de.t-ive.ny to nume.nou de.Ati.nati.oni>,
and tnanApont ofa commodi.ti.iA othun than coat.
WATER REQUIREMENTS
Appnox.i.mate.iy 740 acne.- fit ofa wate.n ane. ne.qa.i.ne.d faon e.ach
1 mi.tti.on tonA ofa coat tnanAponte.d by Atunny pi.pe.ti.ne..
By the. ye.an 2000, Ace.nani.o Aiunny pi.pe.ti,ne.A oni.ginati.ng in
the. Uonthe.nn Gne.at Piai.nA coutd ne.qmi.ne, mone. than 300
thouAand acne.~itfyn on 23 pe.nce.nt ofa the. u)ate.n u.Ae.d faon
e.ne.ngy de.ve.topme.nt in that ane.a.
EXISTING CAPACITY
tKi.Ati.ng gaA ptpe.ti.ne.A in the. Foul Conne.nA ane.a ane. e.Kpe.cte.d
to be. ade.qu.ate. to tnanApont both natunai and Aynthe,ti.c gaA
thnough the. yean 2000; addi.ti.onal oi.t pi.pe.ii.ne. capacity
be. ne.e.de.d even -in the. Low Ve.mand Ace.nanio.
145
-------
-cn the. Nox.tke.in Gnat ?iaJLn& an.e. e.K
pe.c.te.d to be. ade.qu.ate. to tx.an&pox.t both c.x.ade. and Aync.tiu.de.
tkx.ou.gk the. ye.ax. 2000} addtttonat gaA plpe.l4.ne.-t> wJLLL be.
ne.e.de.d Ln the. an.ua.
be. fie.qu.4.nd ^oh. atmo&t
bui.it tn tke. fie.Q4.on.
3.7.1 Introduction
This study verifies what has been found in a number of pre-
vious studies: that large-scale resource development in the west-
ern U.S. will require substantial new investments in transportation
facilities. As discussed in Chapter 11, capital costs for trans-
portation may involve more than $30 billion by the end of the cen-
tury, equivalent to more than 25 percent of the total cost of the
energy facilities.1 In addition to the impacts this investment
will have on the national economy, transportation facilities can
produce locally significant environmental impacts along their
rights-of-way. These impacts include noise, accidents, visual
intrusion, and barriers to human and animal mobility. Factors
that determine the extent of such impacts are summarized below.
3.7.2 Variations Among Technologies
Choices among transportation modes are limited by the choices
among energy. conversion technologies. The first choice to be made
is whether to convert the resource at or near the mine site (the
"mine-mouth" option) or ship it to the demand centers in raw form
(the "strip and ship" option). If the mine-mouth option is chosen,
several final fuel forms are available (liquids, gases, and elec-
tricity), each with specific transportation modes available. If
strip and ship is chosen, the two primary options are rail and
slurry pipeline. The present discussion is organized around the
choice of mode, since each has certain characteristic impacts.2
1 See also the policy analysis of energy transportation, in
White, Irvin L. , et al. Energy From the West; Policy Analysis
Report. Washington, D.C. : U.S., Environmental Protection Agency,
forthcoming, Chapter 11.
2As part of this study, the Center for Advanced Computation
at the University of Illinois at Urbana-Champaign undertook a cost
comparison study of alternate transportation options under a sub-
contract with the Univer'sity of Oklahoma. See Rieber, Michael,
and Shao Lee Soo. "Route Specific Cost Comparisons: Unit Trains,
Coal Slurry Pipelines and Extra High Voltage Transmissions," Appen-
dix B in White, Irvin L. , et al. Energy From the West: A Progress
Report of a Technology Assessment of Western Energy Resource Devel-
opment . Washington, D.C. : U.S., Environmental Protection Agency,
1977.
146
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A. Export of Solids: Rail versus Slurry
We have examined two types of solid fuels: coal and uranium.1
Since substantially larger amounts of coal production are antic-
ipated (in terms of weight), attention has been focused on that
resource. Of the two leading prospects for coal transport, rail
and slurry pipeline, it is generally believed that slurry pipe-
lines are more economical when transporting large volumes over
long distances.
More than 90 percent of the total cost of a slurry system is
capital-related, while operating costs form a higher proportion
for a rail system.2 This large capital-operating cost imbalance
means that slurry pipelines are economical alternatives to rail
systems only when their capacities can be fully used. Conse-
quently, slurry pipeline operations need firm, long-term contracts
and throughput rates close to design specifications to operate
economically and efficiently.
The water required by slurry lines (740 acre-ft per million
tons of coal) will make additional demands on already short sup-
plies in some regions of the West. Although closed-loop systems
(where the water is returned in another pipeline) and the use of
petroleum products instead of water have been discussed,3 neither
is considered an economically viable alternative at present.
Slurry pipelines avoid a number of the environmental impacts of
rail systems. Railroads are noisy, disrupt vehicular traffic
in urban areas, and create a safety hazard at grade crossings.
Rail systems are more flexible than slurry pipelines in
their ability to meet fluctuating demand levels and in their
potential to deliver to a variety of geographic locations. More-
over, rail lines can carry other kinds of freight when not used
to capacity by unit coal trains.
Although oil shale may be mined as a solid, export of the
shale before extracting the kerogen is not considered practical
because of the large volume of shale that would have to be trans-
ported.
2The comparative economics of the two systems depend, to a
great extent, on the cost of restoring existing rail lines. This
cost is discussed later in this section.
3The petroleum product would be burned, along with the coal,
in this alternative. To the best of our knowledge, no one has
seriously proposed a closed-loop system.
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At the railroad usage levels anticipated in the regional
scenario,1 noise impacts will be substantial for many people.
More than one million people live within one mile of one Montana-
to-Chicago route, a range within which noise produced by a single
unit train can be annoying. In the case of traffic disruption,
the rail usage anticipated could amount to 43 round trips per day
to the Chicago area. If just half of this traffic (i.e., 22
round trips per day) is sent along a single rail line at 20 miles
per hour (mph), the chance of a grade crossing being blocked at
any given time will be approximately one in ten. Towns with over-
or underpasses, of course, will not suffer this impact (nor the
noise of train horns).
Environmental impacts of slurry pipelines are different in
kind and are almost entirely related to their use of water. The
water must be treated at the end of the line before being reused
or discharged. One of the products of this treatment, which must
be disposed of, is a sludge of coal fines containing as much as
five percent of the original coal. Also, spills can occur as a
result of failures in pipes or pumping station equipment. With
the exception of pumping stations, repairing such leaks will
normally require flushing a substantial portion of the line and
thus discharging a large amount of the slurry into a holding
pond. This coal slurry cannot be reinjected into the line.
Physical input requirements of the two systems will be roughly
comparable on a region-wide basis. For example, railroads would
use 9.5 million tons of steel by the year 2000 under the Nominal
Demand scenario, versus 7.8 million tons for slurry pipelines.
Each system requires about 380 tons of steel per mile for fixed
structures (assuming 25 million tons/year capacity), but rail-
roads will also need rolling stock. On the other hand, many of
the railroad lines are already in place and will simply require
some upgrading.
B. Export of Electricity: AC versus DC
Electrical transmission avoids many of the problems mentioned
above and, in some ways, constitutes even less of a barrier to
animals than do above-ground pipelines. Like slurry pipelines,
electrical transmission costs are heavily weighted toward initial
capital investments, and the economics of such lines are predicted
on high utilization of capacity. The concept of mine-mouth elec-
trical generation for export implies that there are almost never
any existing transmission facilities.
than one hundred 100-car unit trains leaving the Powder
River Basin daily by the year 2000.
148
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Because of their height, transmission lines have .more or an
aesthetic impact than do other transport modes. Additionally,
there is the possibility of impacts from ozone generated by high
voltage transmission.
The two major technological alternatives available for elec-
trical transmission are AC and DC. AC has relative advantages
when smaller quantities of power are sent over shorter distances
(as compared to DC applications). AC also allows more flexibility
in terms of delivering power to many destinations simultaneously.
These differences arise mainly from the fact that DC terminal
installations are more complex and expensive. In other respects,
DC seems to have the advantage: they can carry significantly
higher line loads, have lower transmission losses, result in less
noise, and require shorter supporting towers. Still, the voltages
being contemplated for bulk energy transmission (800 kilovolts)
produce unique phenomena (e.g., some electrostatic effects) with
which little operating experience has yet been gained.
C. Gas and Liquid Pipelines
Pipelines will be used when petroleum and natural gas are
exported from the region in raw form, or when coal is liquefied
or gasified within the region. Oil and gas pipelines create few
adverse impacts although high-pressure gas pipelines are a signi-
ficant safety hazard.
3.7.3 Variations Among Existing Conditions
Certain locational characteristics partly determine the im-
pacts of energy transportation systems. The key variations are
the capacity of existing transport links in close proximity to
developable energy deposits, and, in the case of slurry pipelines,
the extent of available water resources.
A. Existing Capacity of Transport Links
Obviously, extraction (and, to some extent, processing) must
be done wherever the minerals are found. More often than not in
the West, the deposits are located far from established popula-
tion centers and their associated transportation networks. The
following discussion summarizes present capacity by area for rail
systems, gas and oil pipelines, and electrical transmission lines.
At present there is only one major slurry pipeline in the region,
the Black Mesa line in Arizona and Nevada.
(1) Rail Systems
In the eight-state study area, rail facilities are especially
sparse around the Four Corners area. In that region, the distance
from coal deposits to the nearest rail trunk line may often exceed
150 road miles. Due to denser populations and greater agricultural
149
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production, rail links in the Great Plains have been developed
more extensively.
The capacity and quality of rail lines presents the most
problematic issue concerning the study area's transportation
system. Comprehensive, systematic data are not available on how
much coal could be carried over the current rail lines or how
capacity varies by region. However, much of the nation's rail
lines have not been maintained to normal standards, and unit
trains will require better-than-standard track for high-speed
operation. One estimate of reconstruction costs is $3.3 billion
(1973 dollars).l
However, even if all existing lines are upgraded for unit
trains, the volumes of coal in the regional scenario will neces-
sitate the building of new main lines. There is some disagree-
ment as to when existing rail line saturation would occur, but
assuming that 70 million tons of coal per year could be handled
on one set of double track, some 6,600 miles of additional track
would be required by 2000, at a cost of $2.0 billion. However,
any excess carrying capacity of new and rebuilt rail lines would
be available for other commodity shipments, which is an advantage
not shared by slurry pipelines, the other coal transport mode
considered here.
(2) Transmission Lines
Generally speaking, each mine-mouth power plant will need a
new transmission line to connect it with the distribution net-
work at the load center. Substantial transmission capacity links
the Four Corners area, Arizona, and Los Angeles; other routes
are less developed.2 The Nominal Demand scenario would call for
13,000 new miles of electric lines, each capable of carrying 2,200
MWe, in the region by the year 2000.
(3) Gas and Oil Pipelines
Existing gas pipeline capacity from the Four Corners states
is adequate through the year 2000 for the synthetic gas and natural
gas developments projected in both the Nominal Demand and Low
^.S., Federal Energy Administration. Project Independence
Blueprint, Final Task Force Report: Analysis of Requirements and
Constraints on the Transport of Energy Materials, Vol. I. Wash-
ington ,B.C.:Government Printing Office,1974.
2Energy Resources Co. Preliminary Assessment of the Economic
and Environmental Impact of Alternative Demand/Supply Scenarios
for Electricity in the Southwest.Draft Final Report, for U.S.
Environmental Protection Agency. Cambridge, Mass.: Energy Re-
sources Co., 1976.
150
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Demand scenarios. Two major interstate gas pipeline companies have
pipelines that currently traverse the area; these have a total
yearly capacity of 2,341 billion cubic feet (bcf), exclusive of
added compression and looping which could be used to increase the
capacity. Except for short pipelines to tie in with these exist-
ing trunk lines, no new pipelines should be required. In the
Northern Great Plains, gas pipeline capacity will probably not
be adequate. A Nominal Demand scenario projects that 201 bcf
Of gas in 1990 and 3,429 bcf in 2000 will be produced in the
Powder River Coal Region. One major gas pipeline with a capacity
of 56 bcf per year currently traverses the Powder River Region.
Existing oil pipeline capacity is adequate in the Northern
Great Plains and inadequate in the Four Corners states. Assuming
the Nominal Case level of development, 142 thousand bbl/day is
projected to be produced in the year 2000 in the Powder River
area of the Northern Great Plains. Existing capacity there is
620 thousand bbl/day. In the Four Corners area, 3.9 million bbl/
day should be produced by 2000, and existing capacity without
looping is 260 thousand bbl/day.
B. Water Availability for Slurry Pipelines
The viability of a slurry pipeline depends on the availabil-
ity of water at the shipping point. In general, more water is
available from the UMRB than from the UCRB. However, the amount
of water available from specific areas depends on technical,
economic, and legal factors. For example, slurry pipelines may
be able to utilize groundwater sources which, because of cost or
low water quality, other water users would not consider. Water
availability also depends on state law and interstate compacts
which restrict the diversion of water outside a river basin.
Ironically, these may prevent slurry pipeline development while
allowing generation of electricity for export from the region,
even though electric generation consumes more water per unit of
coal input than do slurry pipelines.
3.8 AESTHETICS AND NOISE
HIGHLIGHTS
AESTHETICS
The. vno&t c.n.^t-ic.at ae.Atke.t-ic. tmpac.tt> ^tiom e.ne.x.gy de.ve.top-
me,nt ate. l^ke-iy to occui ne.au national paikA, &otie.AtA ,
monu.me.nt-!>, -i-botate-d afie.a&, and ane.at> Jin a natural. Atate..
The.t>e. aie.at> a.n.0, highly valu&d -in the. We.At and ae.Athe.t'ic
tmpac.t& can qu^ckiy de,tiac.t 6*.om the.i.x. be.au.ty on value..
151
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Stiip mi.ne.A , conve.iAion plantA , tsianAmi.AA4.on l4,ne.A , and
tiainA wilt piodu.cz viAual intiu.A4.onA , opaque plame.A ,
and ie.ducti.onA in
' Stiip mining o ฃte.n SLe.Au.it4 i,n the. mo At Ae.ve.ie. Akoit-te.im
ae.Atke.t-ic. i.mpactA on land; thuA , the. Auc.ce.AA o jj tie.clamatJ.on
piacti.ce.A W4.it be. cn.-it4.cat in de.te.im-in4.ng the, magn4.tu.de,
o ฃ ae.Athe.ti.c impactA .
* NOISE
' Hoi.Ae. -impacts wi.ll be. Ai.gnifi4.cant within one.-hal& mile, o&
la-it line.A , whe.ie. the. noiAe. le.ve.1 M4.lt be. above. 55 de.cibe.tA.
Ve.pe.ndi.ng on the. loate., the.Ae. -impactA could abject a taige,
nu.mbe.1 ofi pe.ople..
3.8.1 Introduction
Aesthetic impacts from energy development include alterations
in the land, air, water, and biota, and increases in noise levels.
Personal values will be important in determining how critical
these impacts will be. Aesthetic impacts from energy development
will be discussed as they vary by technology and then as they vary
by existing conditions.
3.8.2 Variations by Technologies
A. Aesthetics
In general, western residents highly value the natural
beauty and, in many areas, the scenically spectacular nature of
their region. Thus, many westerners perceive strip mines, energy
conversion facilities, stacks, plumes, transmission lines, etc.,
more negatively than do newcomers who are employed by the energy
development activities. While few data exist to evaluate system-
atically the aesthetic impacts of different energy development
technologies, several generalizations about potential impacts
can be made. For example, the most serious land-related impacts
result from surface strip mining which can alter the vegetation,
color, and topographic character of the land. Thus, how much
land is disturbed and how successful reclamation is will be
critical from an aesthetic viewpoint.
Aesthetic impacts on air are likely no matter where conver-
sion facilities are located in the West since so much of the West
enjoys long and clear visibility. Emissions from energy facili-
ties, particularly power plants, will reduce visibility by an
average of eight percent. During worst-case weather conditions,
visibility can be reduced by as much as 80 percent. Air pollu-
tants can also alter the natural coloration of the sky in some
areas, thus affecting the contrast of natural features and
152
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formations against the skyline.1 Air pollutant emissions (e.g.,
hydrogen sulfide, SO2, and various HC) can also produce unpleas-
ant odors close to facilities.
The appearance and rate of movement of water are also valued
aesthetic qualities. Direct water consumption for energy develop-
ment will decrease flow rates, increase turbidity, expose pre-
viously submerged areas, and cause discoloration of shorelines
due to algae growth. In addition, increases in the local popula-
tion will probably result in greater quantities of materials being
discarded in streams, a very apparent aesthetic impact.
The density of human-made objects and other evidence of
human presence is aesthetically objectionable to some people.
Over 100 new large-scale energy conversion facilities are pro-
jected for the West in the Low Demand case by the year 2000.
Skyline alteration (e.g., smokestacks and transmission lines)
from these facilities will be another impact because of the long
distance from which a structure on the skyline can be observed.
The color, design and location of a facility may also affect its
aesthetic appeal.
B. Noise
Noise is often considered an aesthetic impact; however, it
is also becoming recognized as a pollutant which may affect
public health. Energy development in each of the scenarios will
increase levels of traffic (highway and rail) and will introduce
new stationary sources of noise as well (mining, and construction
and operation of facilities). The amount of noise generated will
depend on the particular types of equipment used, and on the pres-
ence or absence of physical noise barriers.
Among stationary sources, surface strip mining will have
less impact on the noise levels than power plant construction
and operation. This is in part due to the tall overburden piles
which reduce some of the mining noise. Haulers will be the
principal noise source of the strip mines, and will cause annoy-
ance levels up to one-half mile from the mine. The construction
and operation of energy conversion facilities will cause annoy-
ance levels up to one mile from the plant.
Among transportation sources, trucks and unit train engines
produce noise levels which result in an annoyance level within
^.S., Department of the Interior, Bureau of Land Management.
Final Environmental Statement; Proposed Kaiparowits Project,
6 vols. Salt Lake City, Utah: Bureau of Land Management, 1976,
Chapters III-VII.
153
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one-half mile of roads and rai$;ioad lines. Moving sources/ such
as coal trains, will generally produce more extensive .impacts
than, stationary sources because they affect more people. In addi-
tion, there are few tall buildings along railways to block the
noise.
3.8.3 Variations by Existing Conditions
A. Aesthetics
Aesthetic land impacts will vary according to the existing
topographic, climatic, and biological conditions at the facility
site. Although federal law1 requires reclamation of surface-
mined land to the original vegetation and contour, the success
of reclamation will depend critically on rainfall and how much
water is available for irrigation. Thus, the potential success
of reclamation is very uncertain in many western areas, but par-
ticularly in the arid Southwest. If reclamation does succeed,
the aesthetic quality of an area can be improved if distinctive
new relief characteristics are added or, in some cases, if "non-
native" vegetation would be allowed.
Air-related aesthetic impacts will be aggravated by the rug-
ged terrain of some areas. This is especially true in western
Colorado and southern Utah. Loss of visibility will also be per-
ceived most readily in areas of Utah and Arizona where long dis-
tance visibility has come to be expected by residents and tour-
ist.
Where new access roads make wilderness areas more accessible,
increases in ORV use could destroy plant life and encourage ille-
gal activities such as poaching or indiscriminant killing of non-
game animals. This is a potential problem at all energy develop-
ment sites in the West, but negative impacts are most likely
around Beulah, North Dakota, where the geologic fragility and
high recreational potential of the badlands to the west make them
extremely vulnerable to overuse; Escalante, Utah, which is sur-
rounded by national parks, forests, and recreation areas, all
within easy driving distances from hypothesized energy facilities;
and Rifle, Colorado, which is close to several national parks
and forests and where certain heavily used areas are already be-
ginning to show signs of deterioration.2
The aesthetic visual impact of the facilities may be reduced
if they are designed to conform to the surroundings. This is
Surface Mining Control and Reclamation Act of 1977, Pub. L.
95-87, 91 Stat. 445.
2Todd, J. "We're Losing the Wild in the Wilderness." Colo-
rado Outdoors, Vol. 25 (March/April 1976), pp. 10-11.
154
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expected to be most difficult in the Northern Great Plains due
to flat topography.
B. Noise
Noise impacts will depend primarily on the distances between
sources and populations. Thus, people living closest to energy
facilities will experience the highest average sound levels.
As noted, railroads will affect the greatest numbers of people.
For example, more than one million people live within one mile
of a railway main line from Montana to Chicago. The distribution
of mining and facility noise impacts will depend almost entirely
on the distribution of energy development in the West. In addi-
tion, topography and foliage will modify noise impacts to a degree,
For example, valleys tend to entrap noises generated within them,
and dense brush and forests absorb sound waves quickly.
3.8.4 Summary of Technological and Locational Factors
The blue skies and long-range visibility of the western
states are highly valued, both for their intrinsic appeal and
for their enhancement of the scenic beauty of parks, monuments,
and projected sites in the region. Many portions of the study
area have average visibilities of 65-70 miles, and some places
in southern Utah and northern Arizona allow clear visibility
up to 100 miles. Thus, any reduction in long-range visibility
at particular sites will probably be considered a negative
aesthetic impact by both residents and tourists.
In spite of revegetation requirements, the changed appear-
ance of mining areas may be a negative impact to some people
simply because it is different from what existed "naturally."
Problems in reclaiming mined land may reduce the variety of
vegetation in some more arid areas of the West, thus contributing
to the disappearance of certain wildlife species. Similarly,
the dewatering of aquifers and the infiltration of aquifers,
springs, and streams by waste pond leachates could harm aquatic
species and wildlife that use these water sources. These poten-
tial ecological problems could degrade the wildlife and vegetation
in national parks and pristine places. Thus, reduction or loss
of wildlife and vegetation in some areas will have negative
aesthetic impacts on area visitors.
As noted previously, energy development-related noise in-
creases from both stationary and moving sources cause aesthetic
impacts in nearby communities. To some long-time residents, both
the intermittent and continuous sounds will be displeasing,
annoying, and possibly disturbing to typical patterns of behavior
and sleep. In an area such as Rifle, Colorado, where a larger
than normal fraction of the population is of retirement age,
the noise created by an energy development could be especially
155
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annoying. The fact that retirement-age people have moved into
this area seems to indicate a desire to get away from the dis-
turbing effects of higher-paced life elsewhere and spend their
retirement years in relatively calm, quiet surroundings.
3.9 SUMMARY
This section summarizes differences in impacts that can be
expected from different combinations of technological and loca-
tional factors and the general trade-offs between exportation
and on-site conversion of coal resources.
3.9.1 Technological and Locational Factors That Cause Impacts
Table 3-38 lists the most significant impact-causing factors
identified in Sections 3.2-3.8. Among technological factors,
labor intensity contributes to several impacts: air quality/-
water use; water quality; the ability of communities to provide
facilities and services; the extent of political disruptions
caused by changes in the relative number of newcomers; and the
extent to which plant communities and wildlife habitat will be
disrupted. The severity of environmental impacts will depend
largely on the choice of energy technology and the extent to
which environmental control technologies are employed. If air
emission controls, water-saving cooling options, and wastewater
control technologies are employed, the adverse impacts on ter-
restrial and aquatic ecosystems, human health, and aesthetic
characteristics (such as visibility) can be reduced but not
eliminated.
Community size is among the most important locational factors,
contributing to: water quality problems in small communities
which often do not have adequate sewage treatment plants nor the
resources for expanding them; inadequate services since the in-
stitutional and financial capacity to expand services is often
lacking in small communities; the extent of political disruptions
caused by changes in the newcomer-to-oldtimer ratio; and health
care capacity.
Coal characteristics, which vary widely in the eight-state
area, affect: air quality (as sulfur and ash content vary);
water use (as moisture and seam thickness vary); water quality
(as effluent streams vary in composition in accordance to varia-
tions in coal composition); the extent to which plant communities
and wildlife habitat are degraded and eliminated (as seam thickness
and thus land use vary); and health impacts (as the trace ele-
ment composition, sulfur, and ash content vary).
3.9.2 Export versus On-site Conversion
Two major locational choices are available as regards coal
conversion facilities: ship the coal out of the region to be
156
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converted elsewhere, or mine and convert, the coal to another fuel
form on-site, in which case the choice is among the types of con-
version technologies. This section briefly summarizes some of
the consequences of those choices and how locational factors can
affect them.
A. Coal Export
Mining and exporting western coal will substantially reduce
the negative air quality, water, ecological, social, political,
and health impacts for the region. Air emissions from mining
are primarily blowing dust and can be negligible if proper dust
suppression techniques are used; and emissions from urban sources
associated with mining are much less (because population increases
are less) than is the case with conversion facilities. Even when
intensive irrigation is assumed, water use for reclamation is one-
tenth that required by a conversion facility. In either the ex-
port or mine-mouth conversion case, degradation and elimination
of terrestrial plant and wildlife communities will result from
surface mining, but population-induced ecological impeicts associa-
ted with labor intensive coal conversion facilities will be
avoided if resources are exported. Because mining has low labor
requirements, fewer social and political impacts, resulting from
inadequate services and facilities and the influx of newcomers,
are expected. Since air and water quality remain virtually un-
changed, public health hazards are minimal. Occupational risks
with mining remain in both cases. This is not to say that mining
does not have negative impacts. For example, aquifer systems
can be altered and underground miners will be exposed to occupa-
tional health hazards. The negative impacts from coal transporta-
tion (primarily safety risks, noise, and community disruption
from unit trains and water consumption of slurry pipelines) will
be magnified with the export option.
Mining for export may also minimize many of the positive
impacts. Tax revenues, employment potential, and income benefits
associated with capital- and labor-intensive conversion facilities
are exported along with the coal.
B. Mine-Mouth Conversion
Facilities for producing synthetic fuels from coal have many
impact-causing factors in common, and these factors are substan-
tially different from those associated with electric power plants.
Synthetic fuels facilities result in fewer air quality problems
than electric power generation because emissions are considerably
less (HC emissions from coal liquefaction and oil shale retorting
facilities are an exception). The hypothetical coal synthetic
fuels facilities at our sites do not cause federal ambient air
standards (except for HC) or Class II PSD increments to be ex-
ceeded. Power plants in our scenarios regularly violate Class II
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increments even when high levels of pollutant removal by air
emission control technologies are assumed. If control technologies
were lower (at levels which would meet NSPS), then ambient stan-
dards would be violated.
Similarly, water use by electric power plants is consider-
ably higher than that of synthetic fuels facilities (unless power
plants use intermediate or minimum wet cooling, in which case
they are similar). A typical size Lurgi gasification facility
requires less water than other typical-size conversion technol-
ogies. In the central Rocky Mountains and Southwest, water con-
sumption may be the determining variable in choosing a conversion
technology. Since air quality is also more of a problem in these
areas (due to the terrain, dispersion potential, and, in the case
of Colorado, state ambient air quality standards), synthetic fuels
facilities may be a more desirable choice for- the Southwest and
central Rocky Mountains than power plants. If electric power
plants are sited in these two areas, air emission control tech-
nologies may require very high removal efficiencies and water
saving cooling options may have to be employed.
Although all conversion technologies are more labor inten-
sive than mining, typical size synthetic fuels facilities are
more labor intensive than typical size electric power plants.
This means that the social, economic, political, and ecological
impacts of electric power plants will be somewhat less than those
of synthetic fuels facilities. Electric power plants also offer
larger increases in the tax base than do synthetic fuel facilities.
C. The Effect of Locational Considerations
The effects of conditions at a specific site cut across all
the generalizations stated above either to worsen or mitigate
impacts. Those conditions that affect air quality, water, and
ecological impacts generally vary according to three subareas
in the eight-state study area: Northern Great Plains, Rocky
Mountains, and Southwest. However, social, economic, and politi-
cal impacts are also sensitive to other factors. As mentioned
above, community size is a critical locational variable,"affecting
the capacity of the public and private sectors to provide services,
the nature of the local labor force, and the extent to which old-
timers are likely to be displaced by newcomers in the political
power structure. State impact mitigation programs also determine
a community's ability to respond to rapidly escalated demands for
services and facilities, and such programs vary from state to
state.
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