U.S. Environmental Protection Agency Industrial Environmental Research FPA-600/7-76-
Office of Research and Development Laboratory
Cincinnati,Ohio 45268 December 1976
PRODUCTION AND PROCESSING
OF U.S. TAR SANDS:
An Environmental
Assessment
Interagency
Energy-Environment
Research and Development
Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S.
Environmental Protection Agency, have been grouped into seven series.
These seven broad categories were established to facilitate further
development and application of environmental technology. Elimination
of traditional grouping was consciously planned to foster technology
transfer and a maximum interface in related fields. The seven series
are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from
the effort funded under the 17-agency Federal Energy/Environment
Research and Development Program. These studies relate to EPA's
mission to protect the public health and welfare from adverse effects
of pollutants associated with energy systems. The goal of the Program
is to assure the rapid development of domestic energy supplies in an
envirbnmentally—compatible manner by providing the necessary
environmental data and control technology. Investigations include
analyses of the transport of energy-related pollutants and their health
and ecological effects; assessments of, and development of, control
technologies for energy systems; and integrated assessments of a wide
range of energy-related environmental issues.
This document is available to the public through the National Technical
Information Service, Springfield, Virginia 22161.
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EPA-600/7-76-035
December 1976
PRODUCTION AND PROCESSING OF U.S. TAR SANDS
AN ENVIRONMENTAL ASSESSMENT
by
N. A. Frazier, D. W. Hissong,
W. E. Ballantyne, and E. J. Mazey
BATTELLE
Columbus Laboratories
Columbus, Ohio 43201
Contract Number 68-02-1323
Project Officer
Eugene Harris
Resource Extraction and Handling Division
Industrial Environmental Research Laboratory
Cincinnati, Ohio 45268
INDUSTRIAL ENVIRONMENTAL RESEARCH LABORATORY
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
CINCINNATI, OHIO 45268
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DISCLAIMER
This report has been reviewed by the Industrial Environmental Research
Laboratory, U.S. Environmental Protection Agency, and approved for publi-
cation. 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.
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FOREWORD
When energy and material resources are extracted, processed, converted,
and used, the related pollutional impacts on our environment and even on
our health often require that new and increasingly more efficient pollution
control methods be used. The Industrial Environmental Research Laboratory -
Cincinnati (lERL-Ci) assists in developing and demonstrating new and
improved methodologies that will meet these needs both efficiently and
economically.
Factors traceable to the increasing shortfall in U. S. production of
natural crude have rekindled interests in U. S. tar sands as a source of
synthetic fuel. If U. S. tar sands do become a viable resource base for
syncrude, then their commercial development would create activities and
sources with potential for environmental impacts. Reported here are the
results of a preliminary study to assess the potential primary environ-
mental impacts of production and processing of U. S. tar sands bitumen.
This research will be especially applicable to research agencies and the
various control agencies associated with energy production. For further
information contact the Extraction Technology Branch of the Resource
Extraction and Handling Division.
David G. Stephan
Director
Industrial Environmental Research Laboratory
Cincinnati
iii
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ABSTRACT
Factors traceable to the Increasing shortfall in U.S. production of
natural crude have rekindled interests in U.S. tar sands as a source of
synthetic fuel. If U.S. tar sands do become a viable resource base for
syncrude, then their commercial development would create activities and
sources with potential for environmental impacts. Reported here are the
results of a preliminary study to assess the potential primary environmental
impacts of production and processing of U.S. tar sands bitumen.
With the possible exception attributable to chemical differences
between tar sand bitumen and coal, potential environmental impacts of
producing tar sands by mining methods would be similar in type to those of
mining coal by the same method and in the same area as the tar sand deposit.
Processes for extracting bitumen from the mined tar sand would generate
solid waste in the form of spent sand. Constituents and quantities of
emissions to air and water are process dependent but existing control
technology and good environmental practices are technically applicable.
A viable in situ production technology for producing tar sand reservoirs
has not yet been demonstrated. On the basis of methods tested to date,
potential environmental impacts of producing tar sands by in situ methods
would be very similar to those of conventional oil field production.
Facilities used to upgrade tar sand oil would pose potential primary
impacts of the same type as coking and hydrotreating processes in an oil
refinery. Whether or not new upgrading facilities would have to be con-
structed or existing facilities might be used would depend on location and
size of tar sand deposit.
Environmentally, in situ production of tar sands would be preferred.
From the viewpoint of resource utilization, production by surface mining
methods, where economically and technically possible, would be preferred.
Technical and economic factors will determine if in situ methods, or
possibly underground methods, are an alternative to surface mining in
environmentally sensitive areas.
iv
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CONTENTS
FOREWORD ill
ABSTRACT : . iv
FIGURES vi
TABLES vii
I. Introduction 1
II. Characteristics of U.S. Tar Sands 3
Geographic Distribution of U.S. Tar Sands 3
Properties of U.S. Tar Sands 6
General Environmental Setting of Utah's
Major Tar Sand Deposits 11
III. Production of Tar Sands 13
Production Methods 13
Surface Mining 15
In Situ Production 26
IV. Extraction and Upgrading of Tar Sand Bitumen 42
Processing Operations 42
Potential Environmental Impacts 48
V. Environmental Comparison of Tar Sand Production
and Processing Technology 64
VI. Energy Perspective of U.S. Tar Sands 69
REFERENCES 72
APPENDICES
A. Illustrations of Mining Methods 76
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FIGURES
Number Page
1 Occurrence of Petroleum-Impregnated Rocks and Shallow
Oilfields in the United States 4
2 Distribution of Tar Sand Deposits in Utah 7
3 Area Strip Mining with Concurrent Reclamation 16
4 Contour Mining 17
5 Steam Drive in Situ Recovery Process 31
6 Illustration of Forward and Reverse Combustion in
Situ Recovery Processes 33
7 Diagramatical Illustration of a Wet Forward
Combustion in Situ Recovery Process 35
8 Flow Schematic of Process Equipment in Fire Flood
Recovery Operation Showing Various Emissions 39
9 Flow Schematic of a Water Reuse Processing Facility for
a Steam Injection Recovery Process 41
10 Flow Sheet for Tar Sands Extraction System Used at
GCOS Plant 43
11 Flow Sheet for Tar Sand Oil Upgrading System 46
12 Flow Sheet for Tar Sand Oil Upgrading System Used at
GCOS Plant 47
13 Sulfur Balance Flow Sheets for Tar Sand Oil
Upgrading System 49
A-l Block Cut Method 77
A-2 Box-Cut Method 78
A-3 Slope Reduction: One and Two-Cut Method 79
A-4 Parallel Fill Method, Modified Slope Reduction 80
A-5 Mountain Top Removal Method 81
A-6 Head-of-Hollow Fill 32
A-7 Longwall Stripping 83
VI
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TABLES
Number Page
1 Deposits of Bitumen-Bearing Rocks in the United
States with Resources over 1,000,000 Barrels 5
2 U.S. Tar Sands Reserves 5
3 Major Tar Sand Deposits in Utah 8
4 Characteristics of Utah's Major Tar Sands 9
5 Types of Potential Primary Environmental Impacts—
Surface Mining of Tar Sands 21
6 Range of Constituents in Produced Formation Water:
Offshore California 38
7 Hydrocarbon Emissions "rom Storage Tanks 51
8 Emission Factors for Petroleum Refining Processes '. . . . 52
9 Uncontrolled Emissions to Air From Tar Sand Oil
Upgrading System 53
10 Controlled Emissions to Air From Tar Sand Oil
Upgrading System 54
11 Water Use Characteristics of Category B Petroleum Refineries ... 56
12 Maximum Effluent Rates Based on New Source Performance
Standards for Petroleum Refineries 60
13 Observed Effluent Loadings for Category B
Petroleum Refineries 61
14 Qualitative Evaluation of Wastewater Flow and
Characteristics by Fundamental Refinery Processes 62
15 Environmental Comparison of Potential Tar Sand Production
and Processing Methods 65
16 Effect of Production Variables on Utilization of Tar Sand
Resources 70
vii
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SECTION I
INTRODUCTION
Reported are the results of a preliminary study to determine the
potential primary environmental impact of producing and processing bitumen
in U.S. tar sands deposits. Bitumen in the U.S. deposits, currently
estimated at 25 to 30 billion barrels, is a potential source of synthetic
crude oil. Laboratory research and experimental or pilot field projects
on methods of recovering tar sand bitumen have been conducted on an inter-
mittent basis for some 3 decades in the U.S. Commercial interests in the
deposits have waxed and waned over the years. Up to the present time, the
U.S. tar sands have not been able to compete with other energy resources
for the capital required for their commercialization as a source of syncrude.
The United States' increasing dependence on imported natural crude has
been well publicized. National policies and programs to decrease this
dependence have caused an upsurge in interest in the contribution that U.S.
tar sands, as well as other potential syncrude resources, could make to the
U.S. energy picture.
At the present time, the only tar sand deposit being commercially pro-
duced on a large scale is the vast Athabasca deposit in Alberta, Canada,
an operation that began about 10 years ago. However, inplace reserves of
this deposit are about 20 times greater than those of all U.S. deposits as
they are now known.
Many interacting factors will determine if, when, to what extent, and
at what rate U.S. tar sands are developed in the future. One of these
factors, the potential primary environmental impact of the producing and
processing the tar sands, is the subject of this report.
Results of the study are presented in five sections. In order of
presentation, the contents of these sections relate to:
(1) Characteristics of U.S. tar sands deposits, i.e., their
geographical distribution and properties
(2) Probable emission sources and other potential causes of
primary environmental impact expected to be associated
with methods of producing tar sand reservoirs and with
extraction and upgrading of tar sand bitumen
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(3) Assessment of potential primary environmental impacts
of the production and processing segments of a U.S.
tar sands industry
(4) Environmentally preferred components of a tar sand
operation
(5) Perspective of U.S. tar sands as a source of syncrude.
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SECTION II
CHARACTERISTICS OF U.S. TAR SANDS
Tar sands is a general term applied to deposits of unconsolidated and
consolidated clastic sediments whose interstitial spaces are partially or
completely saturated with highly viscous bitumen or hydrocarbon materials.
Bitumen also occurs in fractures and vugular pores of carbonate rocks but
generally not in sufficient quantities to make them of commercial interest
as a source of syncrude. Other terms used to refer to or include tar sands
are bituminous sands, asphaltic rocks, and oil-impregnated rocks.
Although there is no clearcut definition of tar sand reservoirs, they
differ from conventional oil reservoirs by the high inplace viscosity of
the oil or bitumen. A general rule of thumb is that at reservoir temper-
atures heavy oil will flow to the well bore at very low rates; whereas, for
practical purposes, bitumen in tar sands will not flow at all. Order of
magnitude values of the viscosity of the bitumen can range from several
hundred thousand to several million centiposes.
GEOGRAPHIC DISTRIBUTION OF U.S. TAR SANDS
More than 500 occurrences of surface and shallow oil- impregnated rocks,
including tar sands, are known in 22 states (see Figure 1) (1-3) f but their
evaluation as a resource base is not complete. Major U.S. tar sands, as
shown in Tables 1 and 2, have been estimated to represent a resource base
or inplace reserves of between 18.7 and 30.1 billion barrels.*
The State of Utah, with some 85 to 95 percent of inventoried U.S. tar
sand resources, has been comparatively active in evaluating its bitumen-
bearing rocks. Even in the case of Utah, "reserve estimates assigned to
deposits are largely a matter of personal judgment and educated guesswork
buttressed with a certain amount of carefully considered
Other states are beginning or attempting to begin work to inventory
their deposits in greater detail than they are now known. Alabama has
recently completed a study(5) of the bitumen-bearing Hartselle Sandstone in
northern Alabama. Missouri, Kansas, and Oklahoma are initiating or hope to
initiate cooperative efforts in the heavy-oil region of their tristate area,
parts of which -also contain tar sands. (6-10) Oklahoma is investigating best
* One barrel equals 42 gallons; one gallon equals 3.76 liters.
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*'*•'.*
H SOUTH
NEB RASKA
4 « C°LOR,00
K A N S 4
^Sli^r^oTfH
0 K L A H ' A
&UBAM%EORG I
LEGEND
n PETROLIFEROUS ROCK
SHALLOW OILFIELD
COUNTY REGULAR SHALLOW OILFIELD,
FIGURE 1. OCCURRENCE OF PETROLEUM-IMPREGNATED ROCKS AND SHALLOW
OILFIELDS IN THE UNITED STATES
[From Reference (1)]
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TABLE 1. DEPOSITS OF BITUMEN-BEARING ROCKS IN
THE UNITED STATES WITH RESOURCES
OVER 1,000,000 BARRELS1
State and name of deposit
California:
Edna _
South Casmatia -. -. -
North Casmalia
Sisquoc
Santa Cruz ...
McKittrick
Point Arena . . ...
Kentucky:
Kyrock area . . . .
Davis-Dismal area..
Bee Spring area
New Mexico: Santa Rosa . .
Texas: Uvalde
Utah:
Tar Sand Triangle
P.R. Springs . .
Sunnyside
Circle Cliffs
Asphalt Ridge
White rocks
Hill Creek
Lake Fork
Raven Ridge
Rimrock
Resources
(millions of barrels)
141.4-
46 4
40.0
26.0-
10.0
4.8-
1.2
18.4
7.5-
7.6
57.2
124.1-
10.000.1-
3,700.0-
2,000.0-
1,000.0-
1,000.0-
65.0-
300.0-
15.0-
100.0-
30.0-
166:4
50.0
9.0
11.3
140.7
18.100.0
4,000.0
3,000.0
1,300.0
1,200.0
125.0
400.0
20.0
125.0
35.0
U.S. total 18,694.9- 28,863.2
'Source: Extraction of energy fuels. Federal Council for Science and Technology. Bureau of Mines open file report
30-73. Wa-.hington, O.C. 1972.
Reproduced from Reference (3) *
TABLE 2. U.S. TAR SANDS RESERVES1
State
Alabama
California
Kansas
Kentucky
Missouri
New Mexico
Ohio
Texas
Utah
Total
Largest
published
estimate
(in place)
billion
barrels
0 15 *
.321
05
.084
.0009
.057
.0005
.14
29.3
30.1 ...
Date of
latest new
information
1973
1963
1964
1951
1935
1942
1941
1962
1973
1 Compiled by Dr. Frederick Camp of Sun Oil Co. All data represents the work of other investigators. There is no input
of original data from the Sun Oil Co.
Notice: Only Utah has reserves reported greater than 1,000,000,000 bbls. Only Utah and Alabama report recent exploration.
Reproduced from Reference (3).
* 1975 estimate for the Hartselle deposit is 1.18 billion
barrels
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use of tar or asphaltic sands in southern Oklahoma and Kentucky is compiling
existing information preparatory to publishing on that state's tar sand
deposits.(6)
Utah has 51 deposits(H) ranging in size from those with little to no
interest as a resource to the Tar Sands Triangle group of deposits (see
Figure 2) with inplace resources estimated at 12.5 to 18 billion
barrels.(3,4,12,13) of Utah's inventoried 24 to 28 billion barrels of
inplace bitumen, some 40 percent occurs in central Utah in the Uinta Basin
(see Table 3) and 60 percent in central southeast Utah.
PROPERTIES OF U.S. TAR SANDS
Utah's major deposits occur in sandstone and siltstone.(12) Ritzma'H'
summarizes the lithology of Utah's deposits as follows:
"Most deposits, particularly those of major size, occur in
sandstone which, with finer grain size, grades into siltstone
and, with coarser grain size, grades into grit and conglomerate.
More than 98 percent of the estimated oil in place in Utah's
deposits is contained in sandstone and siltstone.
Along the south flank of the Uinta Basin, the Argyle Canyon,
Minnie Maude Creek and Willow Creek deposits contain notable
amounts of oil-impregnated limestone in the Green River
Formation. The Thistle deposit, also in the Green River,
contains considerable heavily impregnated oolitic limestone
and coquina. The Split Mountain deposit occurs in coarse
crystalline and vuggy Park City Formation limestones. The
Daniels Canyon deposit occurs in highly fractured quartzite
and siliceous limestone.
In central southeast Utah, all deposits are contained in
sandstone, siltstone, and some conglomerate, except for
small amounts of oil-impregnated limestone found in San
Rafael Swell and Teasdale deposits and localities.
The Mexican Hat deposit (San Juan County) occurs in Pennsylvania
carbonate rocks, and the Rozel deposit (Box Elder County) is
found in oolitic mud and salt on the shores of Great Sale Lake".
Values of porosity, permeability, and oil and water saturation exhibit
variations and ranges that might be expected in tar sand deposits. Values
of these and other properties of major Utah tar sand deposits are shown in
Table 4.(12>14)
In the winter of 1975, the Laramie Energy Research Center conducted a
reverse combustion experiment near Vernal, Utah, in the northwest Asphalt
Ridge deposit.(' Average characteristics of 22 samples from cores of that
Rim Rock Member (Mesa Verde Formation) test are as follows.
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H
UTAH GEOLOGICAL & MINERAL SURVEY SHEET < a 2
Mip 33.
SupcKcdn Hip Ho, II. "FMiimiwr Lvoiion Mw.
Oil Imtnjnitcd Rodi DtpotiB o{ Uuh". Af(ll l»«
LOCATION MAP
OIL-IMPREGNATED QQCK DEPOSITS OF UTAH
April 1973
Howard R. Ritimt
REPRINT JULY, 1974
fined on publWwd, unpublitfwd ind contributed dm
•nd on origin*! field inrntigrtiom of U.G.& MS. perumwl
Principrt ioveMigMon. 1965-72: R-L BIAcy, J.L. Bowmin, W,D. Bynt til,
J.W. Gwynn, D.C. Mwtn, P.R. feienon. A.R. Pntt, S. Quigtov, H.fl. Riumt
WYOMING
A R ' " I Z" ' "6 N A
FIGURE 2. DISTRIBUTION OF TAR SAND DEPOSITS IN UTAH
[From Reference (11)]
AND SOLD |v THE
UTAH GEOLOGICAL AND MINERAL SURVEY
DONALD T. MCMILLAN, DIRGCYOfl
103 UTAH GEOLOGICAL SUBVCV BUILDING
LHUvenUTY OF UTAH
SAIT UAKI CITT. UTAH. Mill
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TABLE 3. MAJOR TAR SAND DEPOSITS IN UTAH
[From References (4) and (12)]
Bitumen
Deposit In-place (106bbls)
Uinta Basin
P. R. Spring 4,000 - 4,500
Sunnyside 3,500 - 4,000
Hill Creek 1,160
Asphalt Ridge 1,150
Argyle Canyon 100 - 125
Raven Ridge 125 - 150
Whiterocks 65 - 125
Central Southeast Utah
Tar Sands Triangle 12,500 - 16,000
Circle Cliffs-East Flank 860
Black Dragon 100 - 125
Family Buttes 100 - 125
Circle Cliffs-West Flank 450
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TABLE 4. CHARACTERISTICS OF UTAH'S MAJOR TAR SANDS
Average Values * '
Permea- Bitumen Water
Porosity bility, sat., sat.,
Deposit I P. v. (») md Z P. V. Z P.V.
Asphalt Ridge 19.6 497 51.4 2.7
N.W. Asphalt
Ridge 22.8 603 45.2 20.2
Circle Cliffs 12.3 228 17.7
Hill Creek 20.2 325 29.7 2.1
P. R. Spring 25.0 1,510 42.5 3.0
Sunnyside 21.3 729 44.8 —
Tar Sand 20.0(c) 207 --
Triangle 19.7 788 70.7
White Rocks
Ranges, []
Compressive Areal No. of
strength, Extent pay
psi (sq. miles) zones
2,491
20-25 2-5
1,598
27.7 1-3
6,555 115-125 6-13
[3]
4,784 240-270 1-13
[13]
7,805 35-90 1-12
3,242(c) 200-230 1
~"*
0.6-0.75 1
« No. of Samples,
Cross
thickness
of pay
(Stracigraphic
range, feet)
M'ftl •
v
10-135
5-310
53-65
(61)
10-102
(7) (39)
15-550
5-300
1000+
() • Average
Overburden
Thickness
(feet)
0-500+
f\l\
Value U '
Gravity
* API
S. 6-17. 5
[4]
Gallons/
Ton
13-27
'
6-26
[4)
0-500+ -11.1-22.4
0-500+
0-500+
0-500+
0-1600+
0-470
[9J
5.5-10.5
[5] (7.9)
5.8-10.3
[37H9.5J
6.2-6.7
[2]
-3.6-9.6
[5] (+4.5)
4.4-12
1.0-21.2
[129]
0.2-30.5
[454J
„
4.9-13.7
[5](9.3)
4.5-31.4
(a) All reference (14) values based on samples from cores except as indicated.
(b) P. V. •• pore volume.
(c) Surface samples.
(d) Total liquid saturation, percent by weight.
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Porosity, percent
Permeability, millidarcy
Oil saturation:
percent of pore volume
percent by weight
Water saturation, percent of
pore volume
Bitumen
Inplace
10.5
182
54.0
7.6
16.0
After Bitumen
Extracted
28.5
615
Listed below are ranges in average properties of the Hartselle Sandstone
deposit at various locations in northwest Alabama.(5)
Porosity, percent pore volume
Oil saturation, percent pore
volume
Thickness, feet
Barrels per acre-foot
Barrels per acre
Gallons per ton
Range
6.0
8.4
2
60
232
0.8
23.8
48.9
55
499
12,802
7.0
Average
259
5,270
3.7
Depths to the Hartselle Sandstone range from zero to more than 1,000 feet.
Oil inplace is estimated at 1.18 billion barrels over 350 square miles where
the formation is thicker than 150 feet.
Analysis of oils extracted from the tar sands vary from deposit to
deposit.(4,5,11,16,17) Sulfur in the Uinta Basin oils (approximately 80
samples) is on the average about an order of magnitude less than in the oils
from central southeast Utah (approximately 30 samples). For the former,'
Ritzma(4) has cited values ranging from 0.14 to 0.87 percent with an average
of 0.4 percent. In contrast, sulfur in oils from central southeast Utah
range from 1.64 to 6.27 percent with an average of 4.0 percent. Ranges for
sulfur and nitrogen in extracts from the Hartselle bitumen in Alabama are
1.08 to 1.43 percent and 0.29 to 0.5 percent, respectively.
Average concentrations of metals in 220 tar ash samples from Unita and
Grand Counties, Utah deposits are listed below in parts per million.
Chromium
Cobalt
Copper
102.92
103.10
109.63
Manganese
Nickel
Zinc
547.47
203.00
211.63
Other metals in the tar ash identified by emission spectroscopy are aluminum,
calcium, iron, lead, magnesiuin, silicon, silver, sodium, titanium, and
vanadium.
10
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Citing Humphreys*, McConvilled8) compared raw bitumen and synthetic
crude product from the Great Canadian Oil Sands, Ltd. commercial operation
at the Athabasca deposits:
Raw Synthetic
Bitumen Crude Product
Sulfur 4.5 - 5.0% 0.2%
Nitrogen 0.5 - 1.0% 0.1%
Vanadium 150 ppm Nil
Ash 1.0% Nil
Other values noted for metals in the Athabasca bitumen (in ppm) are:
Vanadium 210; 250; 290
Nickel 82; 100
Iron 75
Copper 2; 5
GENERAL ENVIRONMENTAL SETTING OF UTAH'S
MAJOR TAR SAND DEPOSITS
Utah's major deposits are characteristically in relatively inaccessible
and sparsely populated areas and often rugged mountainous terrain with
Asphalt Ridge being the more notable exception. The Sunnyside deposit is
at elevations of 8,000 to 10,000 feet with elevations of other deposits
ranging from 6,000 to 8,700 feet. Canyons with 800 to 1,000-foot relief
are commonplace. The more prominent streams are the Colorado and Green
Rivers but intermittent streams and dry valleys are the general rule in the
immediate environs of the tar sands.
Deposits underlie Federal, state, private, and Indian lands, but most
of the land is Federally-owned.(13)
Ritzma(H) summarized the setting of Utah's deposits as follows:
"Lack of or difficult access to large sources of fresh water will
hamper exploitation of these deposits as sources of oil in most
areas. Water supplies may be available in parts of the Uinta Basin
to support mining and processing operations on rich, concentrated
deposits, such as Whiterocks and parts of Asphalt Ridge. Water
supply is a serious factor in considering exploitation of the large
potential reserves of the Tar Sand Triangle and Circle Cliffs.
The Circle Cliffs deposits are partially within the extended
boundaries of Capitol Reef National Park and the remainder of
the deposits is within areas proposed for various scenic, recre-
ation, and wilderness preserves. Access to the deposits is severely
limited.
* Humphreys, R. D., "Some Engineering Aspects of the Tar Sands Project",
Paper presented at the 75th Annual General Meeting of CIM, Vancouver,
B. C., April, 1973.
11
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The Tar Sand Triangle deposits lie mostly within the Glen Canyon
National Recreation Area and immediately west of Canyonlands
National Park. Access to the area for development purposes is
severely restricted.
Other conflicts over land use and environmental considerations
are expected to greatly influence development of all of Utah's
deposits, particularly those susceptible to open-cut mining
methods."
12
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SECTION III
PRODUCTION OF TAR SANDS
PRODUCTION METHODS
Laboratory research, field experiments, and pilot field projects have
involved two basic approaches for producing tar sand reservoirs—mining of
tar sand as an ore for subsequent extraction and upgrading of the bitumen
values and in situ methods of reducing viscosity of the tar sand bitumen so
that it will flow to a producing well.
Mining
When the ratio of waste (e.g., overburden) to tar sand is below certain
limits, tar sand reservoirs can be produced by surface mining technology
quite similar to that used for surface mining of coal and ores. A break-
even value for the overburden to pay ratio is difficult to determine
initially^!"' and requires analysis of several costs including those of
alternative mining methods and equipment, transportation of ore to a surface
processing facility, the processing facility, transportation and disposal of
spent sand, and environmental protection measures. The characteristics of
the waste material to be stripped, i.e., whether or not the overburden and
any nonproductive strata within the tar sand deposit require drilling and
blasting, also affects the costs of a surface mining operation. Richness
of the tar sand ore has obvious importance to determination of the break-
even ratio of waste to tar sand as does the market value of syncrude. In
his discussion of commercialization of the Athabasca deposits, McConville(18)
states that, with current technology and costs, probable limiting ratios of
1:1 to 1:1.5 for large tar sand bodies although for small areas the limiting
ratios may be as high as 2.5:1 to 3:1, depending on richness of the deposit.
Discussion in U.S. literature is almost exclusively concerned with
surface mining as opposed to underground mining. In areas where overburden
would be too thick for an economical surface operation, underground mining
versus in situ methods would require an analysis of tradeoffs between the
two methods. Although about 90 percent of the bitumen can be recovered from
the tar sand mined by underground methods, some percentage of the tar sand
would not be mined. Maximum bitumen expected to be recoverable by in situ
production is around 50 percent. The tradeoff analysis would then center
around what percentage of the tar sand ore would have to remain inplace for
an underground operation. Also, if one of the constraints facing an under-
ground operation is to prevent or substantially reduce the potential for
surface subsidence over a mined-out area, then this percentage could be
13
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quite significant and this, in effect, might completely offset the higher
recovery efficiencies from mined ore. During this study, no in-depth infor-
mation was noted on whether or not underground mining of U.S. major tar sand
deposits is practical from a mining engineering point of view-
In Situ Production
The approach of in situ methods for producing a tar sand reservoir is
that of reducing viscosity of bitumen so that vapors or oils will move to
producing wells where it can be lifted to the surface. Although field pro-
jects to test various in situ approaches have been conducted in the U.S. and
Canada, a commercial operation for producing tar sands by in situ methods is
still in the future.
Two advantages of in situ over surface mining methods are that the
former would eliminate the need for handling and processing vast tonnages
of bitumen-bearing materials and for disposing of the resultant spent sand
waste. One disadvantage, from a resource utilization point of view, is that
recovery efficiency would probably be no greater than about 50 percent com-
pared to around 90 percent probable from processing of mined tar sand. The
heterogeneous and nonuniform nature of tar sand characteristics also poses
problems in prediction and control of in situ performances and processes.
As indicated previously, a principal factor involved in deciding between
in situ and surface mining methods is the ratio of thickness of overburden
and nonproductive layers in a deposit to the thickness of the pay sand or
sands. Although this ratio may be uneconomical for a mining operation, the
properties (e.g., fractures and joints) of the overburden or perhaps its
thickness could be insufficient to confine the pressures associated with
some in situ methods. Thus, at least in concept, there could be some tar
sands at depths intermediate between those favorable for surface mining and
those for in situ methods that involve a build-up of pressure in the reser-
voir. Which of the in situ methods that may ultimately be applied for
commercialization of U.S. tar sands is not known within the current state
of knowledge. About the most accurate statement that can be made at this
time is that no single method will be applicable to all deposits.
The U.S.S.R. is reported to have developed a combination of underground
mining and in situ methods to produce high viscosity crude. In commercial
use since 1972, the thermal-mining technology involves sinking of mine
shafts to a depth above the pay zone, drilling and blasting of passages to
drilling/production galleries, and drilling of inclined .and/or horizontal
production wells from the galleries. Stream is injected into the reservoir,
produced oil and water are moved to a sump, and oil is separated from the
water and pumped to a central collecting point where it is heated again
before it is pumped to the surface. Production to date is from depths to
650 feet with 50 to 60 percent recovery from a reservoir containing crude
with viscosities of 15,000 to 20,000 centipoises.
14
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SURFACE MINING
The basic technology of area and contour methods for surface mining of
coal are expected to be applicable to U.S. tar sand deposits in the event of
their commercialization. The area method (Figure 3) would apply to deposits
underlying flat terrain and the contour method (Figure 4) and its variations
(see Appendix for illustrations) to hilly or mountainous terrain. A con-
siderable body of literature exists on these methods of mining coal with a
central theme of much of the more recent literature concerned with variations
and practices to reduce impacts of mining. The methods are aptly described
in summary form in References (21) and (22).
Adaptation of the longwall method for mining deep underground coal to
mining of shallow coal deposits is under investigation.(23,24) Should this
adaptation of the method, called longwall stripping(23)} prove to be com-
mercially practical, it too might be a candidate for mining some tar sands
deposits from the surface (see Figure A-7 in Appendix A).
Materials Handling
Surface mining of U.S. tar sands would involve removal and handling of
substantial tonnages of material including overburden, ore, and any inter-
bedded waste rock. In that sense, a surface tar sand mine operation would
be essentially analogous to a surface coal mine. However, once the mined
tar sand is processed (bitumen extracted), large quantities of spent sand
will also have to be handled. In this sense, the materials handling require-
ments associated with a tar sands mining operation would be different from
those of a surface coal mine operation. If an extraction plant is located
near the tar sands mine, which would be the expected case in a large
operation, the spent sand presumably would be returned to the mine area for
disposal.
A perspective of the material that would be handled can be gained by
assuming a U.S. mining operation that supplies tar sand feed to an adjacent
extraction plant supplying an upgrading plant produing 10,000 barrels* per
day of syncrude. Then, using a tar sand feed containing 20 gallons of
bitumen per ton of sand (approximately mid-range of values in Table 4),
approximately 29,000 tons of tar sand ore per day would be required if the
ore contained no appreciable water. After extraction of the bitumen, about
26,000 tons per day of spent sand would need to be returned to the mine or
some other area for ultimate disposal.** If an overburden to pay ratio of
1:1 is assumed, then an additional 29,000 tons of this material would have
to be handled, giving a total materials handling requirement of 84,000 tons
per day. Multiple handling of some portion of the material would be required
as mining and reclamation operations proceed.
* Size of plant used in the subsequent section on extraction and upgrading;
see Figure 11 in that section.
** In concept, depending on its properties, impurities and distance to a
market, the spent sand could become available as a material for con-
struction or other industries using quartz sand as a raw material.
15
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ME AREA '
•
-- V...W, .„!/,. V-'"'-. ..:...
mwm^&i%$£.
ORIGINAL SURFACE
~ ~CO~AL BED
J-I~-r— STRIPPING BENCH ——
'FIGURE 3. AREA STRIP MINING WITH CONCURRENT RECLAMATION
(Reproduced from Reference 21)
-------
/I-?: fYV fyf*}.*f3^7^1gK?£*?v*:'-&?&y i-Vf
P^^C^^^^^^-^^'f^^
SL-S.-JQjfi-'r^Vf-V 'y'^ft'^**2.fCKvV*ClpCt%*ifcSi&ftJtS\iJifol'^S-ri»<(PK'<
J. S/Tf PREPARATION
2. DRILLING & BLASTING OVERBURDEN
3. REMOVAL OF OVERBURDEN
4. EXCAVATING & LOADING
FIGURE 4. CONTOUR MINING
(Reproduced/Modified from Reference 21)
-------
oo
(See Appendix for variations and
approaches to surface restoration)
TOE
FIGURE 4. (Continued)
-------
The operation of Great Canadian Oil Sands, Ltd. (GCOS) at the
Athabasca deposits has proven the technical feasibility of surface mining,
at least at that location. That integrated operation can produce 55,000
barrels of oil per calendar day by processing 140,000 tons per day of tar
sand mined at a stripping ratio of 0.5:1.(18) Other proposed Canadian
mining operations include(18):
Company
Syncrude Canada
Shell Canada and
Shell Explorer
Petrofina Canada,
et al.
Syncrude
Production
(bpcd)*
125,000
100,000
122,500
Tar Sands
Ore
(106 tpy)**
92
75
?
Overburden
or Waste
(106 tpy)
45
29
?
Stripping or
Waste to Pay
j
Ratio
0.5:1
0.38:1
1.5:1
U.S. tar sand deposits are much smaller than the Athabasca deposit and thus
a single U.S. operation the size of any of these Canadian facilities is
h i ghly unlikely.
The following materials handling operations would probably be character-
istic of a U.S. tar sand surface mine:
• Surface clearing
• Removal of overburden
• Mining of ore (tar sand)
• Removal of barren rock or ore that is too low in grade
• Construction of haul roads
• Transportation of ore to processing facility
• Construction of impoundments and drainage diversion
channels
• Transportation of tailings
• Surface grading and contouring for reclamation
• Rehandling of temporarily-stored waste.
As mining progresses and reclamation begins, different combinations of these
operations may be going on simultaneously.
* Barrels per calendar day.
** Tons per year.
19
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The size of an operation, terrain, mining method, rock properties,
geology, characteristics of the tar sand, and distance to a process plant
would all play a role when choosing type, size, and mix of equipment to be
used, e.g., shovels, draglines, bulldozers, ripping dozers, pan scrapers,
large trucks, bucket-wheel excavators, conveyors, and pipelines for tailings.
Potential Environmental Impacts
The types of primary environmental impacts that could result from a
surface tar sand mining operation are shown in Table 5. Of the types
indicated, those that actually occur, as well as their duration and severity,
will depend on details of mining and material handling methods employed;
size of the operation; all elements of the premining environment; and the
degree to which sound environmental protection measures are practical during
planning, mining, and surface restoration phases of the operation. Area
mining is generally considered to pose less potential for impact than con-
tour mining but some of the major deposits in the U.S., particularly in
Utah, are in areas of high relief.
Air Emissions^—
Air emissions should be quite similar to those from surface mining of
coal except that as tar sands are exposed, volatiles in the bitumen could be
an additional emission source. Severity would depend on temperature,
elevation, and whether or not fractures in the overburden have allowed some
of the volatiles to escape during geological time.
Materials handling operations can produce dust, particularly if over-
burden or rehandled waste is dry and unconsolidated. Haul roads are a
source of dust when transporting ore and spent sand but water or hydroscopic
materials can be used to reduce dust generated from this source. Ore could
be transported by conveyors which would eliminate dust from hauling of ore
to an extraction plant. Spend sand can be slurrieu with extraction process
water and pumped to a temporary or permanent disposal area which would also
eliminate the use of haul roads for this purpose.
Diesel engines emit particulates, sulfur oxides, nitrogen oxides,
hydrocarbons, aldehydes, and organic acids.(25) Quantities would depend
on fuel composition, size and mix of diesel-powered equipment, terrain,
size of mining operation, and whether or not ore and/or spent sand is
transported in earth-moving equipment.
Water Emissions and Solid Wastes—
Surface mining operations that disturb existing or expose new surfaces
would increase availability of solubles and suspendable constituents for
aqueous transport. Duration and severity of impacts on water quality
resulting from these operations would depend on terrain, climate, details
of mining method and environmental protection practices, geochemistry of
overburden, method of transporting ore and/or spent sand, surface drainage
patterns, and geohydrology.
Excluding possible effects of chemical differences between tar sands
and coal, types of impacts on water quality of a surface tar sand mine would
20
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TABLE 5. TYPES OF POTENTIAL PRIMARY ENVIRONMENTAL IMPACTS--
SURFACE MINING OF TAR SANDS
Operation or Source of Impact
Site Preparation
Surface Clearing (cleared
area)
Stripping (stripped area)
Tar Sand Extracting (mined
area)
Haul Road Transportation
(construction)
Tailings Disposal
Bitumen in Tailings or Low
Grade Tar Sand Waste
Fines in Tailings
Stripped Waste
Solubles or Water-
Transportation Particles
in Overburden
New Surface
Increases in Surface Slope
From Waste Disposal
Rehandling of Materials:
Backfilling, Grading,
and Recontouring
Increased
Air Emissions
Volatile
Engine Hydrocarbons
Dust Exhaust of Bitumen
X X
X X
X X
X
X X
(X) (X)
X X
X
X X
POTENTIAL IMPACT
Increased Availability of
Aqueous Transportable Materials
Suspended/
Solid Waste Dissolved
Generated Inorganics Organics Solids
X (X) (X)
X (X) (X)
(X) (X)
X
X
XXX
X X
X
X X
X
(X)
(X)
(X)
X
(X)
X
X
X
X
X
-------
TABLE 5. (Continued)
NJ
POTENTIAL IMPACT
Surface Changes
Operation or Source of Impact
Site Preparation
Surface Clearing (cleared
area)
Stripping (stripped area)
Tar Sand Extracting (mined
area)
Haul Road Transportation
(construction)
Tailings Disposal
Increased Destruction
Landslide of Existing
Risk Vegetation
X
(X)
(X)
(X)
Alteration
of
Habitats
X
(X)
X
(X)
Topographic Drainage
Changes Diversion
X X
(X) (X)
X
(X)
(X) (X)
Increased
Noise
X
X
X
X
(X)
X
Changes
Ground Water
Regime
Physical Chemical
(X)
(X)
(X)
(X)
Bitumen in Tailings or Low
Grade Tar Sand Waste
Fines in Tailings
Stripped Waste
Solubles or Water-
Transportation Particles
in Overburden
New Surface
Increases in Surface Slope
From Waste Disposal
Rehandling of Materials:
Backfilling, Grading,
and Recontouring
(X)
-------
be essentially analagous to those of a surface coal mine in the same area.
Surfaces disturbed, exposed, or created by mining operations, are bared to
the erosive action of precipitation runoff with attendant increases in
suspended solids with the extent being a function of slope and "looseness"
of the surface materials. Good mining practices in sloping terrain provide
for diversions of runoff upgradient from a mine and/or downgradient
retention basins as well as reducing the slope of waste material as mining
progresses. Permeable materials underlying bare surfaces are also exposed
to the chemical action of water on soluble components. This water can then
return to the surface downgradient to become a part of surface water or
enter the groundwater, depending on site specifics.
The organic phases of tar sand bitumen are more similar to petroleum
than to coal. Hence, exposed tar sand surfaces and unrecovered bitumen in
spent processed sand, if exposed to the physical action of runoff, will be
a potential nonpoint source of organic loading (primarily alkane—or para-
ffin—type hydrocarbons of heavy molecules with lesser amounts of aromatics)
that is not associated with a surface coal mine operation.
Sulfur in the bitumen is present as organic compounds which are oil
soluble and should not be leachable. Also, trace metals in the bitumen, as
in petroleum, are present as oil soluble organic compounds, e.g., porphyrins
and salts of organic acids. Although a majority of these compounds are
insoluble in water, some could hydrolyze and the metal ion become soluble
in water. The extent to which hydrolysis will occur is pH and rodox
potential dependent, being less pronounced in alkaline solutions (e.g.,
alkaline surface and ground waters).
A potential for impact on water quality could develop if either (1)
hydrolyzable components in the bitumen of tar sand ore wasted at the mine
site or in spent sand wastes or (2) their hydrolyzed products become avail-
able for aqueous transport. However, surface-breached tar sands have been
exposed to surface waters over geologic time and subsurface deposits are a
part of the geohydrological regime of an area. Thus, it can be conjectured
on one hand, that surface mining could reduce potential for impacts on water
quality because tar sand ore would be removed for processing. On the other
hand, increased exposure (change from an anaerobic to aerobic environment)
of tar sand bitumen as a result of (1) tar sand benches exposed during
mining operations, (2) mine-wasting of low-grade tar sands, and (3) presence
of unrecovered bitumen on surface areas of spent sand grains would be sources
of water quality degradation.
If tar sands in their natural setting (before mining) are now degrading
water quality*, then surface mining of tar sands could add to this degra-
dation. If tar sands in their natural setting are not presently degrading
water quality, surface mining could still result in conditions that have
potential for impacting water quality because of exposure of tar sand bitu-
men. Evaluation of this potential would require field and laboratory
studies.
* No data were noted on water quality in the environs of a tar sand deposit.
23
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In the event that bitumen in the tar sand is extracted by a hot water
process with caustic soda added, some components of the bitumen, including
metal compounds and aliphatic and aromatic organic acids, would be expected
to react with the water and dissolve (hydrolyze). In that case, unrecovered
bitumen in the spent sand should contain very little free water leachable
components. Any process water wasted with the spent sand could, however,
contain hydrolyzed products.
Other factors affecting the potential impact on water quality are the
products of weathering resulting from (1) increased area of bitumen exposed
and (2) wasting of coal and of oil shale known to be associated with some
tar sands. Exposure of coal containing pyrite leads to formation of iron
sulfate and in the case of oil shale weathering of organic components leads
to the formation of organic acids.
Site specifics that will influence potential for water quality impacts
include geochemistry of overburden; pH and redox potential of waters;
climate, particularly preciptation; terrain; and^geohydrology. Adherence
to environmentally sound mining practices, including burial of wasted coal,
oil shale, low-grade tar sand, and spent sand as quickly as possible, will
reduce whatever potential that might exist.
The same can be said for any measures taken to prevent erosive action
of water on bared surfaces and/or to use sedimentation basins, either of
which would reduce the potential of contaminants being transported as
colloidal or suspended solids or by adhering to suspended inert mineral
particles.
Based on the preceding discussion, potential sources of effluents that
could be associated with a surface mining operation are precipitation runoff
from the mining area, infiltrated water, and effluents from spent sand
tailings ponds and processing facilities. Characteristics of effluents
expected from a hot water extraction and from a tar sand oil upgrading
facility are discussed in a subsequent section. Collectively, these sources,
within an effluents guideline perspective, would contain the following con-
stituents:
BOD
COD
TSS
Oil and grease
PH
Phenolic compounds
Ammonia as N
Sulfur compounds
Metals
Solids.
Surface Changes—
Surface mining of tar sands would change the topography of the land
surface through the stripping and excavation of overburden and ore, the
construction of haul roads, and the disposal of waste materials. Vegetation
24
-------
on stripped areas, areas graded for facilities (e.g., power lines, roads,
and colocated extraction and upgrading plants), and nonstripped areas used
for disposal of solid wastes and for impoundments would be destroyed.
Collectively, topographic changes, denudation of vegetated areas, and noise
from mining (equipment and blasting) can impact wildlife and wildlife
habitats.
Surface topography could be restored in part with degree of restoration
dependent upon terrain. Efforts to revegetate areas would meet with varying
degrees of success depending on availability of top soil, mining practices,
terrain, and climate. More generally, factors determining the degree to
which the area of a tar sand mine can be restored to a premined status
should not differ from those of a surface coal mine in the same area with
one significant exception; namely, reclamation and revegetation of spent
sand waste disposal areas. Approaches to restoring an area of a tar sand
mine to a premined status will have to address problems of restoring areas
used for disposal of spent sand from a bitumen extraction plant. Depending
upon specifics of an operation, e.g., present or possible future regulations,
terrain, extraction process, and method of transporting spent sand to a
disposal area, methods of "disposing of spent sand will likely include:
(1) Temporary disposal in ponding areas until the sand can be
disposed of permanently in mined out areas without inter-
fering with mining operations
(2) Permanent disposal behind dams constructed in valleys near
a mine or processing plant.
Revegetation of spent sand disposal areas has been the subject of con-
tinuing research at the GCOS operation in Canada. Attendant problems at
that operation include those of poor settling properties of clay particles
and other fines in the tailing ponds and of minor amounts of bitumen in
the tailings which has precluded recycling of water back to the processing
plant. Reports are that GCOS has spent at least $1.5 million in research
on this problem and that it would cost up to $1.75 per barrel of recovered
oil to get the fines to settle out of the water completely.(1°)
Ground Water—
Previously discussed surface sources which might degrade quality of
surface waters would also be potential sources for impacting ground water
quality. Possible transport mechanisms include infiltration of precipitation
runoff as it moves downgradient after being in contact with the surface
source, precipitation seeping downward through the surface source with
resultant leachate entering the groundwater, and process effluents (from
adjacent processing facilities) that follow either of these two routes.
In addition to characteristics of the surface sources, potential for
impact would depend on the amount and time distribution of precipitation,
geohydrological and geochemical parameters, and distance the groundwater
travels before it recharges surface streams or is withdrawn for use. With
regard to the latter, shallow wells (used for watering livestock) in alluvial
25
-------
aquifers are relatively common in intermittent or dry stream beds in remote
and semiarid areas. Quality of water in these aquifers that supply wells
downgradient from a nearby tar sand mine probably would present the most
immediate potential for being affected.
Potential physical effects of surface mining on groundwater are trace-
able to two basic causes either, both, or none of which could occur at a
specific mine. If the mine intersects an aquifer or aquifers, then ground-
water supply to wells, at least to those located immediately downgradient,
could be interrupted or diminished. Wells supplied from perched water
tables or alluvial aquifers in intermittent or mostly dry stream valleys
would be especially susceptible to this type of an effect.
The second cause stems from changes in runoff coefficients resulting
from alteration in surface characteristics controlling the amount of pre-
cipitation that infiltrates as a local source for charging an aquifer.
IN SITU PRODUCTION
Up to 90 percent of the tar sands deposits in the United States have
been estimated to be at depths greater than 300 feet.'^) In situ production
methods are potentially applicable for recovering bitumen in tar sand
deposits that are too deep for surface mining methods to be economically
feasible. Where used, these methods would obviate several sources of
potential environmental problems associated with surface mining, e.g.,
disturbing large surface areas, removing overburden, mining and trans-
portation of ore, generation of dust, extraction of the bitumen from the
sand, and transportation and disposal of spent sand.
The technology for in situ production of tar sands is not as developed
as that for surface mining and has not been proven commercially or demon-
strated to be economically feasible. The technology is still focused on
the experimental and field pilot study phases. In situ production would
not yield as high a bitumen recovery as would surface mining. Recovery
efficiencies of around 90 percent can be expected from surface mining,
whereas in situ recovery efficiencies probably would range up to approxi-
mately 50 percent.
General Methods and History of
In Situ Production
In situ production of a tar sand reservoir would require drilling one
or more wells into the pay sand, setting casing, and perforating the casing
in the potentially productive pay zone. Because of the highly viscous nature
of the tar sand bitumen, in situ techniques for its recovery would differ
from those generally employed for conventional oil recovery. The viscosity
of the bitumen must be reduced to a level that will enable it to flow
through the sand matrix to the well bore. This may be accomplished by
injecting hydrocarbons, solvents, or emulsifiers into the reservoir to
dissolve the bitumen and thereby reduce its viscosity, or by adding heat
directly by the injection of steam or indirectly by air injection and
26
-------
combustion of part of the bitumen in place. The addition of liquid solvents
and emulsifiers has generally proven to be more costly, slower, and less
effective than thermal methods of recovery, and most research and field
testing has emphasized either direct or indirect thermal recovery. One
reason for the apparent advantage of thermal techniques over solvent
techniques is the rapid decrease in bitumen viscosity with increases in
temperature, e.g., a 5° API tar sand oil found in California has a viscosity
of 38,000 centipoises (cp) at 140° F, 1050 cp at 210° F, and only 57 cp at
325° F.<27>
In situ production of a tar sands reservoir would involve using some
of the wells to inject the heat or fluid into the reservoir and other wells
to produce the bitumen. To improve areal sweep efficiencies, flood patterns
would be employed to direct the injection fluid, or heat front, to central
producting wells; some commonly used flood patterns are line drive, 5-spot,
7-spot, and 9-spot.
Pilot field projects to develop in situ methods for producing tar sands
have been conducted intermittently in the U.S. for about 2 decades but, to
date, no U.S. or Canadian deposits have been commercially produced by these
methods. In 1959-1960, Standard Oil of Ohio tested steam flooding in Utah's
Northwest Asphalt Ridge deposit; Shell and Signal Oil (1965-1966) experi-
mented with steam flooding in Utah's Sunnyside deposit; and Gulf, in the
1960's, conducted a fire flood experiment in Utah's Asphalt Ridge deposit.
Experiments have also been carried out in Kentucky and western Missouri
deposits, and pilot tests to produce viscous oil from California's Vacar
Tar Sand were conducted by American Petrofina in the mid-1960 's using cyclic
steam injection.
The most recent field test in the United States was conducted by
ERDA's Laramie Energy Research Center on a 9-spot reverse combustion fire
flood near Vernal, Utah, on a Sohio lease at Northwest Asphalt Ridge. The
fire flood burn was started in November, 1975, and was terminated after only
4 weeks because of poor area sweep efficiency.
At present, there is no evidence of other recent tar sand production
field test projects in the United States. A considerable number of pilot
and commercial scale projects have been conducted, however, in several states
for the production of viscous heavy oils. Since the early 1950' s, over 100
in situ projects to recover heavy oils have been reported in the literature.
In Canada, in situ research efforts have been conducted by Imperial Oil,
Shell Canada, Amoco Canada Petroleum, and Gulf Canada. Imperial Oil has
spent over $15 million^O on a research and pilot project to test steam-
injection recovery techniques for heavy oil at its Cold Lake facilities.
Shell Canada has conducted steam injection tests on the Peace River oil
sands deposit, and Amoco is continuing tests of a 50-bpd pilot plant at tar
sand deposits near Fort McMurray. Gulf Oil has recently been given approval
by the Alberta Energy Resources Conservation Board for a 50-bpd steam-driven
pilot test at the Wabasco tar sands deposit.
27
-------
Most in situ production development, to date, has been conducted on the
heavy oil deposits. These heavy oils are similar in composition to tar
sands bitumen but have some degree of mobility. The general rule of thumb
for distinguishing between heavy oils and tar sands bitumen is that heavy
oils will flow at a very low rate, e.g., one barrel per day, whereas tar
sand bitumen will not flow at all at reservoir temperatures. The basic
technologies employed for producing heavy oils are, however, potentially
applicable to the less mobile tar sands bitumen . The specific in situ
production technologies that are discussed below are either currently, or
have been, applied to tar sand and heavy oil deposits in the United States
and Canada.
Specific Methods of In Situ Production
Most information on specific processes and field-test results was
obtained through a search of technical journals and reports, reprints of
presentations at meetings and symposia, and telephone communication with
persons familiar with in situ production methods. In most cases, the
technical content of environmentally-related information was neither
explicit nor quantitative. Little information was available on the
economics of the processes or the analysis of the coproduced streams, e.g.,
produced water and produced gas. The characteristics of coproduced streams
are thus presented only on a generic basis.
Chemical Injection—
Chemical injection involves the injection of hydrocarbon-based solvents
or aqueous alkaline surfactants into the producing zone to lower the vis-
cosity of the heavy oil or bitumen. Solvent stimulation using naphthenes
and aromatics has been practiced successfully in California since the mid-
'60's for the recovery of heavy oils. The process served principally as a
well-bore stimulation technique in which the solvent was injected into the
zone around the well bore to dissolve the heavy oils and paraffins. In one
test, after injecting 500 to 1,000 barrels of solvent, the well was placed
back on production.(27) -^he process was repeated until most of the crude
oil in the well-bore vicinity has been produced.
In tests conducted by the USBM near Bartlett, Kansas, in the early
1970fs, explosive fracturing of a heavy oil reservoir was followed by
solvent stimulation. The experiments met with moderate success; about 12
percent of the oil contained within a 3-spot well pattern was produced.
The application of solvent stimulation or miscible drive displacement
for tar sands, however, has not been successful. Shell Canada(29) experi-
mented for several years on the Athabasca tar sands and concluded that
viscous fingering and gravity overlay effects, coupled with the high cost
of the naphthenes and aromatic solvents, rendered the process economically
infeasible. At present, there appears to be no activity", either in the
United States or Canada, directed toward the use of miscible solvents to
produce tar sands.
Shell Canada developed an alternative to miscible solvent injection
that utilizes aqueous-based emulsifying fluids. The emulsifiers were
28
-------
believed to be superior to the miscible fluids in that the oil-loaded
emulsifying fluid possessed a viscosity only slightly greater than the
original emulsifying fluid and lower than the viscosity of a comparably
loaded solvent-based fluid. Moreover, the flow of the injected emulsifiers
occurred in the wetting phase path, meaning the bank of tar or heavy oil
ahead of the displacement did not have to be moved to obtain penetration
into the zone. Two systems were formulated for use in the Athabasca tar
sands: (1) an alkaline solution of proprietary nonionic surfactants and
(2) a dilute solution of sodium hydroxide. Field testing indicated that
the contacted portion of the reservoir was limited to where high gas or
water existed, or where a fracture was created. The result was that pene-
tration and dissolution of the tar into the oil was a very slow process and
the concept was abandoned.
Steam Injection—
Cyclic Steam Injection—Cyclic steam injection has found wide commercial
application since its introduction in 1959 for the production of heavy oils.
In this method, steam is injected into a producing zone, followed by an
alternate period of production from the same well. The method takes
advantage of the high latent heat of vaporization of the steam which, upon
condensation, is transmitted to the reservoir. The steam heats the
reservoir in the vicinity of the well bore and thus reduces the oil
viscosity, permitting the oil to flow during the production cycle.
Development of a cyclic steam injection project entails drilling
several closely spaced wells into the reservoir and injecting anywhere from
1,000 to 25,000 bbl of 500° to 700° F steam into each well.(30) The
injection process generally lasts a few days after which the wells are shut-
in to allow time for the reservoir to "soak". The wells are then opened
and produced. The cycle may be repeated several times before the oil pro-
duction rate diminishes to an uneconomical level.
Cyclic injection has been used successfully in major heavy oil fields
in the United States, particularly California. The viscosities of the oil,
at reservoir condition, are, however, relatively low (less than 40,000
cp).(3D
Imperial Oil, Ltd.(32) has invested $15 million in a 5,000 bpd project
at Alberta's Cold Lake oil sands (100,000 cp at reservoir conditions). Wells
are drilled in a 7-spot pattern and steamed for about a month, after which
time they are produced on pump for 3 to 4 months. About 30,000 barrels of
600° F steam are injected into each pattern yielding a production of 9,000
to 10,000 barrels of oil for a recovery of 20 to 30 percent of the oil in
place.(26) Produced water is separated from the oil by conventional methods
and reinjected into a deep formation for disposal. The produced gas, at
present, is separated from the produced liquids and flared or reinjected with
the steam. No information was available on the exact composition of the
produced gas, although it contains primarily C02 with small quantities of
methane and l^S. The produced water is saline, with 3,000 to 12,000 ppm
29
-------
NaCl, and somewhat basic with a pH of 8 to 8.5. The somewhat high pH is
attributed to the ion exchange process utilized to soften the steam feed
water.
Imperial Oil questions the application of steam cycling as an economi-
cally feasible method for producing the heavy oils. It was suggested that
extensive research will be required to more effectively utilize the steam,
improve sweep efficiencies, optimize selection of candidate production zones,
and reduce water influx. One major problem is the enormous volume of water
required for steam generation and the availability of water. Imperial is
currently working on a project designed to process the produced water to
make it acceptable to boilers.(32) Another problem with steam cycling is the
energy balance; the pilot project requires an equivalent input of one barrel
of oil for every three barrels of oil produced.
Cyclic injection is considered to be more suitable to reservoirs with
thick pay zones and large volume of oil in place per acre and with wells
capable of commercial production without steam injection.(33,34) There is
no evidence of cyclic injection having been successfully employed on oil
reservoirs with viscosities in excess of 100,000 cp. As this is signifi-
cantly less than the viscosity of tar sands bitumen (500,000 to 6 million
cp), nothing can, as yet, be concluded concerning the probable success of
steam cycling for tar sands production.
Steam Flooding—Steam flooding is similar to a conventional water flood
except that the injected fluid is steam, or steam with an emulsifier. An
illustration of a steam flooding recovery process is shown in Figure 5. Heat
losses restrict the distance that the steam front can be propagated through
the reservoir and pattern floods are generally used for the development of
a field, e.g., 5-spot or 7-spot patterns.
Steam flooding has found frequent application in reservoirs with high
viscosity oils and relatively good permeabilities. For oils with viscosi-
ties up to 1,000 cp at normal reservoir temperatures, horizontal sweep
efficiencies are usually high. However, viscous bypassing may be signifi-
cant for oils with normal reservoir viscosities greater than 1,000 cp.
Little work has been conducted on steam flooding highly viscous heavy
oil and tar sands. The most noted pilot scale work to date was conducted
by Shell Canada, Ltd. in the early 1960's on the McMurray tar sands in
Alberta, Canada. A 5-spot pattern of wells was drilled, the production zone
fractured, and a caustic and steam solution injected into the four corner
wells. Although no information was available on the actual volumes of
steam and caustic injected,or the volumes of oil produced, 0.685 tons (4 bbl)
of steam was injected per barrel of oil produced. From the results, Shell
concluded that a practical well spacing for a 5-spot pattern would be 4
acres per producing well and with this configuration predicted a possible
overall recovery of 50 to 70 percent of the bitumen in place. Due to the
high heat requirements for steam generation, Shell also concluded that for
a commercial operation to be economically feasible, no more than 0.5 tons
(2.9 bbl) of steam should be injected per barrel of oil recovered.
30
-------
Injection Well
Production Well
Steam
Oil and Wa
Overburden
.-— •
u-
^
\ Buffer
Sv 1 Zone
^VS. J -N_
\V. Hrnt-rrl r >
^S^«s. IICULLU 1 — -\/r
^S-^ Region /
/ -^
— -
ICold Region ^
n
9
FIGURE 5 STEAM DRIVE IN SITU RECOVERY PROCESS
-------
Although Shell Canada, Ltd. Is continuing to conduct field testing of
steam injection on a site in the Peace River oil sands deposit, a commercial
steam drive recovery project has not been implemented in either the United
States or Canadian tar sands. The major problems associated with steam
injection—high energy and water requirements and effective communication
between wells—have yet to be solved satisfactorily.
Fireflood—Fireflood involves in situ combustion to generate heat within
a formation by combustion of a portion of the in-place bitumen. Principally,
there are two variations of in situ combustion-r-forward and reverse.
The forward combustion process, illustrated in Figure 6, requires the
drilling of air injection and oil production wells. Ignition is started at
the air injection well and the combustion front propagates through the
formation in the direction of air flow toward the producing wells. The
temperature of the dry, burned region increases from the temperature of the
injected air at the sand face to the maximum temperature at the burning
front (600° to 900° F). Injected air captures heat from the burned zone
and moves it toward the burning front. Immediately ahead of the burning
front, water and light components of the crude bitumen are vaporized and
driven toward the producing well. The residual bitumen and coke provide
the fuel to sustain the combustion process.
Forward combustion has been applied primarily for secondary and tertiary
recovery of heavy oil with viscosities typically ranging from 100 to 1,000 cp
at reservoir conditions. The process has been demonstrated, however, to
suffer a major drawback, particularly with the heavier more viscous oils in
low permeability reservoirs. The oil and water vapors, swept ahead of the
burning front, contact the unheated portions of the reservoir where they
cool and condense. The condensed liquids become very viscous and tend to
plug the pores in which they are deposited thus restricting flow to the
production wells.
In a reverse combustion process, also illustrated in Figure 6, ignition
is affected in the production well and the combustion front propagates
through the tar sand toward the air injection well, i.e., counter to the
direction of air flow from the injection well. A portion of the bitumen
is vaporized and carried with the air stream to the producing well; the
remainder is burned as fuel or left as residual coke in the sand. Reverse
combustion has not been utilized to the extent that forward combustion has,
although two factors are cited as advantages over the forward combustion
process for tar sands application^^):
(1) The vaporized fluids are directed through the hot,
burned-out zone and are, therefore, less likely to
condense and plug the pore spaces.
(2) The oil produced is of higher quality as a result
of the thermal cracking of the bitumen.
32
-------
Injection
well
Production
well
Foword combustion
p
4
4
-------
The process, however, is sensitive to the air flux, or rate of injection of
air, which insures that the burning does not reverse direction and behave as
forward combustion.
The most recent reverse combustion experiment was conducted by ERDA/
LERC at the Northwest Asphalt Ridge tar sand deposit near Vernal, Utah,
in late 1975. Combustion tube experiments indicated that 40 percent of the
in-place bitumen would remain in the pay zone as coke and 10 percent would
be burned. On the basis of a 50 percent recovery and a 75 percent sweep
efficiency, it was estimated that 800 bbl of oil could be recovered from
the 9-well line-drive pattern. However, only 55 bbl of upgraded bitumen
and 170 bbl of water were recovered.(14,15)
Forward Combustion-Water Flood—This process (see Figure 7) involves
instituting a conventional forward combustion drive until a portion of the
reservoir has reached a temperature of about 1,500° F, after which water is
injected with air into the formation. The water serves to lower combustion
temperature, and the generated steam transfers the heat into the formation
more rapidly, accelerating the recovery process. This feature is regarded
as being particularly attractive for the recovery of tar sands bitumen.(30,35)
To date, most of the research on forward combustion and water flooding
has been conducted by the Amoco Production Company in the Athabasca tar
sands. Field tests, using conventional and reverse combustion, were com-
menced in 1958 to produce bitumen from the Gregoire Lake area. Shown below
are the properties of the tar sands and the bitumen.
• Specific gravity of bitumen 1.08
• Viscosity (200° F) 1,000 cp (50° F) 2,000,000 to 5,000,000 cp
• Hydrogen/carbon ratio 1.44
• Sand minus 200 mesh
• Porosity 35 to 40 percent
• Permeability most tar zones, 200-300 millidarcies, clean
sand from tar zones, several darcies, silt zones, few
millidarcies
• Saturations 0 to 90 percent bitumen (remainder water,
little or no gas saturation)
• Bitumen content on weight basis 0 to 18 percent.
In 1966, water was injected concurrently with air in a forward com-
bustion drive. The process was labeled the Combination Forward Combustion
and Water Flood. Tests performed on a 1/2 acre 5-spot pattern yielded a
32 percent removal of the bitumen in place and it was estimated that 55
percent of the oil heated to 150° F or more was recovered. Following this
34
-------
INJECTION
WELL
PRODUCTION
WELL
OVERBURDEN LAYER
yA Water & Air
HEATED
SAND
, COMBUSTION"^
ZONE
\ HYDROCARBON^'
VAPORS
COLD REGION
'OF RESERVOIR
FIGURE 7. DIAGRAMATICAL ILLUSTRATION OF A WET FORWARD
COMBUSTION IN SITU RECOVERY PROCESS
(From Reference 14)
35
-------
successful operation, an expanded pilot with 12 patterns over 35 acres was
developed. Additional tests are currently being conducted.(30)
Forward combustion with water flooding has the advantage over dry
forward and reverse combustion in that most of the coke is left in the
reservoir as residue, resulting in a less viscous, upgraded produced oil.(37)
Recovery efficiencies are also considered to be greater because of improved
heat transfer from the steam. In addition, the required volume of injected
air is generally lower with the combined water flood. A summary(38) Of
results from 24 dry forward combustion drives indicated an injected air/
produced oil ratio of 6 to 44 mscf/bbl as opposed to a range of 1 to 6
mscf/bbl for two wet combustion drives.
Wet combustion, in addition to water requirements of approximately one
barrel of water per mscf of injected air(3°), poses another possible problem
for producing tar sands. Condensation of the vaporized oils and water could
result in plugging of reservoirs with low permeabilities.(37)
Potential Environmental Impacts
To date, there is no commercial in situ production of tar sands and a
viable production technology is yet to be demonstrated. Information per-
taining to environmental effects is estimated on the basis of a few pilot
studies conducted on tar sands and the application of similar technology
for the production of heavy oils and is limited at best. Primary environ-
mental impacts should, however, be similar to those of conventional
petroleum production and any environmental problems could be addressed in
a similar manner.
Air Emissions—
Gaseous byproducts would constitute the major atmospheric discharge
associated with in situ combustion. The volumes of gases produced with the
oil may vary considerably depending on the reservoir conditions, the type
of production mechanism, and the characteristics of the bitumen in place.
Gas to oil ratios ranging from 5 to 75 mcf/bbl have been reported from in
situ combustion recovery operations.(38)
Generally, the produced gas can be expected to contain varying amounts
of sulfur compounds (S02, H2S, etc.), nitrogen, carbon dioxide, carbon
monoxide, oxygen, and hydrocarbons. A review(38) of 24 different wet and
dry in situ combustion recovery projects on heavy oil reservoirs showed the
average range of concentrations of the produced gases to be:
• Oxygen, 2.5 to 3.5 percent
• Carbon dioxide, 10 to 17 percent
• Carbon monoxide, 0 to 2 percent
• Hydrogen sulfide, 0 to 2 percent
• Methane, 0 to 2 percent; and the balance nitrogen.
36
-------
No information was found on particulates, SC>2, or nonmethane hydrocarbon
content.
An analysis(15»37) of the gas produced from the ERDA/LERC reverse
combustion test near Vernal, Utah, revealed the following approximate
compositions:
• Carbon dioxide, 9 percent
• Carbon monoxide, 3 percent
• Hydrogen, 1 percent
• Methane, 1 percent
• Nitrogen, 80 percent.
There was no evidence of hydrogen sulfide.
Generally, the gases probably would be very lean and lack sufficient
heating value to justify collection and processing for marketing. They
might be either vented from the water knockout and separation tanks to the
atmosphere, or combusted further to completely oxidize the carbon monoxide,
hydrogen sulfide, and methane. The ERDA/LERC pilot facility utilized a gas
treater with a continuous pilot flame to insure complete combustion of the
off gases.(37)
Other air emissions associated with in situ recovery projects are the
exhaust discharges from diesel or gasoline-powered equipment and dust
generated from vehicles traveling the access roads.
Water Emissions—
The most potentially significant quantity of water from a volume and
possible contamination standpoint would be water coproduced with the oil.
Some water almost always accompanies produced oil but may vary in quantity
from less than 1 percent to over 99 percent of the production stream. No
information was found on the composition of the water produced from the tar
sands production processes. However, since petroleum and tar sand reservoirs
can occur in the same areas, constituent species in the coproduced water
probably would be similar to those from conventional petroleum production,
an example of which is given in Table 6. Shown in Figure 8, a flow schematic
of some of the surface equipment employed in a fire-flood recovery operation,
are constituents to be expected in air, solid waste, and water emissions.
Coproduced waters in the conventional onshore petroleum production are
not known to present any major environmental problems as the common practice
is to reinject them into another subsurface formation. Subsurface disposal
of coproduced waters has been practiced in some in situ tar sands pilot
projects and is currently being practiced at Imperial Oil of Canada's Cold
Lake steam-injection pilot operation.
37
-------
TABLE 6. RANGE OF CONSTITUENTS IN PRODUCED FORMATION
WATER: OFFSHORE CALIFORNIA^)
Effluent
Constituent Range, mg/1
Arsenic 0.001 - 0.08
Cadmium 0.02 - 0.18
Total Chromium 0.02 - 0.04 .
Copper 0.05 - 0.116
Lead 0.0 - 0.28
Mercury 0.0005 - 0.002
Nickel 0.100 - 0.29
Silver 0.03
Zinc 0.05 - 3.2
Cyanide 0.0 - 0.004
Phenolic Compounds 0.35 - 2.10
BOD5 370 - 1,920
COD 340 - 3,000
Chlorides 17,230 - 21,000
TDS 21,700 - 40,400
Suspended Solids
Effluent 1-60
Influent 30 - 75
Oil and Grease 56 - 359
(a) Some data reflect treated waters for reinjection,
[From Reference (39)]
38
-------
Produced
Oil and
Water From
Fire Flood
I
Off Gas
C02
CO
H2S
CH4, C2H6
N2
02
u>
VD
Water Cooled
Heat Exchanger
3-Phase
Separator
Produced Sand
to Pit -
Oil With
Water
Emulsion
Water
Eaulsion
Separator
Produced
Water
Dissolved Solids
BOD, COD, Slightly
Acidic, Suspended
Solids, Oil, and Grease
Oil
Storage
Air
To Injection
[Disposal Well
FIGURE 8. FLOW SCHEMATIC OF PROCESS EQUIPMENT IN FIRE FLOOD
RECOVERY OPERATION SHOWING VARIOUS EMISSIONS
-------
In in situ tar sands production, water would be used primarily for
injection into the reservoir (steam flooding and wet combustion processes)
and for cooling the produced fluids. In some regions in the United States,
particularly where major tar sands exist, water available for these purposes
might be a problem. If so, it could be necessary to treat and reuse, rather
than dispose of the produced water by injection.
Treatment of the water prior its reuse for water injection in a wet
combustion process would involve neutralization, filtration, and flotation;
treatment for reuse for steam injection would likely require an additional
water-softening step (ion exchange). Figure 9 is a schematic of a water
reuse processing facility for steam injection recovery. Potential for
environmental impact would be low and somewhat comparable to that of
injection disposal.
Solid Wastes—
Produced sand and drill cuttings would constitute the major solid wastes
associated with in situ production. The produced sand should not be signi-
ficant if gravel packing or other sand filtration methods are applied in
the well bore. The sand that would be produced could be separated from the
bitumen and probably discharged into a pit that would later be backfilled.
This procedure is commonly employed on conventional onshore production.
The cuttings produced from the drilling operation could also be disposed
of by procedures commonly employed in the oil production industry—burying in
a pit and back-filling at the completion of the drilling operations. The
volume of cuttings would be relatively small; the drilling of a 600-foot well
would produce approximately 30 cubic yards of rock cuttings.
Disposal of drilling muds should pose little to no potential for
environmental impacts because these muds are customarily collected and
reused. Cable tool or air drilling operations do not employ drilling muds.
Surface Changes—
In situ production of tar sands offer much less potential for surface
impacts than surface mining. Some vegetation would likely need to be cleared
and the ground graded to accommodate equipment installations, but only
relatively small areas would be affected. Roads, pipelines, and the appro-
priate separation and treatment equipment would have to be constructed and
electric power and possibly telephone lines erected. Surface operations can
be conducted so as to avoid or minimize interference with the concurrent
land usage such as livestock grazing, agricultural cultivation, recreation,
and wildlife habitat.
At the completion of the production operation, all equipment and the
concrete pads could be removed and the wells plugged in accordance with
recommended procedures. Restoration of a site should not be an extensive
operation because the extent of disruption to the land surface would be
minimal.
40
-------
Produced
Oil and
Water
I
Water Cooled
Heat Exchanger
Produced
Sand
Produced
Water
Filter
Water
[Ion-Exchange)
Steam
Generator
Injection
Well
FIGURE 9. FLOW SCHEMATIC OF A WATER REUSE PROCESSING FACILITY
FOR A STEAM INJECTION RECOVERY PROCESS
-------
SECTION IV
EXTRACTION AND UPGRADING OF TAR SAND BITUMEN
PROCESSING OPERATIONS
Extraction refers to the separation of the bitumen, or tar sand oil,
from the mined tar sand. Upgrading refers to the on-site processing of the
tar sand oil to produce a synthetic crude oil product suitable for shipment
to a petroleum refinery. The final processing into products such as gasoline,
heating oil, etc. will almost certainly be done not at the mine site but
rather at a petroleum refinery. The complex processing operations necessary
to produce these final products would not be economical on the small scale
of a U.S. tar sand facility. Even the existing and planned Canadian tar
sand facilities, which are much larger than U.S. facilities will be, produce
only a synthetic crude oil.
Most of the operations required in the extraction and upgrading of tar
sand oil are identical to or similar to operations conducted in petroleum
refining. This fact has been used in analyzing the potential emissions from
these sections of a tar sand facility. It is also because of this similarity
that the extraction and upgrading sections are discussed generally together
here. However, separate discussions are provided where appropriate.
The processing operations selected for the emission analysis were based
on a consensus of the one existing and several planned Canadian tar sand
facilities. Material balance and emissions data are based on a facility
producing 10,000 bbl/day of synthetic crude oil product, which is about the
maximum size anticipated for U.S. tar sands.(40) These quantities can, of
course, be scaled proportionally to any other facility size.
Extraction Facilities
A flow sheet for the extraction system used at the Great Canadian Oil
Sands (GCOS) facility is shown in Figure 10.(18.19) This system is based
on the hot water extraction process first developed by Dr. K. A. Clark(41»42)
but also piloted by several companies. The extraction sequence includes the
following steps:
(1) Pulping of the oil sand with water, steam, and dilute
caustic
(2) Separating the bitumen from the sand by skimming and
froth flotation
42
-------
Makeup Naphtha
from Coker
Makeup
Water
Pond Water Return
Tar Sand Feed*!
2,480 T/D Bit.
26,710 T/D Min.
Conditioning
Drum
Froth
Settler
Oversize
Steam f o
i £
Caustic n ¥
..... w> i
Addition c
•H C Cr-t\i k
3 B rrotn
=! ^ _. Middlings
Separation
Cell \. Sand ^>
* Assume 20 gallons ^s. .s'
of bitumen per ton ^v^X^
of tar sand
T^ JO
4J
O
fe
1 ' r» ^
*-v» Scavenger [-J
M-JH^I -fnoQ Ce l!s
1 r
Settling Pond
1
\
f
Tail
;
I
Tar Sand Oil
to Coker
2,160 T/D Bit.
65 T/D Min.
300 T/D Bit.
25,790 T/D Min.
FIGURE 10. FLOW SHEET FOR TAR SANDS EXTRACTION SYSTEM USED AT GCOS PLANT
(QUANTITIES SCALED DOWN TO 10,000 B/D SYNCRUDE PRODUCT
FROM UPGRADING SYSTEM)
-------
(3) Mixing the bitumen froth with a diluent (naphtha)
(4) Centrifuging to remove water and fine solids.
In addition to the froth and sand removed from the separation cell, a
"middlings" stream is also withdrawn. This stream contains mostly water but
also some suspended fine mineral and bitumen particles. A portion of this
stream is returned for mixing with the conditioning drum effluent to dilute
it properly for pumping. The balance of the middlings, which is called the
"drag stream", is withdrawn to purge the system of very fine mineral matter.
The drag stream is treated by scavenging, which involves froth flotation
using air. The scavenger froth is combined with the settling cell froth,
and the tailings from the scavenger cell are combined with the separation
cell tailings. The tailings go to a settling pond.
Note that, based on Figure 10, the overall bitumen recovery in the
extraction section is about 87 percent.
Other extraction methods that have been proposed for tar sands include
cold water separation and anhydrous solvent separation.
Another alternative for separating the bitumen from tar sands is
retorting, a high temperature "destructive distillation" similar to that
used for oil shale. This alternative has not been given much attention in
the literature. In Europe, a Lurgi Ruhrgas process plant used in coal and
oil shale retorting experiments has been used in an experiment to distill
about 40 metric tons of American tar sand feed stock.(43) A major reason
that it might be considered for U.S. tar sands is that it could reduce the
water consumption, and Utah's tar sands are located in areas that are
generally short of water. The major disadvantage of retorting is that,
because of the high temperature required, the thermal efficiency (i.e.,
oil recovery efficiency) will be lower than for extraction. Also, the
quality of the oil product will be inferior because of increased degradation
of the hydrocarbons by the high temperatures and increased contamination of
the oil with trace species contained in the sand. On the other hand, the
lower water consumption should be reflected in a lower water pollution
potential. The major solid waste, i.e., the spent sand, should be
essentially unaffected.
All the planned Canadian tar sand facilities as well as the operating
GCOS include hot water extraction. For that reason, this process was
chosen for the emissions analysis given here. The fuel quantities shown
on the flow sheet in Figure 10 are based on 10,000 bbl/day of synthetic
crude oil product from the upgrading section (discussed below). The
quantities were scaled down from the material balance data for the GCOS
plant but are based on 20 gallons of bitumen per ton of tar sand feed (see
Table 4).
44
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Upgrading Facilities
The raw tar sand oil will be upgraded, probably on-site, to make it
more like a typical petroleum crude oil. This will involve
• Removing the small amount of mineral matter remaining
in the oil
• Decreasing the density, viscosity, and carbon/hydrogen
ratio of the oil
• Removing some of the sulfur and metals from the oil (most
U.S. tar sand oil contains more sulfur than most petroleum
crudes do).
To accomplish this, the GCOS plant plus all but one of the proposed Canadian
plants use a coking process followed by hydrotreating of the coker liquids.
The only exception to this sequence is the proposed Shell Canada, Ltd. plant,
which is to use vacuum flashing, solvent deasphalting, and hydrotreating.(19)
One reason for the attractiveness of coking as the primary upgrading step is
that the mineral matter (sand) in the feed cannot plug a coker and is
readily removed with the coke.
A flow sheet for the upgrading system is shown in Figure 11. A fluid
coker is used in this system. The naphtha and gas oil produced by the coker
are hydrotreated separately. Off gas from the coker and the hydrotreaters
is freed of H2S and then used to generate the hydrogen required and to meet
other fuel needs of the plant. The H2S recovered from the gas is converted
to elemental sulfur in a Glaus sulfur plant. The coke produced by the
coker is used to generate steam, part of which is used as such and part of
which is in turn used to generate the electrical power required by the plant.
The hydrotreated naphtha and gas oil are recombined to form the synthetic
crude oil product.
The fuel quantities shown on the flow sheet in Figure 11 were scaled
down from the material balance data for the proposed Syncrude Canada, Ltc.
plant.(19) Note that the overall oil yield for the upgrading section is
about 82 percent.
For comparison, a flow sheet for the upgrading system of the GCOS plant
is shown in Figure 12.(19) The primary differences between this flow sheet
and the previous one are that a delayed coker is used instead of a fluid
coker and three liquid streams are taken from the coker instead of two.
Delayed coking produces more coke than fluid coking, which is reflected in
a lower liquid product yield. The overall oil yield for this flow sheet is
only about 78 percent. The GCOS plant produces more coke than is required
for its fuel needs.(^) In order to bring the coke production more in line
with the needs and thus to increase the product yield, the future facilities
are planning to use fluid coking. One of the planned facilities (Home Oil/
Alminex) plans to use a variation of fluid coking known as Flexicoking, in
which most of the coker produced is converted into a fuel gas.
45
-------
Steaa
Naphtha to
•^—Extraction
202 B/D System
Tar Sand Oil
12,200 B/D
(2,160 T/D Bit.)
( 65 T/D Min.)
Sulfur
359 T/D Coke
65 T/D Min.
Synthetic
rude
10,000 B/D
(1,532 T/D)
FIGURE 11. FLOW SHEET FOR TAR SAND OIL UPGRADING SYSTEM
(FUEL QUANTITIES SCALED DOWN FROM SYNCRUDE,
CANADA FLOW SHEET)
-------
Gas
12,800 B/D
(2,280 T/D)
Synthetic
Crude
'* 10,000 B/D
(1,440 T/D)
580 X/D
FIGURE 12. FLOW SHEET FOR TAR SAND OIL UPGRADING SYSTEM USED AT GCOS PLANT
(QUANTITIES SCALED DOWN TO 10,000 B/D OUTPUT)
-------
The flow sheet based on fluid coking (Figure 11) should be more repre-
sentative of future tar sand facilities and hence was used in the calculations
presented here.
POTENTIAL ENVIRONMENTAL IMPACTS
Air Emissions
The extraction and upgrading facilities include a number of sources of
emissions to the atmosphere. Some of these emissions can be roughly quanti-
fied, whereas others can be discussed only qualitatively. Some of the
emission estimates to be discussed are based on the similarity of these
process operations to those used in petroleum refineries.
Sulfur Oxide Emissions—
The major potential sources of sulfur oxide emissions are the tail gas
from the Claus sulfur plant and the flue gas from the steam boilers. A
Claus plant normally recovers about 95 percent of the sulfur fed to it, and
the other 5 percent is present as SOX (primarily 802) in the tail gas. Tail
gas treatment processes are available that can increase the overall sulfur
recovery to 99.5 percent, thus reducing the tail gas emission by a factor
of 10. An even more severe problem is the flue gas from the steam boilers,
which are fired with the coke produced by the coker. If the feed to the
coker contains 4 weight percent sulfur, the coke produced will contain
about 5 weight percent sulfur.(45) Combustion of such a high sulfur coke
results in considerable emissions of SOX in the flue gas. Flue gas desul-
furization (FGD) processes are available, or at least being developed, that
can remove up to 90 percent of the SOX from flue gas. Actually, the same
S02 recovery process could be used for both the boiler flue gas and the
Claus plant tail gas.
To estimate the magnitude of these emissions, sulfur balances were made
for a tar sand oil (to the upgrading section) containing 4 weight percent
sulfur. This is the average concentration for the large deposits in south-
east Utah. The sulfur content of the syncrude product was taken as 0.27
weight percent, based on the Syncrude Canada data(19)} and that of the coke
was taken as 5 weight percent. Then, based on the flow sheet in Figure 11,
of the 86.40 tons/day of sulfur entering the upgrading section with the feed,
4.14 tons/day will leave in the syncrude, 17.95 tons/day will go into the
coke, and 64.31 tons/day will go to the Claus plant as H2S. Two sulfur
balances from that point on are shown in Figure 13. Without a flue gas
desulfurization system, the total emission will be about 42.3 tons/day of
S02- With a flue gas desulfurization system treating both the flue gas and
the Claus plant tail gas, the total emission will be about 4.4 tons/day of
S02-
Another option for controlling sulfur oxide emissions from the steam
boilers is to combust the coke in a fluidized bed with limestone added to
tie up the sulfur. This method would be as effective as flue gas desulfur-
ization in reducing the SOX emissions but would have the following
disadvantages relative to FGD:
48
-------
Uncontrolled
3.22 T/D S as SO,,
64.31 T/D S as H S
Sulfur
Plant
61.09 T/D S
' 17-95 T/D S as SO,
17.95 T/D S in coke
Steam
Boilers
Emission » 21.17 T/D S = 42.30 T/D SO,
Controlled
64.31 T/D S as
4.21 T/D S as SO-
17.95 T/D S as SO,
17.95 T/D S in coke
Steom
Boilers
80.04 T/D S
19.95 T/D S as SO,
2.22 T/D S as SO,
Emission •= 2.22 T/D S = 4.44 T/l) SO,
FIGURE 13. SULFUR BALANCE FLOW SHEETS FOR TAR SAND OIL
UPGRADING SYSTEM
(10,000 B/D Syncrude Product)
49
-------
• The Glaus plant tail gas problem could not be solved
simultaneously.
• The sulfur value would be recovered as a mixture of
calcium-sulfur compounds instead of as elemental
sulfur.
• The particulate matter emission via the flue gas would
be greater.
There may be some other emissions of sulfur oxides if process heaters
are fired with liquid products or intermediates. Emission factors for this
will be given in a later section. Information on the extent to which such
fuels will be used is not available. Most of the fuel needs of the plant
will probably be met with the cleaned fuel gas.
Hydrocarbon Emissions From Storage Tanks—
Storage tanks will be required for the tar sand oil feed, the naptha
and gas oil intermediates, and the syncrude product. The emissions of hydro-
carbons from these tanks would depend primarily on the type of tanks used.
Following EPA petroleum refinery guidelines, storage facilities required
would depend on volatility of stored hydrocarbons (Federal Register 39FR9308,
March 8, 1974):
• Nonvolatile (vapor pressure •''1.5 psia)
Cone roof tanks
• Moderately volatile (vapor pressure >1.5 but <11 psia)
Floating roof tanks
• Volatile (vapor pressure >11 psia)
Pressure facility.
To estimate the magnitude of these emissions, some calculations were
made using the equations developed by the American Petroleum Institute and
published by the EPA.(46) f^g results of these calculations are shown in
Table 7. The calculations are for a single tank for each material stored,
with the size of the tank based on the flow rate of the stream involved.
The data shown for floating-roof tanks apply for the best design of such
tanks and indicate that the emissions from such tanks are only about 3 per-
cent of those from fixed-roof tanks. As indicated in the footnote, some
types of floating-roof tanks can have emissions three times greater than
the "best design" values.
Miscellaneous Emissions—
There are a number of other emission sources in the extraction and
upgrading sections that can be roughly quantified based on the similarity
of many of the operations involved to operations in petroleum refineries.
This can be done by using the published emission factors for the pertinent
refinery operations, and these are given in Table 8.(47) The estimated
emissions based on these emission factors are shown in Tables 9 and 10.
50
-------
TABLE 7. HYDROCARBON EMISSIONS FROM STORAGE TANKS
Material Stored
Tank Size, 103 bbl
Tank Dimensions, ft
Vapor Pressure at 70 F, psia
Specific Gravity
Turnover Rate, E input/yr/B capacity
Enr'-sions for Fixed-Roof Tanks, 'lb/day
Breathing loss
Working loss
Total
Emissions for Flcating-Roof Tanks, lb/day
Standing loss
Withdrawal loss
Total
Tar Sand Oil Feed
100
122 D x 48
5.2
1.011
30
718
4,000
4,718
121
11
132
Naphtha
20
63 D x 36
6.6
0.751
13
330
920
1,250
66
_i
67
GC.S Oil
50
86 D >: 48
0.3
0.919
13
53
120
173
2
_3
6
Syncrude Product
100
122 D x 48
3.5
0.860
13
626
2,700
3,326
68
_4
72
Total
1,727
7.740
9,467
258
19
277
(a) Correspond to Reid vapor pressures of 7.0 psi for tar sand oil feed, 10.5 psi for naphtha, 0.4 psi for gas oil, and
6.0 psi for syncrude product.
(b) Data for proposed Syncrude, Canada plant.
(c) Froa "Supplement No. 1 for Compilation of Air Pollutant Emission Factors", 2r.d Edition, U.S. EPA, July, 1973.
Other parameter values taken froa this source were tank outage - 50% of tank helghc, csily temperature variation -
15 F, wind velocity = 10 mi/hr.
(d) For welded tanks. To calculate emissions for completely riveted tenks, multiply by the following factors:
Single Se_al Doub:.s 3as3
Pontoon Roof 2.89 2.44
Pan Roof 3.11 2.89
-------
TABLE 8. EMISSION FACTORS FOR PETROLEUM REFINING PROCESSES
Ui
Particulate Sulfur Oxides, Carbon
Type of Process
Boilers and process heaters
lb/103 ft gas burned
10/103 bbl oil burned
Fluid cckir.g units
Uncontrolled, lb/10 bbl fr feed
With ESP, ib/103 bbl fr feed
Compressor engines, lb/10 ft gas burned
Blow Down Systems
Uncontrolled, lb/10, bbl ref cap
Controlled, (c>lb/10J bbl ref cap
Process Drains
Uncontrolled, lb/103 bbl wastewater
Controlled,^) lb/103 bbl wastewater
Cooling Towers, lb/10 gal cooling water
Miscellaneous losses, lb/10 bbl ref cap
Pipeline valves and flanges
Vessel relief valves
Pur.? seals
Co-.pressor seals
Others*6)
(a) s - refinery gas sulfur content (lb/100
Matter
0.02
840
523
6.85
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
ft ). Factors
(b) S - fuel oil sulfur content (weight percent). Factors
of 336 Ib/bbl (0.96 kg/liter).
(c) Vapor recovery system or flaring.
as S02
Monoxide Hydrocarbons
2s Neg
6,720 S(b> Neg
NA
NA
2s(a)
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
based on
based on
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
complete combustion
complete combustion
0.03
140
Neg
Neg
1.2
300
5
210
8
6
28
11
17
5
10
of sulfur
of sulfur
Nitrogen
Oxides,
as NO
0.23
2,900
Neg
Neg
0.9
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
to S02-
to SO. and
Aldehydes
0.03
25
Neg
Neg
0.1
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
assumed fuel
Ar.conla
Neg
Neg
Neg
Neg
0.2
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
Neg
oil density
(d) Vapor recovery or covers on oil/water separators.
(e) Direct air blowing, sampling, etc.
\^y — — — — ~ — ^f -
Source: Compilation of Air Pollutant Emission Factors, 2nd Edition, AP-42, pp 9.1-3 to 9.1-5, U.S. EPA, April, 1973.
Conversion forlorn: kfi/Utrr - 0.002853 (Ib/bM), kg/m3 - 16.02 (lb/ft3), kR/lUor - 0.1198 (Ib/pnl).
-------
Ui
OJ
TABLE 9. UNCONTROLLED EMISSIONS TO AIR FROM TAR SAND OIL UPGRADING SYSTEM
(10,000 bbl/day Syncrude Product)
Emissions, Ib/day
Process Operation
Steam plant
Sulfur plant
Storage tanks (fixed roof)
Fluid coker
Blow down systems
Process drains
Cooling towers
Valves, flanges, seals, etc.
Subtotal
Process heaters
Compressor engines
(a) Based on 70" of mineral
P Articulate
Matter
2,450(a^
—
6,381
—
—
8,831
—
matter in coke feed
Sulfur Oxides,
as S02
71,733
12,850
—
—
—
—
84,543
Carbon
Monoxide
359
-------
TABLE 10. CONTROLLED EMISSIONS TO AIR FROM TAR SAND OIL UPGRADING SYSTEM
(10,000 bbl/day Syncrude Product)
Process Operation
Steam plant
Sulfur plant
Storage tanks
Fluid coker
Blow down systems
Process drains
Cooling towers
Valves, flanges, seals, etc.
Sulfur
Particulate Oxides,
Controls Matter as SO
Flue gas desulf (FGD)
system — 8,872
Tail gas recycle to FGD
system 0
Floating roof — —
Electrostatic precipitator 84
Vapor recovery or flaring
Vapor recovery or covers
on separators --
Ends sions , Ib /day
Nitrogen
Carbon Glides,
Monoxide Hydrocarbons as NO.
(a) (a) (a)
n b*l
— » ZOJ
61
106 Cc)
855
Aldehydes Acmonia
_-
Subtotal
Process heaters
Compressor engines
84
8,872
1,372
(a) Depends on type of flue gas desulfurization system used.
-------
Table 9 gives the uncontrolled emissions and Table 10 the controlled
emissions. These tables also include the data from the previous sections
on sulfur oxide emissions and hydrocarbons storage losses.
The miscellaneous emissions include (Table 9):
• Hydrocarbons from blowdown systems, process drains,
cooling towers, and leakage from valves, flages, and
seals
• Particulate matter from fluid coker and steam plant
• Nitrogen oxides from the steam plants.
There are also emissions from process heaters and compressor engines.
Emissions from the process heaters depend strongly upon whether gas or oil
is used to fire the heaters, as can be seen from the emission factors in
Table 8.
The emission control methods considered here include (Table 10):
• A flue gas desulfurization system for the steam boiler
flue gas and the Glaus plant tail gas
• Floating-roof storage tanks
• An electrostatic precipitator on the fluid coker
• A vapor recovery or flaring system for process blowdown
• Vapor recovery systems or covers on the oil/water separators.
These methods result in overall emission reductions of about 90 percent for
sulfor oxides, 88 percent for hydrocarbons, and 99 percent for particulate
matter. These figures do not include the emissions from process heaters and
compressor engines, which could not be estimated.
In order to estimate the emissions from two sources (process drains and
cooling towers), information was required on the cooling water circulation
rate and wastewater flow rate. Lacking any more specific data, average
data for Category B petroleum refineries were used.(48) These data are
shown in Table 11. A Category B refinery is one which includes cracking-
type processes like coking but not more complex operations such as lube oil
or petrochemical production. This concept will be discussed further in the
following section on water emissions.
A source of hydrocarbon emissions not shared by petroleum refineries
is that of evaporation from the surface of the settling pond used for the
tailings. This emission cannot be quantified but will be less than the
flow rate of bitumen to the pond (300 tons/day in Figure 10), since some of
this bitumen will be returned to the process with the pond water return.
55
-------
TABLE 11. WATER USE CHARACTERISTICS OF CATEGORY B
PETROLEUM REFINERIES
Cooling Water Circulation Rate, gal/bbl crude 1,450
Wastewater Flow, gal/bbl crude
Refineries with no once-through cooling water
Median 24
Range 4-89
Refineries with some once-through cooling water
Median 174
Range 7-6,861
Source: Brown & Root, Inc., "Economics of Refinery Wastewater
Treatment", API Publication No. 4199, pp V-2 and V-9,
August, 1973.
Conversion factor: kg/liter = 0.002853 (Ib/bbl).
56
-------
Water Emissions
The extraction and upgrading facilities include a number of operations
that will generate wastewater at various levels of contamination. Like any
other modern plant, a new tar sand facility would be expected to use modern
technology for reducing the wastewater flow and for treating the wastewater
prior to discharging it. The wastewater problems of a tar sand facility
will be very similar to those of a petroleum refinery. The final pollutant
emission rates from the facility will depend upon the extent to which the
wastewater is treated. Lacking other information, one can roughly estimate
the emission rates for a tar sand facility by assuming that such a facility
will have to restrict its emissions to about the same level as a modernly
controlled petroleum refinery of similar size and complexity. These concepts
will be elaborated on in the following sections.
Sources of Wastewater—
Based largely on the experience of petroleum refineries(49)s one can
say that the sources of wastewater from tar sand oil extraction and upgrading
facilities will include the following:
(1) Cooling Water Slowdown. As will be discussed in the
following section, the facility will almost certainly use
an evaporative, recirculating cooling water system. In
such a system, a small amount (usually 0.5-2 percent(45,49))
of the circulating water must be withdrawn to purge dis-
solved solids from the system. This "blowdown" contains a
very high concentration of dissolved solids (usually 0.2-
0.4 percent(49)) an(j small amounts of various species added
during treatment of the water or picked up during its use.
(2) Boiler Feed Water Blowdown. The normal practice in plants
requiring steam is to recycle the steam condensate for use
as boiler feed water. When this is done, a small amount
(typically about 5 percent(49)) of this water must be
withdrawn to purge dissolved solids from the system. This
blowdown is similar in composition to the cooling water
blowdown discussed above.
(3) Sour Water. Sour water, containing primarily H2S and NH3,
will be generated in the fractionation operations that
follow the coker and the hydrotreaters. In addition to
H2S and NH3, the condensate from the coker fractionator
will contain phenols and perhaps cyanides. Sour water can
also come from process knockout drums.
(4) Storm Water Runoff. The runoff water from paved process
areas and tank areas will be oily, whereas that from
utility areas will contain solids but not oil.
57
-------
(5) Pump and Compressor Cooling Water. Some water used in
cooling pump pedestals and glands and compressor jackets
will become contaminated with oil.
(6) Tank Bottom Draws. The water periodically drained from
tanks will be oily and in some cases also sour.
Water Segregation and Reuse System—
In order to minimize the wastewater treatment costs and the final
effluent rate, the facilities will employ modern technology for segregating
various effluent streams and reusing water. The facilities will almost
certainly use a recirculating cooling water system with tooling towers
rather than once-through cooling water. Steam condensate will be reused as
boiler feed water. Segregating the effluent according to composition will
increase the efficiency of the wastewater treatment system, since each
effluent will receive only the treatment it requires. For example, only
oily waters will go through the API oil-water separators.
Wastewater Treatment Processes—
A combination of wastewater treatment processes will be used in a tar
sand facility. These processes probably will be selected from the following:
• Primary Treatment Processes
Equalization (to dampen surbes in flow and loadings)
- API oil-water separators
Sour water strippers
• Secondary Treatment Processes
- Dissolved air flotation
- Aerated lagoons
- Activated sludge treatment
- Chemical coagulation and sedimentation
- Filtration.
Tertiary treatment processes, such as carbon adsorption, ion exchange, and
reverse osmosis, probably will not be used.
Estimated Effluent Rates—
The operations conducted in the extraction and upgrading sections of a
tar sand facility, and hence the wastewater problems, will be very similar
to those of a petroleum refinery. Therefore, one can use information on
petroleum refineries as a basis for roughly estimating the effluent rates
for a tar sand facility. To be more specific, one can use data for
Category B refineries. This category includes cracking-type or petro-
chemical production. Two types of data for such refineries can be used—
effluent regulations or effluent data—for actual refineries.
In considering effluent regulations, it is most meaningful to consider
the New Source Performance Standards (NSPS), since these apply to new
facilities such as the tar sand facilities will be. These standards specify
the maximum effluent rates, in pounds per thousand barrels of feedstock, for
58
-------
various effluent characteristics (BOD, COD, etc.). The standards depend on
the size and complexity of the refinery. The complexity is expressed in
terms of a "process configuration" factor, which is six for the flow sheet
of interest in which all the feedstock goes through a coker. For a Category
B refinery of this complexity and the size range of interest here (up to
24,900 bbl/day), the NSPS are given in Table 12.(50) Also included in
this table are the corresponding maximum effluent rates (in pounds per day)
for a tar sand facility producing 10,000 bbl/day of synthetic crude oil
product.
For comparison with the NSPS, some data on observed effluent loadings
for existing Category B refineries are given in Table 13.(51) This table
also shows the wastewater treatment processes used at these refineries.
For all the effluent characteristics on which data were available, the
observed effluent loadings span a fairly wide range (a factor of at least
2.5) and (except for ammonia) go both above and below the 30-day average
NSPS.
Some qualitative evaluations of the wastewater-related characteristics
of the individual processes used in the extraction and upgrading sections
are shown in Table 14.(51) This table indicates the extent to which these
processes contribute to the flow rate and various effluent characteristics
of the total wastewater.
Solid and Miscellaneous Wastes
The most abundant solid waste material produced by the extraction and
upgrading sections will be the mineral matter sent as tailing to the
settling pond. For a tar sand facility producing 10,000 bbl/day of
synthetic crude oil product, about 25,790 tons/day of mineral matter will
be rejected in this manner (see Figure 10). This mineral matter probably
will be returned to the mine.
Another 65 tons/day of mineral matter will go the steam boilers in the
coke. About 20 tons/day of this material will be recovered from the boilers
as bottom ash, and about 45 tons/day will go into fly ash in the flue gas.
If only cyclones are used, only part of this fly ash will be recovered. If
high efficiency electrostatic precipitators are used, over 99 percent of
the fly ash will be recovered. If a. flue gas desulfurization system is
used, some collection of particulate matter will be done ahead of the FGD
system. The mineral matter recovered as bottom ash or fly ash will be
relatively easy to dispose of because it will be inert and dry.
A small amount of waste material is produced by the amine treatment
operation used for removing H2S from off gases. This is a purge stream
containing primarily amines and various organic compounds produced from
amines. The amount of this purge stream is about 1.6 pounds per ton of
sulfur recovered from I^S.^) Therefore, based on the sulfur balance
previously discussed, a facility of the size considered here (10,000 bbl/
day) would produce about 100 pounds per day of this material.
59
-------
TABLE 12. MAXIMUM EFFLUENT RATES BASED ON NEW SOURCE PERFORMANCE
STANDARDS FOR PETROLEUM REFINERIES(a)
Maximum Total Effluent Rate for 10,000
Maximum Unit Effluent Rate,
pounds/1000 bbl feedstock^
Effluent Cnaracteristic
BOD5
CODj^
TSS
Oil and grease
Phenolic compounds
Ammonia as N
Sulfide
Total chroaiura
Kaxavalent chromium
pH (diaensionless)
For Any Average
One Day 30
5.75
41.16
3.97
1.69
0.0417
6.55
0.0367
0.0833
0.00714
of Daily Values for
Consecutive Days
3.07
20.83
2.48
0.92
0.0198
2.98
0.0169
0.0486
0.00317
bbl/day
For Any
One Day
70.2
502.2
48.4
20.6
0.508
79.9
0 . 44S
1.016
C.087
of Synthetic Crude Product
pounds, dsy^c'
Average of Daily Values for
30 Consecutive Days
37.5
254.1
30.3
11.3
0.242
36.3
0.206
0.593
0.039
Within the range 6.0 to 9.0
(a) Based on Federal Register, 40 (98), May 20, 1975. Standards for Category B refinery with process
configuration = 6.
(b) Feedstock is tar sand oil to upgrading. Values apply for up to 24,900 bbl/day.
(c) Based on 12,200 bbl/day tar sand oil to upgrading.
Conversion factors: kg/liter •* 0.002853 (Ib/bbl), kg/m3 - 2.853 (Ib/bbl), kg/day - 0,4536 (Ib/day).
-------
TABLE 13 . OBSERVED EFFLUENT LOADINGS FOR CATEGORY B PETROLEUM REFINERIES
Refinery Number
Wastewater Treatment Processes Employed
Aerated lagoon
Activated sludge
Dissolved air flotation
Equalization
Filtration
Oxidation pond
Polishing pond
Effluent Loadings, lb/1000 bbl feed
BOD,
R
COD
TSS
Oil and grease
Phenolic compounds
Ammonia as N
Sulfide
12345
XX X
X
X X
X
X
X
X X
2.8 4.4 2.1 3.6 1.3
13.8 24 34 25.0 13.8
8.7 12 3.0 1.5
0.8 3.2 1.4 1.0
0.001 0.145 0.13 0.018 0.002
1.7 0.05
0.07 0 0.010 0.005
Source: Development Document for Effluent Limitations Guidelines and New Source
Performance Standards for the Petroleum Refining Point Source Category,
EPA 440/l-74-014a, p 104, April, 1974.
Conversion factor: kg/liter = 0.002853 (Ib/bbl).
-------
TABLE 14. QUALITATIVE EVALUATION OF WASTEWATER FLOW AND CHARACTERISTICS.
BY FUNDAMENTAL REFINERY PROCESSES
to
Production Process
Wastewater Feed and
Characteristic Product Storage
Flow
BOD
COD
Phenol
Sulfide
Oil
Emulsified oil
pH
Temp
Ammonia
Chloride
Acidity
Alkalinity
Suspended
solids
XX
X
XXX
X
XXX
XX
0
0
0
0
XX
Distillation
XXX
X
X
XX
XXX
XX
XXX
X
XX
XXX
X
0
X
X
Coking/Thermal
Cracking
X
X
X
X
X
X
XX
XX
X
X
0
XX
X
Hydrotreating
X
X
X
XX
0
XX
XX
0
0
X
0
X - Minor contribution, XX - moderate contribution, XXX - major contribution, 0 - no
problem.
Source: Development Document for Effluent Limitations Guidelines and New Source
Performance Standards for the Petroleum Refining Point Source Category,
EPA 440/l-74-014a, p 18, April, 1974.
-------
If a flue gas desulfurization process is used, a small amount of
waste material may be produced as a result, depending on the nature of the
FGD process. For example, the Wellman-Lord FGD process, which would be
well suited to this application, produces a purge stream by which certain
oxidation products (e.g., sodium sulfate) are removed from the system. In
this case, processing steps can be included so that only a solid waste
material is produced. Although the quantity of this sulfate material is
small, its high water solubility makes disposal difficult.
63
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SECTION V
ENVIRONMENTAL COMPARISON OF TAR SAND PRODUCTION
AND PROCESSING TECHNOLOGY
Information on tar sand production and processing technologies and their
potential sources of primary environmental impact have been described in pre-
ceding sections. Drawing from that information, the environmental pros and
cons of the production and processing technoligies are discussed below and
summarized in Table 15.
Surface mining methods for producing tar sands would pose greater
potential for environmental impact than underground methods. This greater
potential is traceable to problems of restoring larger surface areas dis-
turbed by surface mining to a premined condition, the greater availability
of aqueous transportable materials and the restoration of areas used for dis-
posal of spent sand.
All mining methods pose greater potential for environmental impact than
in situ methods. This is because tar sands produced by mining methods would
require an intermediate process to extract the bitumen from the mined tar
sand ore. Thus, the potential impacts of bitumen extraction process would
either occur at or in the region encompassing the mining area in the case of
a colocated extraction plant or at some other location in the unlikely event
that the tar sand ore is transported considerable distances from the mine.
Environmental advantages of wet versus retorting (dry) extraction pro-
cesses are not as clear cut as in the case of production methods. Both
would generate solid waste and some process and/or cooling water effluent
with amounts dependent upon provisions for reusing water. Process effluents
from wet extraction could contain hydrolyzed components of tar sand con-
stituents which would have to be traded off against the potential air
emissions from retorting.
Tar sand oil extracted from the mined tar sand or produced by in situ
methods would go to an upgrading facility. In this sense, the potential
environmental impacts attributable to upgrading facilities would probably be
somewhat independent of production method. However, data on composition of
water, gas, and tar sand oil produced by the various in situ methods are
extremely meager. The tar sand oil might be transported to an existing
coke/hydrotreating facility for upgrading or a new facility constructed.
Several factors will determine which of these options is selected, not the
least of which is the location and size of the resource base.
64
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TABLE 15. ENVIRONMENTAL COMPARISON OF POTENITAL TAR SAND PRODUCTION
AND PROCESSING METHODS
Operation or
Process
Status of Tar Sand Technology
Major Potential Technical
Disadvantages or Environ-
mental Impacts
Major Potential Technical or
Environmental
Advantages
PRODUCTION
(1) Surface Mining
One commercial operation in
Canada; others planned or
proposed.
Small scale open-pit projects
in U.S,
No large-scale demonstration
of technology in U.S.
Oi
Host potential for surface changes
during mining.
Least potential for complete restoration
of surface to preraining condition.
Require removal and transportation of
tar sands.
Disadvantages include those of extraction
(see below).
Most potential for increasing availability
of aqueous transportable materials.
Generates most solid waste (mine waste plus
spent sand).
Greatest materials handling requirements
(solid waste plus tar sand).
Basic surface mining technology
applicable.
High to highest bitumen recovery.
(2) Underground Applicability of available
Mining underground mining technology
not yet investigated
Require removal and transportation of tar
sands.
Create potential for surface subsidence.
Disadvantages include those of extraction
(see below).
Can draw from available underground
mining technology.
Potential for underground disposal of
spent sand.
High bitumen recovery (longwall taethod
of mining).
Least potential (among mining methods)
for surface changes during mining.
Best potential (among mining methods)
for minimizing permanent surface
changes if no subsidence and spent
sand returned to mine.
Eliminates, stripping operation and
resultant solid wastes.
-------
TABLE 15. (Continued)
Operation or
Process
Status of Tar Sand Technology
Major Potential Technical
Disadvantages or Environ-
mental Impacts
Kajor Potential Technical or
Environmental
Advantages
(3) tongwall
Stripping
(4) In Situ
Production
From Surface
Applicability to tar sands not
yet investigated.
No commercial production to date
from tar sands.
Pilot projects have been conducted
but _ln_situ_ technologies for
Conner dally producing tar eanda
are not yet demonstrated.
Require removal and transportation of
tar sand.
Disadvantages include those of extraction.
If used after contour mining would probably
increase potential for environmental
impact.
Nonuniform nature of tar eand character-
istics poses technical problems.
Bitumen recovery expected to be less than
that for surface mining.
Availability of water unless coproduced
water treated and reused '(depending on
location end uethod)
Applicability of method for mining
of coal under investigation.
Total potential for environmental im-
pact probably less than that of
other methods ol mining same
amount of sands.
If used after contour mining, could
recovt-r greater percentage of tar
sand t.eposit.
Basic technologies include those of
producing hcpvy oil reservoirs.
Produce tar sands that are too deep
to be produced economically by
mining methods.
Eliminate generation of solid waste
of mining and spent sand from
extraction process.
Some upgrading of tar sand bitumen
could occur underground.
Coproduced waters could be disposed
of by subsurface treated and reused
in water-short areas.
Disturb much less surface area than
surface mining.
Eliminate potential sources of dust
and noise in surface mining operation.
(5) In Situ
Production
Underground
Applicability to tar sands not
yet investigated.
Disadvantages probably would be similar
to those of surface in situ
production.
U.S.S.R. reported to be producing
(20)
heavj oil deposit by this method
Other advantages probably would be
similar to those of surface in^situ
production.
-------
TABLE 15. (Continued)
Operation or
Process
Status of Tar Sand Technology
Major Potential Technical
Disadvantages or Environ-
mental Impacts
Major Potential Technical or
Environmental
Advantages
EXTRACTION OF
BITUMEN FROM MINED
TAR SAND
Wet Process:
One commercial operation in
Canada; others planned or
proposed/
Small scale or bench tests in
U.S.
Retorting:
Applicability to tar sands
generally unevaluated
exoertmentally*
Wet Process:
Generation and disposal of solid
wastes (spent sand).
Availability of water if process
water not reused.
Leached constituents in waste
.•ater effluents.
Retorting:
Availability of water for once-
through cooling systems.
High temperature could result
in more contaminants in syncrudc
than wet processes. ^
Wet Process:
Could result in less contaminants
in syncrude than retorting.
Retorting:
Could be less potential for water
pollution than in wet processes.
-------
As indicated above, development of a tar sand industry using in situ
methods of production poses the least potential for environmental impact.
From the viewpoint of maximum utilization of a tar sands resource base, pro-
duction of tar sands by surface mining would be preferred. In situ methods
or possibly underground mining might be possible, however, in lieu of sur-
face mining in environmentally sensitive areas where technical and economic
factors permit a choice of production method.
68
-------
SECTION VI
ENERGY PERSPECTIVE OF U.S. TAR SANDS
Factors restraining development of U.S. tar sands relate to or stem
from:
• Need for exploration of the deposits to acquire data for
evaluating their commercial attractiveness and for developing
a proven production and processing technology
• Lack of proven production and processing technologies,
particularly in situ technology, applicable to U.S.
deposits
• Envisioned problems, project delays, or cancellations,
because of possible or probable problems with environmental
acceptability of a tar sands industry. Major percentage of
deposits underlie or are in environs of national parks and
monuments, pristine wilderness areas, and arid/semiarid
mountainous terrain.
• Net energy to be gained (energy balance)
• Competitive position of tar sands vis-a-vis other energy
sources (e.g., teritiary recovery of oil, shale oil,
liquefaction and gasification of coal, and deep water
offshore oil) for manpower, equipment manufacturing and
construction resources, and available capital.
• U.S. tar sands, as now known, represent a comparatively
small resource base.
• Economic incentives and risks, investment climate, product
price, and governmental policies.
Given a resolution of restraints favorable for development of tar sands,
a "ball park" perspective of U.S. tar sands is that they might potentially
represent 7 to 10 billion barrels of syncrude, depending on how one specu-
lates on the values and combinations of the production variables involved.
Production variables include those shown in Table 16 as well as the per-
centage of tar sand reservoirs produced by each of the methods.
Ten billion barrels of syncrude from tar sands would be approximately
3-1/4 times the amount of natural domestic crude produced in 1975 and 6-3/4
69
-------
TABLE 16. EFFECT OF PRODUCTION VARIABLES ON
UTILIZATION OF TAR SAND RESOURCES
Production
Method
% of In Place
Assumptions Bitumen Produced
Surface Mining
Underground Mining
(b)
100% of Ore Recovered
90% Extraction Efficiency
90% of Ore Recovered
90% Extraction Efficiency
(a)
90
81
Continuous or 55% of Ore Recovered
Conventional 90% Extraction Efficiency
Longwall 80% of Ore Recovered
90% Extraction Efficiency
In Situ 50% Sweep Efficiency^
70% Displacement (d)
75% Sweep Efficiency
70% Displacement
90% Sweep Efficiency
70% Displacement
50
72
35
50
63
(a) Extraction efficiency: % of bitumen recovered from ore processed at
extraction plant.
(b) Underground mining of tar sands seldom mentioned in literature. Ore
recovery based or experience from underground mining of coal.
(c) Sweep efficiency: % of ore. body's total volume from which bitumen
is removed.
(d) Displacement: % of bitumen in affected volume driven to production
wells.
70
-------
times the amount of natural crude imported by the U.S. in 1975 (based on
values in Monthly Energy Review. FEA, PB-242769-12, December, 1975. Even
if all of the 30-billion barrel tar sand resource base were commercially
producable, domestic tar sand deposits would not approach the 600-billion
barrel^-*) resource base of the oil shale deposits of the Green River
Formation in western U.S. Consensus is that something in the neighborhood
of 7 to 10 years would be required to attain large-scale production of U.S.
tar sands, assuming a favorable resolution of the restraints listed pre-
viously.
71
-------
REFERENCES
(1) Ball and Associates, "Surface and Shallow Oil-Impregnated Rocks and
Shallow Oil Fields in the United States", U.S. Bureau of Mines,
Monograph 12 (1965).
(2) "Energy Alternatives—A Comparative Analysis", Prepared by the Science
and Public Policy Program, University of Oklahoma, Norman, Oklahoma
(May, 1975).
(3) "Energy From U.S. and Canadian Tar Sands: Technical, Environmental,
Economic, Legislative, and Policy Aspects", Report Prepared for the
Subcommittee on Energy of the Committee on Science and Astronautics,
U.S. House of Representatives, U.S. Government Printing Office
(December, 1974).
(4) Ritzma, Howard R., Utah Geological and Mineralogical Survey, "Utah's
Oil-Impregnated Sandstone Deposits, A Giant Undeveloped Resource",
Paper Presented to Rocky Mountain Section, American Association of
Petroleum Geologists, Annual Meeting, Salt Lake City, Utah (February
28-March 3, 1973).
(5) Chapin, Hebert S. Jr., et al., Geological Survey of Alabama, "Petro-
liferous Rocks (Mississippian Age) of North Alabama", In Preparation
(September, 1975).
(6) Personal Communications.
(7) Heath, Larman J., et al., "Solvents and Explosives to Recovery Heavy
Oil, Bartlett, Kansas", U.S. Bureau of Mines, Technical Progress
Report No. 60 (September, 1972).
(8) Wells, J. S., and K. H. Anderson, "Heavy Oil in Western Missouri",
Bulletin, American Association of Petroleum Geologists, Vol. 52,
No. 6, (1968) pp 1720-1731.
(9) Searight, Walter V., "Asphaltic Rocks in Western Missouri", Missouri
Geological Survey and Water Resources, Information Circular No. 13
(1957).
(10) Arnold, M. D., and A. Herbert Harvey, University of Missouri, Rolla,
"Evaluation of Thermal Methods for Recovery of Viscous Oils in
Missouri and Kansas", U.S. BM Contract No. G0133100, Rinal Report
(June, 1974).
72
-------
(11) Ritzma, Howard R., Compiler, "Location Map—Oil-Impregnated Rock
Deposits of Utah", Utah Geological and Mineralogical Survey Map
33 (April, 1973).
(12) Campbell, Jack A., "Oil-Impregnated Sandstone Deposits in Utah",
Mining Engineering, Vol. 27, No. 5 (May, 1975).
(13) Glasset, J. M., "Surface Mining of Utah Tar Sands", Paper Presented
at First Rocky Mountain Fuels Symposium, Brigham Young University
(January 31, 1975).
(14) Cupps, Cecil Q., et al., Laramie Energy Research Center, "Field
Experiment of In Situ Oil Recovery From a Utah Tar Sand by Reverse
Combustion", Paper Presented at AICHE Meeting, Los Angeles,
California (November 20, 1975).
(15) Carlson, F. M., "Field Experiment of Underground Reverse Combustion
in a Utah Tar Sand", Paper Presented at the First Rocky Mountain
Fuels Symposium, Brigham Young University (January 31, 1975).
(16) Wood, R. E., and H. R. Ritzma, "Analysis of Oil Extracted From Oil-
Impregnated Sandstone Deposits in Utah", Utah Geological and
Mineralogical Survey, Special Studies 39 (January, 1972).
(17) Gwynn, John Wallace, "Instrumental Analysis of Tars and Their
Correlations in Oil-Impregnated Sandstone Beds", Unitah and Grand
Counties, Utah, Utah Geological and Mineralogical Survey, Special
Studies 37 (October, 1971).
(18) McConville, L. B., "The Athabasca Tar Sands", Mining Engineering,
Vol. 27, No. 1 (January, 1975).
(19) Cameron Engineers, Inc., Synthetic Fuels Data Handbook (1975).
(20) "Mining of Viscous Crude Claimed Viable", Oil and Gas Journal, Vol.
74, No. 1 (January 5, 1976) pp 46-47.
(21) Grimm, Elmore C., and Ronald D. Hill, "Environmental Protection in
Surface Mining of Coal", U.S. EPA-670/2-74-093 (October, 1974).
(22) University of Oklahoma, "Energy Alternatives - A Comparative Analysis",
Report Prepared for the Council on Environmental Quality, Contract No.
EQ 4AC034 (May, 1975).
(23) Moomau, Henry F., et al., Potomac Engineering and Surveying,
"Feasibility Study of a New Surface Mining Method, Longwall
Stripping", U.S. EPA Report 670/2-74-002, Contract No. 68-01-0763
(February, 1974).
73
-------
(24) Roe, K. F., et al., "Shallow Cover Coal Mining and the Environment",
Report Prepared by Kansas Institute for Mineral Resource Research,
University of Kansas for Ozarks Regional Commission, Contract No.
TA 73-9(N) (September 1, 1974).
(25) "Compilation of Air Emission Sources", U.S. EPA, Office of Programs,
Research Triangle Park, Publication No. AP-42 (April, 1973).
(26) ' Personal Communication, Mr. Russel Powell, Imperial Oil of Canada,
Ltd. (January 28, 1976).
(27) Extraction of Energy Fuels Panel, Extraction of Energy Fuels, Prepared
for the U.S. Bureau of Mines, NTIS Report No. QFR30-73 (September,
1972).
(28) Heath, L. J., F. S. Johnson, and J. S. Miller, "Solvents and Explosives
to Recover Heavy Oil", USBM Technical Progress Report No. 60 (September,
1972).
(29) Doscher, T. M., "Technical Problems in In Situ Methods for Recovery
of Bitumen From Tar Sands", 7th World Petroleum Congress, Vol. 3
(1967) pp 625-632.
(30) Mungen, R.,and J. H. Nicholls, "Recovery of Oil From Athabasca Oil
Sands and From Heavy Oil Deposits of Northern Alberta by In Situ
Methods", 9th World Petroleum Congress, Vol. 5 (1975) pp 29-41.
(31) Both, R. C., "Cyclic Steam Project in a Virgin Tar Reservoir", Journal
of Petroleum Technology (May, 1967) pp 585-591.
(32) "New Cold Lake Pilot Onstream", Oil Week (October 13, 1975).
(33) Harmsen, G. J., "Oil Recovery by Hot-Water and Steam Injection",
8th World Petroleum Congress, Vol. 3 (1972).
(34) White, P. C., "Tar Sands and Liquid Fuels From Coal", Reprint of
Presentation at the Oil Daily Forum, New York City, New York (June
10, 1974).
(35) Dietz, D. N., "Wet Underground Combustion: State of the Art",
Journal of Petroleum Technology (May, 1970) pp 605-617.
(36) Utah Tar Sand Test Yields Small Amount of Oil, Oil and Gas Journal
(January 12, 1976) p 26.
(37) Personal Communication, Frank Carlson, ERDA/Laramie Energy Research
Center (January 25, 1976).
(38) Farouq, Ali, S. M., "A Current Appraisal of In Situ Combustion Field
Tests", Journal of Petroleum Technology (April, 1972) pp 477-486.
74
-------
(39) U.S. Environmental Protection Agency, "Draft Development Document for
Effluent Limitations Guidelines and New Source Performance Standards
for the Oil Gas Extraction Point Source Category" (October, 1974).
(40) Personal Communications, U.S. Environmental Protection Agency.
(41) Clark, K. A., "Research Council of Alberta Report 8", Annual Report
1922, Edmonton, Alberta, Canada (1923) pp 42-58.
(42) Clark, K. A., Transactions of the Canadian Institute of Mining and
Metallurgy, Vol. 47 (1944) pp 257-274.
(43) Rammler, Roland W., "The Retorting of Coal, Oil Shale, and Tar Sand
by Means of Circulated Fine Grained Heat Carriers as a Preliminary
Stage in the Production of Crude", Quarterly Journal of Colorado
School of Mines, Vol. 65, No. 4 (October, 1970) pp 141-167.
(44) Ternan, M., B. N. Nandi, and B. I. Parsons, "Hydrocarcking Athabasca
Bitumen in the Presence of Coal: Part I: A Preliminary Study of the
Changes Occurring in the Coal", Canadian Mines Branch Research Report
No. R-276 (October, 1974) pp 1-2.
(45) Nelson, W. L., Petroleum Refinery Engineering, 4th Edition, McGraw-
Hill (1958) p 134.
(46) U.S. Environmental Protection Agency, Supplement No. 1 for Compilation
of Air Pollutant Emission Factors, 2nd Edition (July, 1973).
(47) U.S. Environmental Protection Agency, Compilation of Air Pollutant
Emission Factors, 2nd Edition, AP-42 (July, 1973) pp 9.1-3 to 9.1-5.
(48) Brown and Root, Inc., "Economics of Refinery Wastewater Treatment",
API Publication No. 4199 (August, 1973) pp V-2 and V-9-
(49) Beychok, M. R., Aqueous Wastes From Petroleum and Petrochemical
Plants, John Wiley and Sons (April, 1973).
(50) Federal Register, Vol. 40, No. 98 (May 20, 1975).
(51) U.S. Environmental Protection Agency, "Development Document for
Effluent Limitation Guidelines and New Source Performance for the
Petroleum Refining Point Source Category", EPA 440/l-74-014a (April,
1974) p 104.
(52) Battelle estimate based on contacts with process vendors.
75
-------
APPENDIX A
ILLUSTRATIONS OF MINING METHODS
(Figures A-l to A-6 Reproduced/Modified
from Reference 21. Figure A-7 Reproduced/
Modified from Reference 23)
76
-------
TOP Of RIDGE
^ HIGHWAU -^
CUT 7 I CUT 5 CUT 3 CUT)
—U- "(-<•- -+*— -*
CUT 2
— —*-
CUT 4
— -*•
CUT 6
OUTCROP BAKRIER- — '"^
HOUOW
PROCtDUBt.
I.5CAIP FROM 1OP Of HIC.HWALl 1O OUTCROP BARRIER.
REMOVE AND STOKE (OPiOtL
1 REMOVt ANO DISPOSE OF OVtRBURDEN fROfA CUT i.
3.PICK UP COAL. 1EAVINO AF UASI A IS FOOT UNDISTURBED
OUTCROP BARRIER
4MAKE SUCOLS1VE CUTS AS NUMBERED
S-OV£RBU«DtN IS MOVED IN THE DIRECTION. AS SHOWN BY
ARROWS, tND PLACED IN THE ADJACENT PIT
^.COMPLETE BACKFILL ANO GRADING TO THE APPROXIMATE
ORIGINAL CONTOUR.
RIDGE TOP
-BARRIER
Stripping phase
RIDGE TOP
HOUOW
OMPACTED
ClAY
Backfilling phase
BARRIER
FIGURE A-l. BLOCK CUT METHOD
77
-------
00
PROCEDURE;
t. SCALP FROM POINT A TO POINT B
2..MAKE CUT A C D
5. PLACE SPOIL TKOM A c o IN D E
4. ESTABLISH ROAD AT POINT E ON FILL BENCH
S. SOIID BENCH - POINT C TO f-O
-------
lit STEP (27- EXAMPLE)
PROCEDURE:
1. SCALP FROM TOP OF 2nd CUT HIGH WALL IO TOE OF Fill.
2. REMOVE SPOIL FROM Ut CUT AND PUSH DOWN SLOPE.
3. SPREAD SPOIL AND COMPACT IN LAYERS
UNTIL STORAGE ANGLE ISBEACHED.
4. LEAVE AT LEAST IS' BARBIE*.
I. PICK UP COAL.
TOE
OF FILL
2nd STEP (27 • EXAMPLE)
SECOND CUT AN3 SPOIL
PROCEDURE:
1. REMOVE AND STACK SPOIL FROM 2nd CUT.
2. PICK UP COAL.
3. AUGER IF PERMITTED.
DIVERSION
OUCH
SUP (27° IXAMP1EI
FINAL OKADIKC (ONE AND TWO CUT METHOD)
HIGHWAll
REDUCED SLOPE
IOWIR HALF
SEAM
c
- BARRIER
PROCEDURE:
I. COMPACI SUITABLE SPOIL IN AND ABOVE AUGER HOLES.
2. PUSH STACKED SPOIL AGAINST H1OHWALL.
3. SLOPE BENCH IO SPECIFIED GRADE.
4. AT LEAST 15' OF BARRIER IS LEFT INTACT.
TOE
OF FILL
FIGURE A-3. SLOPE REDUCTION: ONE AND TWO-CUT METHOD
79
-------
l«t STEP (27e EXAMPLE)
—PIT - 50•-*
HtCUT
"-Pit.ioo
I. SCALP FROM TOP OF 2«d CUT HIGHWALL TO TOE Of FltL
2. REMOVE SPOIL FROM Itl CUT AND PUSH OOWNH.OPE.
3. SPREAD SPOIL AND COMPACT EN 3' LIFTS OR LAYERS
UNTIL MAXIMUM DEPTH IS REACHED FOR THAT DCGfftE OF
ORIGINAL GROUND SLOPE.
4. LEAVE AT LEAST 15' BARRIER.
S. PICK UP COAL.
2nd SUP (27° tXAMPlE)
ANGLE Of
REPOSE
PROCEDURE:
1. REMOVE AND STACK SPOIL. FROM 2nd CU1.
2. PICK UP COAL-
3. AUGER IF PERMITTED.
DIVERSION
0IICH
3rd STEP (17" EXAMPLE)
-~- HIGHWAlt
PROCEDURE:
I. COMPACT SUITABLE SfOll IN AND ABOVt AUGflt HOIES
2. PUSH SPOIL fROM Jnd CUT AGAI^SI HIOMWAll.
3. StOPE BiNCH TO SPfCIFIED GRADE.
4. AI IfASI IS' OF ZAKRItR IS LEFT INIACI
5. ROAD ON EOO6 Ot Fill EINCH IS NOT DISTURBED.
ANGlt
OF REPOSE
TOE
OF Fill
FIGURE A-4. PARALLEL FILL METHOD, MODIFIED SLOPE REDUCTION
80
-------
MOUNTAIN TOP
FIRST CUt
HOSSOM
SECOND CUT
MOUNTAIN TOP-
ORIGINAl
GROUND
SlOPt.
ItOSSOM
09
(RUSH DAM
lOURTH CUT
MOUNTAIN TOP,
tARRIER
DIVERSION
DITCH
top after final grading end topsoiling
DIVERSION
DITCH
FIGURE A-5.. MOUNTAIN TOP REMOVAL METHOD
-------
MOUNTAIN TOP
BtINO ([MOVED
I I 9v'LI
L«—CROWNfD Fill BENCH—•"Ls—BtNC
lopsoii—^^p^'^*^,*^t?5i*as*?^^iY—
0 ~JZ?r;jJ^?/*'•''' ' "' ' P' ','"' i, -'"'^ I
c£~Z?; • ''fti!;ti'/i'; •'•'•'•Vi:vV;/.v.vV/.ig;!J?' IAIIRAI
o^r?,'v;y-i:/'',i'-'v'.:iJ''.'.'^'-':''-'^'^:' OKAIN
wfM'rfwfttMtt^&ff'^'
HIGHWAU
ROCK FILLED .{FRENCH DRAIN),
NATURAL DRAIN WAY
15CAIP INTdtf Alt* THAT Will K COVIf ED WITH fill. IIMOVI AND STORC TOfSOfc,
{.CONSTRUCT FIUNCH DSAINS IN IHl HOUOW WATER COUIIIS
S.6UK.D THE F1U IN COMPACTED LAYERS.
IACE OF Fill NO Sttms THAN 3:1.
4.CONSTIOCT «OWNIO TERRACES IVEIY 30 mi.
APPROXIMATELY 20 FEET WIDE.
S-CtNtlt OF COMPUTED FIU BENCH IS CROWNED
fOW'RD THE HIGHWAU, SO THAT WATU
WIU FLOW ONIO fXCAVAHD BENCHIS.
4.BOHO JILT CONItOL SIRUCIURES BtLOW HOLLOW FIU.
FIGURE A-6. HE/D-OF-HOLLOW FILL
82
-------
Hill. MID VAILEY
ISOLATtO ELEVATION
VAWOUS TYPES OF TERRAIN APPLICABLE TO
LONGWALL STRIPPING SYSTEM
/ ELT L'^:^} p—j™ij™^ ^k$&°
BtCr.rll LCD KO /^-,
ORIGJNAL CONlOU't
PLAN VIEW OF LONGWALL STRIPPING SYSTEM
1
SURFACE
CHOSS-SECTIOM VIEW OF LONGWALl STRIPPING
SYSTEM ALOI>'G HifiiiWALL.
SECTION fl-A
TYPICAL CROSS-SECTION VIEW OF
LONGWALL STRIPPING SYSTEM
FIGURE A-7. LONGWALL STRIPPING
83
-------
TECHNICAL REPORT
(Please read Instructions on the reverse
DATA
before completing)
1. REPORT NO.
EPA-600/7-76-035
2.
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
PRODUCTION AND PROCESSING OF U. S. TAR SANDS
An Environmental Assessment
5. REPORT DATE
December 1976 issuing date
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
N. A. Frazier, D. W. Hissong, W. E. Ballantyne,
and E. J. Mezey
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
\
Battelle
Columbus Laboratories
505 King Avenue
Columbus. Ohio 43201
10. PROGRAM ELEMENT NO.
EHE623
11. CONTRACT/GRANT NO.
68-02-1323
12. SPONSORING AGENCY NAME AND ADDRESS
Industrial Environmental Research Laboratory - Cin.,OH
Office of Research and Development
U. S. Environmental Protection Agency
Cincinnati. Ohio 45268
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
EPA/600/12
15. SUPPLEMENTARY NOTES
16. ABSTRACT
Tar sands is a potential source of synthetic fuel for the U- S. If, when, to what
extent and at what rate U. S. tar sands are developed in the future is dependent to
a large extent upon the environmental impact of the producing and processing of tar
sands. Reported here are the results of a preliminary study to assess the potential
primary environmental impacts of production and processing of U. S. tar sands bitumen.
Currently there are two basic ways for producing tar sands—mining and in-situ. Pro-
ducing tar sands by mining methods would be similar to those of mining coal. Solid
waste in the form of spent sand would have to be dealt with, but existing technology
can control it if good environmental practices are followed. Currently there is no
in-situ production technology but it is believed that environmental impacts would be
similar to those of conventional oil field production. Facilities used to upgrade
tar sand oil would pose environmental impacts same as coking and hydrotreating pro-
cesses in an oil refinery. Environmentally, in-situ production of tar sands would
be preferred. From the viewpoint of resource utilization, production by surface
mining methods where economically and technically possible would be preferred.
Technical and ecomomic factors will determine if in-situ methods are an alternative
to surface mining in environmentally sensitive areas.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
COS AT I Field/Group
Tars, Bituminens, Oil Sands, Producing
Wells, Mining, Wastes, In-Situ Combustion,
Emmission, Sandstones, Siltstones, Over-
burden, Refining, Coking, Surface Mining,
Dust, Volatility, Viscosity, Reserves,
Reservoirs
Tar Sands, Synthetic
fuels, Hydrotreating,
Tar Sands Triangle,
Great Canadian Oil Shale,
Ltd, Particulates,
Asphaltic Rocks, Oil
Impregnated.Rocks
8G
81
13B
3. DISTRIBUTION STATEMENT
RELEASE TO PUBLIC
19. SECURITY CLASS (This Report)
UNCLASSIFIED
21. NO. OF PAGES
92
20. SECURITY CLASS (Thispage)
UNCLASSIFIED
22. PRICE
EPA Form 2220-1 (9-73)
84
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