AN ASSESSMENT OF OIL SHALE AND TAR SAND DEVELOPMENT

IN THE STATE OF UTAH

PHASE I

MAY 1980

Prepared by the

Utah Energy Office

in cooperation with

the

Uintah Basin Association of Governments

for

The Department of Energy

Washington, D.C.

UTAH LEGISLATIVE PRINTING OFFICE

PREFACE

This assessment is the result of an interest and commitment by the

State of Utah to both promote development of its vast energy resources

and to manage the impacts associated with such development. As the

development of Utah oil shale and tar sands became more imminent a

specific proposal to study the impacts from this impending development

was made to the Department of Energy. It was noted during the discus­

sions leading to the research contract for this assessment that, "...it

appears that a great deal of information is needed to assure that such

development will proceed in a manner that benefits the citizens of Utah

and the nation." It is in this context that this assessment is being

conducted.

Phase I of this assessment, which is the subject of this document,

is a description of the potential development scenario as revealed

through individual project proposals and as considered likely to actu­

ally occur by 1990 by the Department of Energy in concurrance with the

State of Utah. The scenario developed in Phase I is then to be used as

the starting point for a detailed impact analysis which is the objective

of Phase II of this assessment.

The Utah Energy Office has undertaken the task of compiling all the

information provided by the individual company proposals and the Uintah

Basin Association of Governments into this Phase I document. The work

for Phase I was done by Buzz Hunt, Jeff Burks, and Rod Millar of the

Energy Office Staff with help from Rick Anderson, a research intern.

The Energy Office Staff wishes to thank the many reviewers of an

earlier draft for their many helpful suggestions and comments which

contributed to this Phase I effort. We also wish to acknowledge the

help in providing information and guidance from Chuck Henderson, of the

Uintah Basin Association of Governments, Jim Bunger, the Utah State

Science Advisor, Howard Ritzma, of the Utah Geological and Mineral

Survey, Brent Jones, of the Utah Geological and Mineral Survey, for his

help on the graphics in this document and the individual company project

managers for their cooperation in providing details on their proposals.

Finally we wish to thank Patti Wardle for her excellent typing and

retyping of the manuscript and her good humor when confronted with our

constant revisions which followed each retyping.

- i i i -

TABLE OF CONTENTS

Page

Preface i i

List of Tables v

List of Figures vi

Executive Summary vii

I. INTRODUCTION 1

A. Purpose and Organization of Report 1

B. Oil Shale Resources in Utah 3

C. Tar Sand Resources in Utah 6

II. CURRENT STATUS OF OIL SHALE AND TAR SAND DEVELOPMENT IN

UTAH 10

A. Current Status of Oil Shale Development 10

B. Current Status of Tar Sand Development 12

C. Constraints and Problems 15

D. Production Scenarios 23

III. OIL SHALE PROJECTS IN UTAH 28

A. White River Shale Project 28

B. Paraho Project 39

C. Tosco Sand Wash Project 45

D. Geokinetics Inc. In-situ Project 54

IV. TAR SAND PROJECTS IN UTAH 62

A. Sohio Natural Resources Company Project 62

B. Great National Corporation Project 70

References 78

LIST OF TABLES

Table Page

1-1 Utah Tar Sands Characteristics 9

II-l Production Scenarios 26

II-2 Mining Scenarios 27

III-l White River Shale Project 30

III-2 White River Dam 35

III-3 Paraho Oil Shale Project 41

III-4 Tosco Sand Wash Project 47

III-5 Geokinetics Oil Shale Project 55

IV-1 Sohio Tar Sand Project 63

IV-2 Great National Tar Sand Project 73

-v-

LIST OF FIGURES

Figure Page

1-1 Oil Shale Areas Uinta Basin 5

1-2 Tar Sand Deposits 8

III-l Active Oil Shale Operations 61

IV-1 Asphalt Ridge Tar Sand Deposit 65

IV-2 Sunnyside Tar Sand Deposit 74

-vi-

EXECUTIVE SUMMARY

I. Introduction

A. Purpose and Organization of Report

The development of snythetic fuels in the State of Utah is a topic

of increasing national concern and public debate. As these discussions

continue, a great deal of information is needed to assure that the

development of snythetic fuels will proceed in a manner that benefits

the citizens of Utah and the nation. This report represents the first

of a two-phase assessment of current oil shale and tar sand development

within the state and is intended to provide policy-makers with up to

date information on the status of each proposed project. It is hoped

that this information will prove valuable to those who must reach deci­

sions affecting the ultimate development of Utah's vast oil shale and

tar sand resources.

Baseline data assembled in this report was gathered from existing

development plans, environmental impact reports, resource development

status reports, and discussions with project participants, academic

researchers, and state and local officials. The format used in organ­

izing these materials consisted of identifying those projects in Utah

which may contribute to the production of synthetic fuels by 1990, and

to specify for each of those projects:

(1) the resource to be used,

(2) technologies to be used,

(3) Potential markets and transportation possibilities for the

product,

(4) water requirements of the project, including source, storage

and transportation,

(5) air quality impacts of the project,

(6) socioeconomic impacts,

(7) disposal program for wastes removed for mine development or

underground retorts,

(8) construction and production schedules for the project, and

(9) project sponsors and/or participants.

The results of this assessment are to be published in two separate

reports. Phase I of the assessment is the subject of this report and

should not be considered comprehensive, but rather an outline of the

major factors to be considered in the development of the subject re­

sources. Since the current status of synthetic fuels projects in Utah

cover all stages of development (from conceptual to pilot plant), much

of this information is tentative and for some recent industry activity,

information is not yet available. It should also be recognized that

much of the information used was provided by the firms themselves, and

thus, reflects each firm's attitude toward its own development.

Phase II of the assessment will further elaborate on those projects

identified and include new information on additional projects which are

now getting underway. Phase II will emphasize the impacts of develop­

ment and the likely problems and constraints to production. Cumulative

impacts will also be discussed in an attempt to assess the entire oil

shale and tar sand industry in Utah from the state and local perspec­

tives. Specifically, Phase II will:

(1) identify major federal decisions needed for each project (or

for general synfuel development),

(2) identify unique environmental problems for each project (en­

dangered species, etc.),

-viii-

(3) show the general relationship of oil shale projects and tar

sand projects to other energy development in the Uinta Basin,

(4) show the relationship of oil shale and tar sand development to

major transportation development,

(5) identify supporting state and federal projects or activities,

e.g., water projects, etc., and

(6) identify the specific organizations involved and coordination

required for integration of oil shale and tar sand develop­

ments with related projects.

The remainder of Chapter I briefly reviews the magnitude of oil

shale and tar sand resources within the state. A summary of the current

status of industry development is discussed in Chapter II. Chapter III

provides details of proposed oil shale projects and Chapter IV provides

details of tar sand projects.

B. Oil Shale Resources in Utah

The Uinta Basin of northeastern Utah contains an estimated 321

billion barrels of identified in-place oil (from oil shale of 15 gallons

per ton or more). Of this in-place oil it is estimated that 80 percent

of the 25 gallons per ton or more, resource can be extracted with known

technology. This amounts to approximately 50 billion barrels of recov­

erable shale oil and represents nearly twice the proven U.S. petroleum

reserves and more than a seven year U.S. oil supply at current consump­

tion rates.

C. Tar Sand Resources in Utah

In the United States, deposits of tar sand have been found in 24

states. The largest deposits and those regarded as potentially con-

-ix-

taining commercially exploitable quantities of oil are found in only six

states: Alabama, California, Kentucky, New Mexico, Texas and Utah.

Utah contains approximately 93 percent of the U.S. total resource base.

These Utah deposits (51 are known) are estimated to contain 25.1

billion barrels of oil which is roughly equivalent to the total U.S.

domestic proven reserves of petroleum.

II.. Current Status of Oil Shale and Tar Sand Development in Utah

A. Current Status of Oil Shale Development

Processing oil shale involves heating (retorting) crushed shale to

a temperature of approximately 900 degrees Fahrenheit at which point the

organic material in the oil shale breaks down and forms a vapor from

which a crude oil (kerogen) is then condensed.

Retorting processes fall into two broad categories, above-ground

and in-situ. In above-ground recovery, oil shale is mined, crushed and

fed into a surface retort. In-situ recovery of oil shale involves

subjecting an in-place oil shale resource to heat injected into the pay

zone driving the volatilized kerogen out to a recovery well.

Development work on these two categories of oil shale processing is

continuing and it is expected that both types of recovery will be uti­

lized in Utah. In order to stimulate oil shale development activities

the DOE has undertaken a commercialization program to provide front end

monies to assist in the design and construction of a commercial size oil

shale retort module. In addition Public Law 96-126 authorized DOE to

allocate $2.2 billion to stimulate and promote the production of syn­

thetic fuels from projects which are within one year of commencement of

construction.

-x-

B. Current Status of Tar Sand Development

In Utah, tar sands have been used as a source of asphalt paving

material for many years. Recently, interest in tar sands development

has been renewed. Current development work has focused primarily on

three extraction processes: 1) solvent, 2) thermal and 3) hot water.

These three processes can be utilized in either above-ground or in-situ

recovery operations.

The above-ground recovery technology is currently more advanced

than the in-situ processes. However the fact remains that 85 percent of

the tar sand resource is too deeply buried to be accessible by surface

mining techniques and deep underground mining of tar sands may not be

economically feasible. Therefore, if full potential of this resource is

to be realized there is a pressing need to develop in-situ technologies.

C. Constraints and Problems Associated with Commercial Develop­

ment of Utah Oil Shale and Tar Sand Deposits

Currently there exists an array of economic, technical, environ­

mental, and leasing constraints and problems that must be fully addres­

sed before development of these resources can be undertaken. These are:

1. Economic

There are economic uncertainties about the future cost of oil pro­

duced from oil shale and tar sands which are due to a lack of well

defined technologies for application on a commercial scale, changing

government regulations and the general inflationary trend among input

costs. Also there are uncertainties due to unstable oil supply condi­

tions which affect the future price of world oil. Compounding these

problems are the extremely large capital outlays required for a commer­

cial scale operation.

XI

2. Legal and Land Ownership

The legal issues surrounding oil shale development center on ques­

tions of ownership claims while the problem of tar sand issues are defi­

nitional in character.

There currently exist two major legal cases with regard to Utah oil

shale resources. The first case concerns the contested ownership of

43,000 acres of unpatented mining claims filed on oil shale land under

the Mining Law of 1872. The second major legal case with regard to oil

shale concerns the State of Utah's claim to 157,000 acres of oil shale

land in Uintah County. These legal issues should be resolved in the

courts soon.

The legal constraints to tar sands development involve complex and

obtruse legal arguments over the difference between oil, heavy oil, and

oil in a deposit of oil sand. These issues have prevented the leasing

of tar sands on federal lands. This problem could be resolved by the

passage of legislation presently introduced in the Congress.

3. Technical

There exist several technological problems that must be solved to

have a viable synthetic fuel industry. These problems include an in­

adequate resource assessment, the need for more research and development

and the need for data to scale up recovery processes for a commercial

scale operation.

4. Mining and Construction

Of the many factors that could impede the rate of development or

the eventual size of a synthetic fuels industry in Utah, perhaps the

single most limiting constraint is the construction and mining indus­

try's ability and capacity to allocate limited resources amongst a

-xii-

number of competing demands. A number of large scale energy, water, and

defense projects ranging from the 3,000 MWe Intermountain Power Project,

to the MX missile defense system are currently planned for siting in

Utah. Simultaneous construction with the oil shale and tar sand pro­

jects (which could require 1,100 to 1,750 additional underground miners)

will place severe stress on the construction industry capacity to absorb

this growth.

5. Regulatory

Any proposed development of synthetic fuel processes faces an array

of continuing changing regulations and permit requirements. Consistency

in regulatory policy and simplification of the permitting process could

enhance a more stable environment from which development could proceed.

6. Environmental

Environmental impacts from oil shale and tar sand development range

from air and water quality impacts to land use conflicts associated with

national parks and recreation areas. Regulations which have not been

promulgated yet will also have an unknown impact on development scenar­

ios.

7. Water

Synthetic fuel development will create additonal demand on the

water resources of Utah. It is believed that the state faces no serious

deficits of water for energy development, however, there are several

major issues which center around the question of priority determination,

i.e., how will the increased demand for water affect the current system

of water allocation? Changing needs and requirements could make the

acquisition of existing water rights by energy developers more diffi­

cult.

-xiii-

0. Production Scenarios

Two possible development scenarios have been compiled and appear in

table II-l. These scenarios are based on 00€ projections of expected

industry activity and the industry proposals. The DOE projections are

more conservative than the industry proposals, but they are based on

production by 1990 while the industry proposals are not confined to that

time period.

The scenarios consider four oil shale projects; three above-ground

recovery projects and one in-situ project and two above-ground tar sand

projects. The low projections are: 113,000 BPD for oil shale and

13,000 BP0 for tar sands for a total of 126,000 BPD by 1990. The high

projections are: 177,000 BP0 for oil shale and 50,000 BP0 for tar sands

which is a total of 227,000 BPD by 1990.

In order to reach those production goals it will be necessary to

mine 212,400 TPD for the low proposal and 468,300 TPD for the high

proposal. On a yearly basis these numbers are: 70,097,000 TPY for the

low scenario and 154,470,000 TPY for the high case. The low case repre­

sents nearly six times the entire 1979 Utah coal production and the high

case is over thirteen times the entire 1979 Utah coal production.

III. Oil Shale Projects in Utah

There are four oil shale project proposals for Utah. These are:

1) The White River Shale Project, 2) The Paraho Project, 3) The Tosco

Sand Wash Project and 4) The Geokinetics Inc., In-situ project. The

first three are above-ground recovery projects and the fourth is a modi­

fied in-situ project. Tables III-l through II1-5 summarize the project

proposals for these four oil shale projects.

-xiv-

IV. Tar Sand Projects in Utah

There are currently only two proposals to construct a tar sands

industry in Utah. The Sohio Natural Resources Company Project to be

located on Asphalt Ridge and The Great National Corporation Project to

be located on the Sunnyside Tar Sand Deposit. Both of these proposals

are to be above-ground recovery projects. Tables IV-1 and IV-2 sum­

marize the proposal data for these projects.

-xv-

J

J

AN ASSESSMENT OF OIL SHALE AND TAR SAND DEVELOPMENT

IN THE STATE OF UTAH

PHASE I

I. INTRODUCTION

A. Purpose and Organization of Report

The development of synthetic fuels in the State of Utah is a topic

of increasing national concern and public debate. As these discussions

continue, a great deal of information is needed to assure that the de­

velopment of synthetic fuels will proceed in a manner that benefits the

citizens of Utah and the nation. This report represents the first of a

two-phase assessment of current oil shale and tar sand development

within the state and is intended to provide policy-makers with up to

date information on the status of each proposed project. It is hoped

that this information will prove valuable to those who must reach deci­

sions affecting the ultimate development of Utah's vast oil shale and

tar sand resources.

Baseline data assembled in this report was gathered from existing

development plans, environmental impact reports, resource development

status reports, and discussions with project participants, academic re­

searchers, and state and local officials. The format used in organizing

these materials consisted of identifying those projects in Utah which

may contribute to the production of synthetic fuels by 1990, and to

specify for each of those projects:

(1) the resource to be used,

(2) technologies to be used,

(3) potential markets and transportation possibilities for the

product,

(4) water requirements of the project, including source, storage

and transportation,

(5) air quality impacts of the project,

(6) socioeconomic impacts,

(7) disposal program for wastes removed for mine development or

underground retorts,

(8) construction and production schedules for the project, and

(9) project sponsors and/or participants.

The results of this assessment are to be published in two separate

reports. Phase I of the assessment is the subject of this report and

should not be considered comprehensive, but rather an outline of the

major factors to be considered in the development of the subject re­

sources. Since the current status of synthetic fuels projects in Utah

cover all stages of development (from conceptual to pilot plant), much

of this information is tentative and for some recent industry activity,

information is not yet available. It should also be recognized that

much of the information used was provided by the firms themselves, and

thus, reflects each firm's attitude toward its own development. Phase

II of the assessment will further elaborate on those projects identified

and include new information on additional projects which are now getting

underway. Phase II will emphasize the impacts of development and the

likely problems and constraints to production. Cumulative impacts will

also be discussed in an attempt to assess the entire oil shale and tar

sand industry in Utah from the state and local perspectives. Specifi­

cally, Phase II will:

-2-

(1) identify major federal decisions needed for each project (or

for general synfuel development),

(2) identify unique environmental problems for each project (en­

dangered species, etc.),

(3) show the general relationship of oil shale projects and tar

sand projects to other energy development in the Uinta Basin,

(4) show the relationship of oil shale and tar sand development to

major transportation development,

(5) identify supporting state and federal projects or activities,

e.g., water projects, etc., and

(6) identify the specific organizations involved and coordination

required for integration of oil shale and tar sand develop­

ments with related projects.

The remainder of this introduction will briefly review the magni­

tude of oil shale and tar sand resources within the state. A summary of

the current status of industry development is discussed in Chapter II.

Chapter III provides details of proposed oil shale projects and Chap­

ter IV provides details of tar sand projects.

B. Oil Shale Resources in Utah

Oil shale is neither oil nor shale, but rather, a fine-grained

sedimentary rock containing organic matter which yields substantial

quantities of oil upon pyrolysis (chemical change caused by heat). Oil

shale deposits occur throughout the world, but those in the United

States are among the highest grade. The Tertiary age (eocene) deposits

of the Green River formation in Colorado, Utah and Wyoming account for

an estimated 75 percent of the total U.S. resource and 90 percent of the

total recoverable U.S. resource.

-3-

Utah's Uinta Basin contains an estimated 321 billion barrels of

identified in-place shale oil (from oil shales of 15 gallons per ton or 2

more). Several estimates exist on the magnitude of the "potentially

recoverable" resource base, but it is conservatively estimated that 80

percent of the "25 gallons per ton or more" resource can be extracted

3 with known technology. Thus, from the resource base identified by "25

gallons per ton or more," the Uinta Basin contains an estimated 50

billion barrels of recoverable shale oil. This amount represents nearly

twice the amount of proven U.S. petroleum reserves and more than a seven

year U.S. oil supply at current consumption rates.

Oil shale resources occur on 11 million acres of land in the three-

state Green River formation oil shale region, of which 4.9 million acres

occur in northeastern Utah (see figure 1-1). Approximately 78 percent

of this land is federally owned and is administered by the U.S. Depart­

ment of Interior. This federal land contains 79 percent of the total

in-place resource in the state.

There are legal proceedings currently pending which cast doubt on

the title to Utah oil shale lands. The most significant case at present

concerns the ownership of some 157,000 acres of oil shale land in Utah;

an area which includes federal prototype lease tracts U-a and U-b. The

State of Utah has sued the Department of Interior for title to these

lands, completing about 65 percent of the state's entitlement to lands

under statehood enabling legislation. Federal courts at the district

and appellate levels have ruled in favor of Utah, but the Department of

Justice has appealed the case to the U.S. Supreme Court and a final

decision is not expected until June 1980.

-4-

Figure 1-1

STATE OF UTAH

BEAVER

-J HACHURES ENCLO JTAJ UNDERLAIN BY 0

m ^ O F ALL GRADES

WATHITW SHADED AREA CONTAINS SHALE OF 25 GALLON PER TON GRADE 30 FEET OR MORE THICK.

St George

0 Kanab

1 U - W 113- W.

Utah Geological and Mineral Survey

ARIZONA

OIL SHALE AREAS UINTA BASIN, NORTHEAST UTAH

- 5 - File no. 1363-A

C. Tar Sand Resources in Utah

Tar sand, oil sand, bituminous bearing rock, oil impregnated rock

and bituminous sand are terms used interchangeably in describing hydro-

5

carbon bearing deposits. These are distinguished from more convention­

al oil and gas reservoirs principally by the high viscosity of the hy­

drocarbon which is not recoverable in its natural state through current

oil production techniques.

The most common terminology used to describe this resource is "tar

sand," however, this term is somewhat of a misnomer. The heavy oil

substance contained in these deposits is more accurately called bitumen,

a dense viscous substance exhibiting chemical characteristics similar to

petroleum and other liquid hydrocarbons found in close proximity to

these deposits. In addition, the material containing the bitumen is not

always sand or sandstone; limestone, siltstone, and oolite mud deposits

have also been found to contain these heavy oil deposits. Unlike oil

shale which is homogeneous over large areal extents, tar sand deposits

are highly heterogeneous, consisting of many separate occurrences char­

acterized by noncontiguous beds and variations in point-to-point rich­

ness. Despite the inexactness of the term "tar sand" as it refers to

domestic deposits, the term is firmly enough entrenched in the technical

and industrial literature as well as legislative documents that it will

also be used for the purposes of this assessment.

Tar sand deposits are reported on every continent except Antarcti­

ca. The largest and best known are the Athabasca deposits in

Alberta, Canada, (1,100 billion barrels) and the Orinoco Tar Belt in c

Venezuela (2,000 billion barrels). In the United States, deposits of

-6-

tar sand have been noted in 24 states. The largest deposits and those

regarded as potentially containing commercially exploitable quantities

of oil are found in only six states: Alabama, California, Kentucky,

New Mexico, Texas and Utah. Utah contains approximately 93 percent of

the U.S. total resource base.

Utah contains 51 known tar sand deposits grouped for the most part

within and around the Tertiary age formations of the Uinta Basin in

northeastern Utah and the older Permian and Triassic age formations of

central southeastern Utah. At least five of the deposits can be classi­

fied as "giant" petroleum fields having more than 500 million barrels of

oil (bitumen) in-place. Four other deposits are considered to be "very

large" petroleum fields (100 to 500 million barrels in-place) and 15

others are rated as "large" fields (10 to 100 million barrels of in-o

place resource). Locations of Utah's tar sand deposits are shown in

figure 1-2.

Combined, Utah tar sand deposits are estimated to contain 25.1 bil-g

lion barrels of oil. Of this total, 10.8 billion barrels are in the

Uinta Basin and 14.3 billion in the central southeast part of the state.

This amount is roughly equivalent to the total U.S. domestic proven

reserves of petroleum. The size and resource characteristics of the

major Utah tar sand deposits are given in table 1-1.

Studies of the chemical and physcial characteristics of Utah tar

sand bitumen show that, as a group, central southeast bitumens are

similar to Athabasca bitumen in terms of the high sulfur content and

lower nitrogen and hydrogen content. Comparatively, the Uinta Basin

bitumens (non-marine origin) are higher in nitrogen and hydrogen con­

tent, higher in viscosity, but lower in sulfur content.

-7-

Utah Geological and Mineral Survey Department of Natural Resources

114° W

42° N. n r w IDAHO 112° W.

~'\ CACHE BEAR] j RICH , \ LAKE" I

Figure 1-2

STATE OF UTAH

41° N 41° N

40° N 40° N

39° N

3B° N

V N

39" N

W N

114" W 113° W. 112' W

\ Or ARIZONA

37" N

110° W

TAR SAND DEPOSITS

Utah Geological and Mineral Survey Department of Natural Resources

V o (DOTTED AREA SHOWS EXTENSION

INTO SUBSURFACE)

Table I-l

UTAH TAR SANDS CHARACTERISTICS

Name of Deposit

Asphalt Ridge

Sunnyside

Tar Sand Triangle

P.R. Spring

Hill Creek

Circle Cliffs i

Size of Oil Reserve

106 Bbls.

1,150

3,500-4,000

12,500-16,000

4,000-4,500

1,160

1,300

Areal Extent Sq. Mi.

20-25

35-90

200-230

240-270

115-125

27.7

No. Pay Zones

2-5

1-12

1

1-13

6-13

1-3

Gross Thickness of Deposits (feet)

10-135

15-550

5-300

10-102

53-65

5-310

Gal/Ton

9.5-27

NA

4.9-13.7

.2-30.5

1.0-21.2

NA

Source: UGMS

II. CURRENT STATUS OF OIL SHALE AND TAR SAND DEVELOPMENT IN UTAH

A. Current Status of Oil Shale Development

Even though oil shale as a source of petroleum has been recognized

in this country since the early 1920's, producing oil from oil shale at

an attractive rate of return and a price that is competitive with con­

ventional petroleum sources has proved elusive for more than fifty

years. Awaiting the time when projections of diminishing supplies of

conventional crude oil and increases in price would provide oil shale

with a more competitive posture, oil shale has continued to be a subject

of intense interest, research, and speculation by potential developers

and government officials.

Speculation and interest on the part of private firms and govern­

ment entities has led to the development and testing of many different

processes for producing oil from oil shale. Processing oil shale in­

volves heating (retorting) crushed shale to a temperature of approxi­

mately 900 degrees Fahrenheit at which point the organic material in the

oil shale breaks down and forms a vapor from which a crude oil (kerogen)

is then condensed.

Retorting processes fall into two broad categories, above-ground

and in-situ. In above-ground recovery, oil shale is mined, crushed and

fed into a surface retort. There it is heated, either by gas combustion

or indirectly, and kerogen is extracted. In-situ recovery of oil shale

involves subjecting an in-place oil shale resource to heat injected into

the pay zone. The heat breaks down the organic material in the shale

producing oil vapors which flow through the rock to a recovery well.

Much work has been done on the development of above-ground oil

shale retorting processes and a number of processes have been demon­

strated on a pilot plant scale. However, oil shale technologies have

-10-

not been proven viable on a commercial scale. The scale-up to

full-sized, above-ground, commercial retorts will require modules ten to

fifty times the size of existing pilot plant prototypes. Scaling up

will entail significant economic risks as well as requiring major tech­

nical modifications and adjustments.

Similarily, development of in-situ technology remains in a relative

infancy exhibiting some of the same uncertainties that characterize the

above-ground technologies. In-situ processes involve recovery of the

shale oil resource in place without the need for mining. One firm,

Geokinetics Inc. is currently developing in-situ technologies suitable

for exploiting Utah's near surface oil shale resource. While still

classifying their work as research and development, Geokinetics is the

only project in Utah to have actually produced shale oil in any signifi­

cant amounts.

Recently, in an attempt to remove the economic and technical un­

certainties and promote the commercial production of synthetic fuels,

the Department of Energy (DOE) has undertaken a two-phased commerciali­

zation program. In Phase I, DOE will assign contracts of $5 million

each to three firms, Tosco, Paraho and Superior, for the engineering and

design of a commercial size oil shale retort module. Design and engi­

neering is to be accomplished within 18 months at which time DOE will

review and select designs for awarding $140 million in grants for con­

struction and operation. In addition, Public Law 96-126 authorized DOE

to allocate $2.2 billion to stimulate and promote the production of

synthetic fuels from projects which are within one year of commencement

of construction. The funding is to be allocated as follows:

-11-

(1) $1.5 billion - in price supports/purchase agreements,

(2) $100 million - in project feasibility studies,

(3) $100 million - in support of commercial scale production

facilities, and

(4) $500 million - in reserve for loan guarantees.

B. Current Status of Tar Sand Development

In Utah, tar sand deposits have been used as a source of asphalt

paving material for a good many years. As early as 1892, tar sand was

being mined from the Sunnyside deposit in Carbon County and transported

12 to Salt Lake City where it was used as paving material. For the past

35 years the Uintah County Roads Department has been mining tar sand for

paving and patching from a 10 acre asphalt pit located on the Asphalt

Ridge deposit near Vernal, Utah.

Recently, Utah tar sands have attracted a sustained interest in

their development as a potential alternative crude oil source. Two

different approaches for recovering bitumen from tar sands are currently

under development, above-ground and in-situ recovery processes.

Technologies for above-ground recovery of bitumen from Utah tar

sands have primarily focused on three processes: 1) solvent, 2) thermal

and 3) hot water.

Under the direction of Dr. Alex Oblad, the University of Utah tar

sands research efforts have concentrated on developing both thermal and

hot water extraction technologies. This effort has had as its objective

the development of technology for recovery of Utah tar sands by mining

and surface processing. This research has determined that a modified

hot-water process can be designed to allow efficient recovery of bitumen

from Utah tar sands. Utah tar sands are predominantly "oil wet"; a

-12-

characteristic originally thought to exclude the hot-water process as a

functional method of recovery for Utah bitumens. Recovered bitumen from

Uinta Basin deposits can be used directly as a premium grade paving

asphalt, or converted by thermal or catalytic means to a synthetic crude

13 oil. Using a thermal recovery process, bitumen can be recovered

directly through retorting in a fluidized bed. The yield from this

process is a more refined crude oil than that from the hot-water pro­

cess. Currently, the Great National Corporation proposes to utilize a

hybrid of these technologies in a pilot plant targeted for the Sunnyside

deposit in Carbon County, Utah.

Sohio Natural Resources Company has developed a process very simi­

lar to the hot-water extraction process. Sohio refers to their process

as a "continuous counter current solvent assisted extraction process".

This technology has demonstrated favorable results which warrant further

laboratory development work for the purpose of expanding into a pilot

plant demonstration program. The Asphalt Ridge deposit in Uintah County

is targeted for this effort.

In-situ recovery of tar sands involves the application of energy to

the tar sand reservoir to heat and mobilize the bitumen. Various in-

situ technologies have the objective of establishing a communication

path between the production well(s) and the tar sand reservoir, thereby

allowing the mobilized bitumen to flow and be pumped to the surface.

At reservoir temperature the bitumen is virtually immobile. As

energy is applied to the reservoir and the temperature raised, the vis­

cosity of the bitumen drops. At a temperature of approximately 300

degrees Fahrenheit the bitumen is fluid enough to flow through the pore

space.

-13-

The Laramie Energy Technology Center (LETC) has completed two ex­

periments on the Asphalt Ridge deposit utilizing an in-situ technique.

The most recent experiment used a reverse burn fireflood method followed

by a forward combustion stage. LETC is also planning to conduct an

in-situ recovery test through steam stimulation. Laboratory information

is being collected and a field project planned for the near future.

Santa Fe Energy Company has proposed a forward combustion in-situ

pilot project for the Tar Sand Triangle deposit in Wayne County. This

pilot project is scheduled to commence near the end of 1980 or in 1981

pending an ammendment of the Mineral Leasing Act of 1920 providing for a

15 general hydrocarbon lease on federal lands.

At the present time there is no in-situ technology that has proven

viable on a commercial scale. Even though all of the leading in-situ

processes are based on technological concepts originally developed for

enhanced recovery in conventional oil fields, a multitude of technical

problems still need to be resolved if in-situ production is to become a

viable economic venture.

While proposals have been slow in developing there is a consider­

able amount of interest and activity being channeled into research and

development for recovery of oil from Utah tar sands. Yet, despite the

efforts of current research activities the fact remains that recovery

processes have not been developed to the point where they are ready for

commercial application. Uncertainties still remain and continue to

retard resource development.

Although above-ground recovery technology is currently more ad­

vanced, the fact remains that 85 percent of the tar sand resource is too

deeply buried to be accessible by established surface mining tech-

-14-

niques. Therefore, if full potential of this resource is to be real­

ized there is a pressing need to develop in-situ technologies.

C. Constraints and Problems Associated with Commercial Develop­

ment of Utah Oil Shale and Tar Sand Deposits

Full scale commercial development of oil shale and tar sand de­

posits in Utah is not without complications. Currently, there exists an

array of economic, technical, environmental, and leasing constraints and

problems that must be fully addressed before development of these re­

sources can be undertaken. Input on these matters must come from all

parties involved, i.e., the government sector (federal, state, local),

industry, and other parties at interest. The following is an introduc­

tion to the most important constraints and problems.

1. Economic

Recently, the economic feasibility of oil shale and tar sand devel­

opment has become more attractive. Increases in the ceiling price

charged by OPEC nations coupled with price decontrol of domestic crude

oil have combined to make oil produced from oil shale and tar sand

appear more competitive with conventional liquid hydrocarbons. Yet,

several major economic problems remain unresolved.

The development of commercial scale operations for the mining and

processing of oil shale and tar sand is currently surrounded by economic

uncertainty. The source of this uncertainty is twofold: 1) uncertain­

ties about the future cost of oil refined from oil shale and tar sand

and 2) uncertainty with regard to the future price of world oil.

Uncertainties of future costs are due to a lack of well-defined technol­

ogies for application on a commercial scale basis, changing government

regulations, and the general inflationary trend among input costs.

-15-

Uncertainty in terms of the future price of world oil is attributable to

unstable supply conditions.

Compounding the problem of economic uncertainty is the extremely

large capital outlays which are required for a commercial scale plant.

Given the uncertainty of the economic environment and the corresponding

risk inherent within any development proposal, most firms will not be

inclined to invest massive capital outlays without some form of govern­

ment assistance. If commercial development is to proceed, the federal

government must help cover the inherent high risk associated with these

commercial ventures.

As noted by Utah Governor Scott M. Matheson in testimony before the

Mines and Mining Subcommittee of the U.S. House of Representatives,

Congress has acted strongly to resolve the historical economic uncer­

tainties that have continually plagued synthetic fuel development.

This action has taken the form of a combination of purchase agreements,

price guarantees, loan guarantees, and loans in the proposed Energy

Security Corporation legislation and insurance against the unlikely pos­

sibility of oil price deflation provided in the Windfall Profits Tax Act

of 1980.

2. Legal and Land Ownership

Ownership patterns of the resources and the attendant legal issues

represent significant impediments to the development of a commercial oil

shale and tar sand processing industry. The legal issues involved,

however, differ between oil shale and tar sand resources. The legal

issues surrounding oil shale center on questions of ownership claims

while the problems of tar sand issues are definitional in character.

-16-

There currently exist two major legal cases with regard to Utah oil

shale resources. The first case concerns the contested ownership of

43,000 acres of unpatented mining claims filed on oil shale land under

the Mining Law of 1872. Until 1920, oil shale was considered a locat-

able mineral and, therefore, claims were based on simply demonstrating

18 the presence of an oil shale deposit. However, the Mineral Leasing

Act of 1920 changed the law by making oil shale a leasable mineral.

Due to this change in the law, uncertainty has arisen over the

legality of competing claims. Holders of the pre-1920 claims have been

involved with the Department of Interior over the validity of their

claims during the last 50 years. The continued question of the legiti­

macy of these existing claims has resulted in an injunction suspending

enforcement of lease terms on two federal oil shale tracts in Utah (U-a

and U-b). Thus, development on these tracts has been postponed indefi­

nitely.

The second major legal case with regard to oil shale concerns the

State of Utah's claim to 157,000 acres of oil shale land in Uintah

County. Under the terms of the Statehood Enabling Act of 1894, the

State of Utah was to receive title to four sections of land in each

township. According to the legislation, the sections to be received by

the state were sections 2, 16, 32, and 36. However, in 1894 much of the

state was unsurveyed, thus, the legal transfer of ownership from federal

to state title was never transacted. In the course of time, many of the

sections of land the state was entitled to receive have become included

in homesteads, national parks, recreation areas, reclamation with­

drawals, military and Indian reservations, etc. The State of Utah has,

therefore, selected the oil shale land in lieu of the orginal sections.

-17-

This decision on the part of the state has been challenged by the feder­

al government. Lower court rulings in favor of Utah have been appealed

to the Supreme Court. A decision by the court on the competing claims

should allow for a more orderly development process on the lands in

question.

Legal constraints also exist with regard to the development of a

commercial tar sand processing industry. Almost 90 percent of the po­

tential tar sand leases in Utah are owned and managed by the Department

19 of Interior through the Bureau of Land Management. Currently, there

are no leasing procedures for tar sand on federally managed lands.

Involved in delaying such leasing procedures are complex and ob-

truse legal arguments over the difference between oil, heavy oil, and

oil in a deposit of oil sand. Mining versus in-situ methods of ex­

traction and the methods and degrees of extraction and stimulation

needed for recovery are issues which must also be resolved.

Construction of a commercial scale tar sand processing plant that

is economically viable requires a substantial amount of recoverable

resources. In the absence of federal procedures for leasing of tar

sands, Utah has established regulations for leasing tar sands on state

lands under a single oil, gas, and hydrocarbon lease. However, state

leases alone are in most cases not sufficient to provide the required

resource volume for a commercial tar sand processing industry. Passage

by Congress of legislation which would establish a uniform federal

leasing program would be a first step in opening up federal lands for

tar sand development.

-18-

3. Technical

There exist several technological problems that must be solved to

have a viable synthetic fuel industry. These problems include an inade­

quate resource assessment, the need for more research and development,

and data for commercializing recovery processes.

The problem of resource assessment is mainly concerned with tar

sands. Adequate resource characterization that would allow for intelli­

gent economic evaluation of a property for leasing purposes has been

20 conducted on less than 10 percent of Utah tar sands.

The identification of appropriate technologies for mining and pro­

cessing purposes is also of extreme importance. This identification can

best be done through an orderly research and development program, in­

volving interaction between industry and appropriate public agencies.

Large monetary outlays will most likely be necessary for research and

development. Federal funding may be required as an incentive to under­

take such research.

Uncertainties still surround the scale-up of oil shale processes.

The largest pilot plant surface retort in the U.S. has a capacity of

21 about 1,200 tons of oil shale per day. A commercial module would

probably require a unit some six to 10 times larger. Thus, commer­

cial-sized facilities must still be tested.

4. Mining and Construction

Of the many factors that could impede the rate of development or

eventual size of a synthetic fuels industry in Utah, perhaps the single

most limiting constraint is the construction and mining industry's

ability and capacity to allocate limited resources amongst a number of

competing demands.

-19-

Utah is on the eve of a decade of explosive growth. A number of

large scale energy, water, and defense projects ranging from 3,000 Mwe

Intermountain Power Project to the MX missle defense system are current­

ly planned for siting in Utah. Simultaneous construction of these

projects and a synthetic fuels industry will place severe stress on the

Utah construction industry capacity to absorb this growth. This threat­

ens to create serious bottle-necks in the supply of skilled construction

labor, materials and equipment. Accordingly, widespread shortages could

occur resulting in escalating costs of construction and significant

delays in construction timetables.

In addition to potential shortages in the construction industry,

the mining industry could also be faced with manpower shortages. Three

of the four oil shale projects in Utah anticipate utilizing a conven­

tional room-and-pillar mining technique as is used in underground coal

mining. These operations would require mine development from 158,800

TPD to 261,900 TPD to support a surface retorting shale oil production

level of 93,000 BPD to 157,000 BPD. This would require an additional

1,100 to 1,750 underground hard rock miners from a skilled occupational

25 category that is already in serious short supply in Utah.

Achievement of a commercial synthetic fuels industry in Utah during

the next decade will require labor, materials and equipment capacity

that may not currently exist in the state. In light of other competing

demands for similarly skilled manpower, materials and equipment from

other in-state projects and projects in neighboring states, serious

impediments could result that would inhibit the rate of development or

eventual size of a synthetic fuels industry in Utah.

-20-

5. Regulatory

Any proposed development of synthetic fuel processes faces an array

of regulations and permit requirements. While the number of such re­

quirements is large, it is the continual change in regulatory policy

that has nurtured development delays. Consistency in regulatory policy

and simplification of the permitting process could enhance a more stable

environment from which development could proceed.

6. Environmental

Development of oil shale and tar sand deposits will invariably

impact the environment. Mining by open cut methods will impact the

landscape necessitating reclamation of lands disturbed in this fashion.

A January 1980 DOE analysis identifies a list of yet to be defined

environmental regulations that might constrain synthetic fuel develop-

22 • •

ment. These include air quality emission control measures for visi­

bility, changes in the original prevention of significant deterioration

(PSD) regulations, extension of PSD limiting increments to other pollu­

tants, short-term nitrogen oxide ambient standards, development of

hazardous waste tests and regulations, toxic product regulations, and

occupational safety standards.

Also, competition with other resources such as recreational use

associated with National Parks and other recreational areas in Utah will

create environmental conflicts. The extent that this will inhibit

synthetic fuel development in Utah will have to await completion of

ongoing environmental assessments by the BLM, the National Forest Ser­

vice, the National Park Service and, of course, any congressional action

in response to these assessments.

-21-

7. Water

Synthetic fuel development will create additional demand on the

water resources of the state. Currently, it is believed that the state

faces no serious deficits of water for energy development. However,

several major issues concern the demand for water for energy develop-

23

ment. These issues center around the question of priority determina­

tion. Exactly how will the increased demand for water affect the cur­

rent system of water allocation?

The current legal principle governing water rights in Utah is based

upon the Utah Code Annotated (1953) as revised, and in associated case

law. The governing principle was established as a mechanism by which

private sector development and productive use of the state's water

resources was encouraged. The basis of the legal principle is the

appropriation doctrine. This doctrine, in turn, is composed of three

main components: 1) beneficial use, 2) priority and 3) obligations of

appropriators.

Competing demands for the allocation of water resources in Utah

have historically been solved by reliance on the appropriation doctrine.

Thus, any appropriator who could document his water right as the initial

appropriation (thus the meaning of the first in time first in right, or

priority), and could subsequently show that his use of the water had

beneficial results and had met the legal obligations specified by the

contract, in turn, had seniority against competing claims. Note, there

are two implications for such an allocative mechanism. First, the pro­

visions of allocation hold in the case of the transfer of water rights

from one party to another. Secondly, implicit in the provisions is the

assumption that private beneficial use is synonymous with public benefi­

cial use.

-22-

The implications noted are of importance for water-energy policy

issues facing the State of Utah. Much of the water needed for synthetic

fuel development will be obtained by purchases of existing water rights.

The transfer of the existing property right implies a transfer of the

responsibilities to use the water in a manner which produces beneficial

results and simultaneously meets the obligations specified in the origi­

nal proposal. (Note, these obligations encompass the responsibility to

control pollution of water flows.) Thus, it is the project developers,

not the state, that must shoulder the burden of responsible water man­

agement.

Furthermore, the association of private beneficial use with public

beneficial use will most certainly be questioned as public interest

groups continue their effort of supporting more publicly-oriented legis­

lation. The recognition of a possible dichotomy between private and

social benefits will in turn have ramifications on the market for water

rights. It has long been recognized within the economic discipline that

such a dichotomy forces government intervention into a market in order

to preserve social benefits. It is thus possible that in the future

acquisition of existing water rights by energy developers may become

more difficult.

D. Production Scenarios

The various uncertainties and contingencies facing oil shale and

tar sand development make the projection of future production scenarios

somewhat precarious. However, two possible scenarios have been com­

piled, and appear in table II-l. Ranging from a low of 126,000 barrels

per day (BPD) to 227,000 BPD, the scenarios are based on discussions

with project proponents as well as federal, state and local government

officials. -23-

Of the oil shale projects listed in table II-l, Paraho and Tosco

are now completing their negotiations with DOE for grants of $5 million

each for engineering and design of commercial-sized retort modules.

Tosco proposes to design a 43,000 BPD facility, while Paraho proposes to

design a 6,000 to 10,000 BPD plant. The projections assume that this

work will lead to the construction and operation of these plants. If

these demonstration projects prove successful, it is assumed that Tosco

will increase its capacity to 47,000 BPD, and that Paraho may choose to

gear-up to 30,000 BPD sometime beyond 1990. Spokesmen for Geokinetics

feel confident that the firm can expand its present research and devel­

opment activity by mid 1982 to produce 2,000 BPD. Moreover, if federal

leases become available Geokinetics intends to produce 20,000 BPD by

1990.

Perhaps the greatest uncertainty in the projections concerns the

White River Shale Project (WRSP). Pending a definitive outcome of cur­

rent court cases, WRSP will reportedly adopt whichever technology proves

more feasible between the Paraho and Tosco processes. Current develop­

ment plans for WRSP calls for the ultimate production of 100,000 BPD.

Tar sand production scenarios are also rather tentative, and are

based on the assumption that pilot plant operations will determine

necessary information to pursue commercialization.

Column A in table II-l gives the level of production which DOE

24 considers most probable given the current situation. Column B gives

the original company proposed production which may be subject to revi­

sion depending on initial development results. Columns C and D are the

low and high company projections as indicated in the project proposals.

The oil shale figures are based on 94 percent recovery of kerogen from

-24-

the retorted shales. The tar sand figures are based on a resource

containing 11.3 gal/ton of bitumen and a recovery efficiency of 90

percent.

Likewise, the estimates of mining requirements in table II-2 are

based on the same efficiencies as for table II-l and resource richness.

The figures given in table II-2 indicate what perhaps will be the big­

gest constraint to synfuels development in Utah, i.e., mining produc­

tion. For the A & C scenario there will be required 212,400 tons per

day (TPD) or 70,097,000 tons per year (TPY). In the B & D scenario

these figures are 468,300 TPD and 154,470,000 TPY. The A & C scenario

is nearly six times the entire level of coal production in Utah for 1979

and scenario B & D is about thirteen times the coal production for 1979.

It is clear that a synfuels development of 100,000 to 200,000 BPD is an

extremely large scale development and will require much planning to

successfully implement.

-25-

Table II-l

PRODUCTION SCENARIOS OIL SHALE AND TAR SAND DEVELOPMENT

BY 1990

Oil Shale Projects3^

White River (28GPT) Tosco (25GPT) Paraho (25GPT) Geokinetics Oil Shale Subtotal

(Barrels per day) A B

40,000 43,000 10,000 20,000 113,000

100,000 47,000 10,000 20,000 177,000 "i

Barrels per (330 day) year A B

13,200,000 14,190,000 3,300,000 6,600,000 37,290,000

33,000,000 15,510,000 3,300,000 6,600,000 58,410,000

b) c) Tar Sand Projects

Great National Sohio Tar Sand Subtotal

Barrels C

8,000 5,000

13,000

per day D

25,000 25,000 50,000

Barrels per (330 day) year C D

2,640,000 1,650,000 4,290,000

8,250,000 8,250,000 16,500,000

Total Utah Production

Barrels per day Barrels per (330 day) year A&C BSD A&C B&D

126,000

r

227,000 1 41,580,000 74,910,000

A - DOE projections B - Original Company production plan C - Company low production plan D - Company high production plan

a) - Assumes 94% recovery of kerogen from retorted shale b) - Assumes 90% recovery of bitumen-from processed tar sand c) - Assumes tar sand with 20 gal/yd or 11.3 gal/ton

-26-

Table II-2

MINING SCENARIOS OIL SHALE AND TAR SAND DEVELOPMENT

BY 1990

Oil Shale Projects9)

White River (28GPT) Tosco (25GPT) Paraho (25GPT) Geokinetics (23GPT)

(In-situ) Oil Shale Subtotal

Tons per day A B

64,000 76,900 17,900

NA 158,800

160,000 84,000 17,900

NA 261,900

Tons per (330 day) year A B

21,120,000 25,377,000 5,900,000

NA ^52,397,000 ^

52,800,000 27,770,000 5,900,000

NA 86,470,000

Tar Sand Projects ' c'

Great National Sohio Tar Sand Subtotal

Tons per day Tons per (330 day) year C D C D

33,000 20,600 53,600

103,200 103,200 206,400

10,900,000 6,800,000 17,700,000

34,000,000 34,000,000 68,000,000

Total Mining Production

Tons per day Tons per (330 day) year A&C B&D A&C B&D

212,400 468,300 70,097,000 154,470,000 1

A - DOE projections B - Original Company production plans C - Company low production plan D - Company high production plan

a) - 94% recovery of kerogen from retorted shale b) - 90 % recovery of bitumen from processed tar sand c) - Assumes tar sand with 20 gal/yd or 11.3 gal/ton

-27-

III. OIL SHALE PROJECTS IN UTAH

A. White River Shale Project

The White River Shale Project (WRSP) was formed in June 1974 by

Phillips Petroleum Company, Sun Oil Company (now Sunoco Energy Develop­

ment Company—Sunedco), and Sohio Petroleum Company (now Sohio Natural

Resources Company—Sohio).

The project was formed for the express purpose of establishing a

plan for joint development of the oil shale resource awarded through the

Federal Prototype Oil Shale Leasing Program. The lease to Tract U-a was

awarded to Phillips and Sunedco in May 1974 for a bonus bid of $76.6

million. Sohio then joined Phillips and Sunedco to create the White

River Shale Oil Corporation which was awarded a lease on Tract U-b in

June 1974 for a bonus bid of $45.1 million. Effective January 1, 1975,

Sohio was assigned the lease on Tract U-b.

As required by provisions of the federal leases, WRSP has conducted

an extensive two year environmental monitoring program to establish

baseline data pertaining to the quantity and quality of surface water

and groundwater, the quality of the air, and the population, distribu­

tion and relationships of flora and fauna. Environmental monitoring is

continuing in an effort to answer some questions raised by the baseline

monitoring work and to extend the data base.

Extensive conceptual engineering studies have also been completed

and submitted to the federal government outlining plans for development

of the tracts. These were submitted in the form of a "Detailed Develop­

ment Plan."25

-28-

Questions as to the ultimate disposition of title to the U-a and

U-b tract area in light of existing mining claims and applications for

state leases have led White River to seek and be granted a preliminary

injunction against the Federal Government. This injunction suspends the

terms, conditions, and obligations of the leases under the Federal Oil

Shale Lease Program until the problems of existing mining claims and

state lease applications are resolved. Moreover, the resolution of

these issues is held up pending the decision of the U.S. Supreme Court

involving the State of Utah and the Federal Government over Utah's

selection of 157,000 acres (including tracts U-a and U-b) of

"in-lieu-of" lands. (See Chapter II, Section C, for details.)

The WRSP plans to produce 100,000 BPD by 1990, however, table II-l

shows a DOE projection for WRSP at 40,000 BPD. If the DOE projection is

correct then the 100,000 BPD projection by WRSP may still be possible

but not until after 1990. In either case the projected production

levels will require an incredible mining effort. Table II-2 shows that

this project could require from 21,120,000 TPY to 52,800,000 TPY to be

mined. This is two to five times the entire coal mining production in

Utah for 1979.

Table III-l summarizes the WRSP statistics.

1. Oil Shale Resource

The WRSP is working toward the development of oil shale resources

on 10,240 acres of Federal Lease Tracts U-a and U-b. The tracts are

located in a remote section of northeastern Utah lying immediately south

of the White River in the southeastern portion of the Uinta Basin, (see

figure III-l).

-29-

Table III-l

WHITE RIVER SHALE PROJECT

SITE Uintah County, Utah; T. 10 S., R. 24 E.

10,240 acres on Federal lease U-a, U-b

PRODUCTION 40,000 to 100,000 BPD

First Production: 1989

WATER REQUIREMENTS Usage:

Source:

11,000 to 26,000 acre-feet/year

White River Reservoir

EMPLOYMENT Peak Construction:

Operation:

Mi ne:

4,200

990

430 to 1,060

PROCESS Technology:

Spent Shale:

Surface retort- Paraho, Tosco II, and Union B

55,000 to 138,000 TPD 18,163,200 to 45,400,000 TPY

MINING OPERATION Type:

Production:

Grade of Shale:

Underground, room and pillar

64,000 to 160,000 TPD 21,120,000 to 52,800,000 TPY

28 GPT

-30-

Assayed samples of oil shale from Tracts U-a and U-b show an aver­

age thickness of approximately 55 feet with an average yield of 28

gallons of kerogen per ton. This rich oil shale deposit, known as the

Mahogany Zone, has an overburden which ranges from 250 feet to 1,225

feet. The total oil shale resource present in the Mahogany Zone is

estimated to be 1,060 million barrels. Current estimates anticipate

that approximately 70 percent of this resource could be recovered by the

WRSP project.

2. Mining and Processing Technology

Extensive conceptual engineering studies have been completed by

WRSP and submitted to the Area Oil Shale Office (U.S. Geological Survey)

for approval. The schedule and technologies described in the engineer­

ing studies are based on state-of-the-art knowledge of oil shale mining

and processing. As knowledge of technologies is further developed and

regulatory and economic conditions dictate, the plan and development

schedule presented can be expected to be modified.

WRSP's plans are to follow a modular development approach in com­

mercializing oil shale operations on Tracts U-a and U-b. At the present

time, WRSP anticipates that they will utilize a proven deep room and

pillar mining operation. Mined oil shale will be moved above-ground

where it will be prepared as retort feed by several stages of crushing

and screening. Primary crushing will be carried out in the mine.

The crushed shale will be processed by above-ground retorts. The

specific principal technology of the "above-ground" processing method

has not yet been selected. Several technologies are currently being de­

veloped and demonstrated. The results and success of these demonstra­

tions will be used in making the final selection.

-31-

In-situ technology is not being considered as a candidate for the

primary recovery technology at this time. WRSP is, however, evaluating

the progress being made in this area and will adjust its development

plans to accommodate in-situ as a secondary recovery technology as it is

further developed and refined.

3. Market and Transportation of Shale Oil

Potential marketing areas for the shale oil have been identified.

These areas are:

(1) the Wasatch Front,

(2) the Los Angeles, California area, and

(3) the midwestern United States.

Of the three areas considered, the midwestern United States market

27 appears to be the most promising.

Serving the Los Angeles Basin market would require construction of

a pipeline south from the project site to existing crude petroleum

pipelines in the Four Corners area of Utah. From this location connec­

tions could be made with refineries in Arizona, New Mexico and Southern

California. Under this marketing proposal, shale oil (upgraded kerogen)

from WRSP would have to compete with North Slope crude from Alaska.

Alaskan crude has already caused gluts on the West Coast, making this

market alternative temporarily undesirable. This existing market condi­

tion is, of course, subject to change over a period of time.

In considering the Wasatch Front area of Utah as a potential mar­

ket, limiting factors exist in the refining capacity of the area to

absorb the total shale oil output. Even though there is an existing

10-inch pipeline corridor between Rangely, Colorado and Salt Lake City,

project officials indicate that construction of a new pipeline from the

project site to Salt Lake City would be required.

-32-

To move the shale oil into what the project sponsors view as the

primary market area, a 16-inch pipeline will be constructed for the

commercial phase of the development. The proposed pipeline will convey

the shale oil from the project site along one of two alternative routes

to destinations in Wyoming. Both of these routes are intersected by two

major pipelines which terminate in the midwest, and both have the exist­

ing excess capacity to handle the approximate 100,000 BPD of shale oil

from the WRSP facility. The two alternative routes are:

Alternative one. This route would run from the project site to

Casper, Wyoming. From the project site to Colorado Highway 64, the line

would follow existing Bureau of Land Management corridors containing

pipelines and roads. From Highway 64, the new pipeline would follow an

Amoco right-of-way containing a small-diameter crude line to

Sunbeam, Colorado. From Sunbeam, the line would proceed north to

Wamsutter, Wyoming. The line from Wamsutter would follow an Amoco

right-of-way containing a small-diameter crude line to Casper, Wyoming.

Alternative two. This route would run from the project site to

Fort Laramie, Wyoming. From the project site to Highway 64, the route

would be similar to that of Alternative one. The line would follow the

Amoco right-of-way from Highway 64 to Baggs, Wyoming, via

Sunbeam, Colorado. It would then proceed from Baggs in a new corridor

to Coyote Springs, where it would follow another Amoco small-diameter

crude pipeline to Fort Laramie.

4. Water Requirements

The WRSP has requested 26,000 acre feet per year from the state's

proposed White River Dam Project. Company spokesmen believe, however,

that technological improvements may ultimately reduce actual water re-

-33-

quirements to as low as 13,000 acre feet per year for a 100,000 BPD

shale oil facility.

Of a number of alternative sources of water for WRSP, the company-

prefered alternative is a planned dam and reservoir on the White River

to be built by the State of Utah Division of Water Resources. The

project would be a multipurpose development that would provide a firm

water supply for oil shale processing on Tracts U-a and U-b and would

have sufficient capacity to furnish water for additional oil shale

development in the area.

The site selected for the dam to be built on the White River is

located near the center of Section 17, T. 10 S., R. 24 E., approximately

four miles west of the processing facilities. The proposed dam embank­

ment would be a zoned earth and rock fill structure rising to approxi­

mately 129 feet above the stream channel. White River Dam statistics

are summarized in table II1-2 and the dam site is shown in figure III-l.

Raw water for plant and processed shale use will be obtained from a

pumping station located on the south bank of the reservoir. The pumping

station will pump water through a two mile, 24-inch pipeline to an

on-tract storage pond. The on-tract storage pond will be constructed to

provide operational flexibility, including three days reserve. Also,

additional storage will be maintained to ensure a reliable supply of

water during an outage of the reservoir pumping station or pipeline and

to control drainage water.

5. Air Quality Impacts

The WRSP property is in a Class II, Prevention of Significant Air

Quality Deterioration (PSD) Area. Construction and operation of the

proposed project will impact the atmospheric environment at each devel­

opment stage.

-34-

Table III-2

WHITE RIVER DAM, RESERVOIR AND HYDROELECTRIC POWER PROJECT

SITE Uintah County, Utah

Section 17, T. 10 S., R. 24 E.

PRODUCTION Capacity:

Power Generation:

105,000 acre-feet (total) 67,000 acre-feet (active) 500,000 acre-feet (annual flow)

5 MW

COST

EMPLOYMENT

TECHNOLOGY

Dam and Reservoir

Power Plant:

Construction:

Operation:

Start-up:

Completion:

Dam:

Power Plant:

$19 million (State funds)

$6 million (State funds)

300

10

1981

1983

Earth and rock fill

Hydroelectric, Kaplan turbine

-35-

WRSP officials believe that all emission and air quality standards

will be met during the construction and operating phases of development

activities. However, while significant on-tract and off-tract impacts

are not anticipated by company officials, previous air dispersion model­

ing results point to potential problems in meeting existing PSD Class II

particulate increment limits. Further modeling efforts must await the

final selection of a retorting technology.

6. Socioeconomic Impacts

Construction workers will make a sizable transient addition to the

local population. To help alleviate adverse socioeconomic effects in

the local area a temporary campsite will be established to provide

housing services and recreation for site workers and their families and

for indirectly employed people who will come into the area to provide

goods and services to the camp population.

As proposed in the Detailed Development Plan, the campsite will be

located at Bonanza, five miles north of the construction site. It will

consist of mobile homes as well as eating, shopping, and recreational

facilities. The projected campsite population is calculated to peak at

about 7,000 in the 10th year.

A pool of operations manpower will serve mining, retorting, upgrad­

ing, and all of the support functions necessary to the project as it

moves through all phases of commercial operations.

Mining manpower requirements will grow steadily through all phases

of the project until it levels off at 1,060 men at full production. In

contrast, the manpower requirements for processing operations decrease

between Phase II and III, then steadily increase to a final manpower

requirement level of 990 men at full production.

-36-

The housing needs of the operations work force will be of a more

permanent nature. The town of Vernal, population 8,000, will provide

most of the permanent housing and required services to meet the needs of

the work force from the oil shale project.

WRSP is working closely with local government agencies to insure

that they are informed of WRSP's schedule and plans. This will hopeful­

ly facilitate advance planning and adequate front-end financing to help

guarantee orderly municipal expansion in response to the rapid influx of

new residents. However, due to the magnitude of growth that is antici­

pated, serious problems could arise in the provision of public services

by local impacted communities.

7. Program for Disposal of Spent Shale

It is estimated that for each ton of oil shale processed by WRSP

22 there will be 0.86 ton of spent shale for disposal. Therefore, a

100,000 BPD facility requiring 160,000 TPD of oil shale will result in

138,000 TPD of spent shale, which is approximately 45,400,000 TPY, for

disposal. At the completion of the 20 year WRSP project there will be

950 million cubic yards of spent shale which could cover 900 acres to an

average depth of 200 feet.

Southam Canyon just south and to the west of the processing area is

the company-preferred disposal area for shale processed in all stages of

the White River Shale Project. Factors relevant to using Southam Canyon

as a processed shale disposal area are:

(a) There is sufficient space in this canyon to hold the

anticipated volume of processed shale from the entire

project within the lease boundary.

-37-

(b) The low average rainfall in the area of Tracts U-a and

U-b will result in a low level of surface drainage from

Southam Canyon.

The processed shale will be brought from the retorting area by con­

veyor to a truck loading bin. From there, trucks will move the spent

shale to the disposal area where they will dump and compact the material

in layers. Bulldozers will complete the sculpturing and contouring of

the pile so that it blends in with the surrounding topography.

Spent shale ranges in particle size from fine to gravely, depending

on the retorting process, and contains all the basic nutrients found in

the native soil except for nitrogen and phosphorus.

Studies conducted for the WRSP by the Institute for Land Rehabili­

tation at Utah State University have shown that selected plants can be

established on processed shale. Ten native plant species have demon­

strated the ability to grow when transplanted directly into processed

shale; however, pre-planting, planting, and post-planting management

operations need to be established and carried out to successfully re-

vegetate spent shale.

8. Construction and Production Schedules

The WRSP plan currently regarded by the company as most probable

among alternatives is a modular development of mining, processing, and

related operations in four phases up to full commercialization of a

100,000 BPD shale oil production facility.

The first phase includes sinking an access shaft for initial test­

ing and examination of the ore body to obtain geotechnical data for

final mine design and to provide a bulk sample for retort and crusher

conformation.

-38-

Work on opening the mine will begin towards the end of the second

year and should be completed within six months time. Opening of this

operation will provide 2,000 to 10,000 tons per calendar day of shale

and permit selection of those retorting and crushing techniques best

suited for producing oil from the specific shale mined on Tracts U-a and

U-b.

Phase II will involve engineering studies followed by construction

of a single commercial-sized retort along with a working mine and ancil­

lary facilities. Construction of the mine and above-ground facilities

will require three years at which time full operations will commence and

continue for two years.

In Phases III and IV, construction of full scale commercial opera­

tions will begin during the first quarter of year eight. The first and

second train units (modular additions), attendant ground facilities and

mining operations will be developed concurrently. Start-up and mine

production for support of the first train will be initiated during the

eleventh year of the development plan. A second train start-up and sup­

porting mine production will be initiated in year twelve.

9. Project Participants and/or Sponsors

The WRSP participants are Phillips Petroleum Company, Sunoco Energy

Development Company, and Sohio Natural Resources Company.

B. Paraho Project

The Paraho Project is a proposed plan for development of oil shale

28 resource in the Uinta Basin. The project will be a concerted effort

between the Paraho Development Corporation, its project team, sponsors

and the DOE. As envisioned, the project will be divided into two

phases. Phase I will define the design, cost, schedules, and perform-

-39-

ance plans for constructing and operating a retort module and associated

facilities. Phase II goals will be to construct and operate the retort

module and support equipment for a period adequate to confirm the tech­

nical, economic, and environmental control data for a commercial pro­

duction plant. The primary benefit of Phase II will be the demonstra­

tion of process technology and economics at a scale fully representative

of commercial operations. Also, socioeconomic and environmental impact

data will be available on an adequate scale for reasonable evaluation.

The Paraho Development Corporation has already undertaken the three

year, $10 million, privately funded Paraho Oil Shale Demonstration which

was completed August 31, 1976. The work was performed at the leased

Anvil Points Facility near Rifle, Colorado and used Green River oil

shale from the edge of the Piceance Creek Basin. A Paraho Pilot retort

(2h foot inside diameter) and a Paraho Semi-works retort (8h foot inside

diameter) were designed, constructed, and installed. Valuable research

information gained from the Colorado project will, in many instances, be

applicable to the proposed Utah project.

The Paraho project expects to produce 6,000 to 10,000 BPD with

10,000 BPD prefered by 1990. This would require 17,900 TPD of oil shale

or 5,900,000 TPY. This level of mine production is larger than any

existing underground mine in Utah. Table 111-3 summerizes the Paraho

project statistics.

1. Oil Shale Resource

The site for the Phase II program is on a 582 acre State of Utah

oil shale lease in northeastern Utah. The lease is in Section 32, T. 9

S. , R. 25 E. The lease expires in July of 1998. (See figure III-l for

site location.) The lease is 1*5 miles from Federal Prototype Lease

-40-

Table 111-3

PARAHO OIL SHALE PROJECT

SITE Uintah County, Section 32, T. 9 S., R. 25 E.

582 acres on state lease

PRODUCTION 6,000 to 10,000 BPD

First Production: 1984

WATER REQUIREMENTS Usage:

Source:

200 to 400 acre-feet/year

White River Reservoir

EMPLOYMENT Peak Construction:

Operation:

Mine:

800

400

72 to 120

PROCESS Technology:

Spent Shale:

Surface, Paraho, gravity feed vertical retort

9,200 to 15,400 TPD 3,050,000 to 5,080,000 TPY

MINING OPERATION Type:

Production:

Grade of Shale:

Underground, room and pillar

10,740 to 17,900 TPD 3,544,000 to 5,900,000 TPY

25 GPT

-41-

Tract U-b. Environmental data developed for Tracts U-a and U-b will be

used for Phase I work associated with the Paraho lease.

It is estimated, by company officials, that the leased oil shale

resource contains 87 million barrels of 25 gallon per ton material. Of

this 87 million barrels of in-place resource 62 percent or 54 million

barrels could ultimately be recovered.

2. Mining and Processing Technology

The processing technology to be used by Paraho centers on the

construction and operation of an above-ground oil shale retort module.

The retorting process has been tested at the Paraho Anvil Point demon­

stration site with the result of over 100,000 barrels of crude oil

having been produced. The next step in the technological development of

the process is the demonstration of a full-size retort module.

The basic design of the retort module was pioneered by Paraho in

1966 for the calcination of limestone. The module is characterized by a

vertical kiln where an air and gas mixture is injected into the module

at three separate distributor levels. This mixture is combusted which

results in the separation of oil and gas from the retorted shale.

Many of the design features of the retort module are currently

known, according to company officials. These would include the sizing

and spacing of distributing holes, the control of heating and cooling

within the separate zones of the module, the solid feeds and distribu­

tion methods, the disengagement of oil mist and gas from the top of the

retort, and the characteristics of the oil mist droplets and design gas

velocity for electrostatic precipitators. Other design factors are

still under development for the full-size retort module.

-42-

3. Market and Transportation of Shale Oil

At this stage of the Paraho development program, specific product

markets and transportation networks have not been identified. While

preliminary data obtained by company officials has shown the economic

viability of a commercial operation, such viability will be highly

dependant on the structure of the markets and transportation alterna­

tives faced by Paraho.

4. Water Requirements

The water for the project will be provided from the White River.

Paraho officials expect that the proposed White River Dam and Reservoir

will be constructed in time to provide water on a contract purchase

basis. Total water requirements per annum are estimated in the range of

200 to 400 acre feet. The facility will operate on a zero discharge-

waste water concept.

5. Air Quality Impacts

Paraho officials believe air quality impacts will be controlled to

meet existing regulations. Work performed on a similar retort module in

Colorado provided air quality results favorable to appropriate regula­

tions. With regard to the Utah project, the pollutants emitted from the

mining, retorting, rock handling, gas combustion, and associated fuel

uses will be primarily nitrogen oxides, particulates, carbon monoxide,

and sulfur dioxide. The use of a gas cleanup system, baghouse collec­

tors, and wet suppression is expected to control emissions to an accept­

able level.

6. Socioeconomic Impacts

Paraho officials estimate that as many as 800 workers could be

required during the peak of the construction phase. Estimated manpower

-43-

requirements for the operations phase of the program may entail as many

as 400 workers.

Such an influx of people into the sparsely populated Uinta Basin

presents the possibility of adverse socioeconomic and cultural effects.

Basic services such as housing, medical care, education for children,

etc. will require advanced planning by corporate officials, public

agencies, and local community organizations. The problem of financing

such services via tax revenue will be severely restricted due to a lag

time between demand for services and tax revenue collection. Front-end

financing will be required to mitigate these adverse effects. The form

of this financing will be subject to negotiation between Paraho, local

communities, and public agencies.

Paraho officials believe serious consideration should be given to

the idea of a new town located near the existing community of

Bonanza, Utah. As seen by Paraho, the major advantages of this idea are

that the local existing communities would receive less adverse impact,

commuting time for employees would be reduced, rapid fluctuations in

population as activities go from construction to operation could be more

easily accommodated, and the expansion "boom town" effects could be

isolated and handled in an efficient manner. What effect such isolation

would have on worker motivation or the required wage scale needed to

attract experienced personnel has not been determined.

7. Program for Disposal of Spent Shale

The Paraho project (at 10,000 BPD) would provide approximately

15,400 TPD or 5,080,000 TPY of spent shale. Processed shale will be

placed above ground and protected against leaching, erosion, and dust

generation. The specific program for disposal has not been released by

company officials.

-44-

8. Construction and Production Schedules

Company officials currently project a period of 68 months in which

both Phase I and Phase II can be completed. Variations in this schedule

are likely, however, due to acquiring necessary environmental approvals,

receiving needed financing, variations in construction time, and demon­

stration of a commercially viable technology.

The overall program schedule (currently) can be broken down as

follows:

a) Phase I — 18 months (January, 1980 - June, 1981)

b) Phase II —

i) Phase II decision - six months (June, 1981 -

January, 1982)

ii) Detailed design - six months (January, 1982 -

June, 1982)

iii) Construction - 18 months (June, 1982 - January, 1984)

iv) Operation - 24 months (September, 1983 - September, 1985)

9. Project Participants and/or Sponsors

The project participants include, Paraho, the Standard Oil Company

(Ohio), the Cleveland-Cliffs Iron Company, Davy McKee Corporation, VTN

Consolidated, Inc., and Aero Vironment, Inc. Sponsors include Sohio

Shale Oil, Phillips Petroleum, Mobile Research and Development,

Cleveland - Cliffs Iron Company, Moon Lake Electric Association, Davy

McKee Corporation, and Paraho.

C. Tosco Sand Wash Project

The Oil Shale Corporation (Tosco) presently holds leases on five

tracts of state land, totaling 14,688 acres at its Sand Wash properties.

Under terms of a Unitization Agreement signed with the state in 1975,

-45-

Tosco is now in its fourth year of an eight-year plan to prepare the

leases for future commercial development. As presently conceived, the

29 company seeks to eventually construct a 47,000 BPD oil shale facility.

However, the initial development may be only 43,000 BPD. The preferred

47,000 BPD production level would require the mining of approximately

84,000 TPD or 27,770,000 TPY of oil shale. This is more than twice the

total Utah coal mining effort in 1979. Table III-4 summarizes the Tosco

project statistics.

These plans are still tentative, however, as several unpredictable

risks and uncertainties exist with respect to technology (mining and

processing technologies have not been demonstrated at the commercial

scale), financing (a 47,000 BPD facility requires approximately $1.2

billion in capital investment with four to five years of outlays prior

to receiving initial income from production), a rapidly changing regula­

tory climate, and a lack of a predictable federal energy policy.

In its four years of early development activities at the Sand Wash

site, Tosco has conducted:

(1) exploration of the geology and hydrology through core dril­

ling,

(2) environmental baseline monitoring as a forerunner to prepar­

ing an impact analysis,

(3) revegetation program,

(4) equipment procurement and permit acquisition for an experi­

mental mine,

(5) socioeconomic planning, and

(6) preliminary engineering and cost estimating for commercial

scale facilities.

-46-

Table 111-4

TOSCO SAND WASH PROJECT

SITE Uintah County, Utah T. 9 S., R. 21 E.

14,688 acres on state lease

PRODUCTION 43,000 to A7,000 BPD

First Production: 1988

WATER REQUIREMENTS Usage:

Source:

18,000 acre-feet/year

White River

EMPLOYMENT Peak Construction:

Peak Operation:

Mine:

3,075

700

500 to 560

PROCESS

MINING OPERATION

Technology:

Spent Shale:

Type:

Production:

Surface, horizontal retort (TOSCO II)

66,100 to 72,200 TPD 21,800,000 to 23,900,000 TPY

Underground, room and pillar

76,000 to 84,000 TPD 25,377,000 to 27,770,000 TPY

Grade of Shale: 25 GPT

-47-

1. Oil Shale Resource

The mining zone of commercial interest in the Sand Wash area is the

Mahogany Zone of the Parachute Creek Member of the Green River forma­

tion. According to design parameters used by the Tosco Mining Depart­

ment, the depth of the mining zone varies from 1,800 to 2,400 feet below

the surface (depending on the location within the lease units).

The state lands included in the Unitization Agreement are situated

approximately 12 miles southeast of Ouray, Utah and 34 miles due south

of Vernal, Utah, in Uintah County (see figure III-l).

2. Processing Technology

The mining operation now contemplated will use conventional room

and pillar underground mining techniques. Access to the mining zone

from the surface will be through vertical shafts, with mine ventilation

provided by a forced air system.

The solid shale rock is drilled, blasted, and then hauled to the

surface for crushing. In a series of steps the shale is reduced from

large chunks (weighing up to several thousand pounds) to small,

half-inch sized pieces.

The technique used to extract kerogen from shale is referred to as

the "Tosco II" process developed and refined by Tosco from an earlier

Swedish method. At the heart of this process is the Tosco II retort

unit, where crushed shale is mixed with small, heated ceramic balls in a

sealed rotating cylinder called a pyrolysis drum. When the shale

reaches a temperature of about 900 degrees Fahrenheit, the organic

material yields kerogen vapors and other gases. The kerogen vapors are

then condensed into an oil and upgraded. By-products of this process

include ammonia, coke and sulfur. Gas similar to low BTU natural gas is

also produced, and is intended to be used as plant fuel.

-48-

The composition and usability of kerogen is within the range of

properties of conventional crude oils, its only unusual properties being

a high "pour point" (not considered a problem), and a high nitrogen

content. The nitrogen level is sufficiently high to interfere with

conventional refinery processes, and therefore, requires removal by

standard hydrogenation processes.

The hydrogenation process produces a synthetic crude oil of premium

quality which can be readily converted into transportation fuels in a

typical refinery.

3. Market and Transportation of Shale Oil

Potential markets for the product include most of the Rocky Moun­

tain region, as well as Southern California, where Tosco presently owns

refineries for future processing of shale oil. The company may also opt

to exchange or sell shale oil on the open market.

Oil product shipment after upgrading will probably be by pipeline.

The closest existing crude oil pipelines are the Chevron pipelines

(Rangely, Colorado to Salt Lake City) within 15 to 20 miles of the plan

area; the Amoco pipeline 40 miles to the east at Rangely; and the Pure

Oil pipeline, some 140 miles south at Lisbon, Utah. The Colony Oil

Shale Project in Colorado has applied for a federal permit to build a

pipeline from Colorado to Lisbon. When built, the line would pass

within 50 miles of the Sand Wash site. Thus, several options are avail­

able for shipping shale oil via a new connection from Sand Wash to an

existing or planned common carrier pipeline.

By-products, (LP6, sulfur, coke, and ammonia) if produced commer­

cially, will probably be transported by truck. The nearest rail heads

accessible by improved highway are at Castle Gate, Utah and

Craig, Colorado, located 120 and 140 miles from the site, respectively.

-49-

4. Water Requirements

Tosco has filed a request with the state for 18,000 acre feet per

year from the White River for its water supply. More than 1,700 barrels

of kerogen can be produced per acre-foot of water consumed under current

technology, although recent research by Tosco suggests that with further

technological improvements, water consumption could be reduced by as

much as 20 percent.

Water diversion facilities from the White River would be located in

the general vicinity of the proposed Ute Indian Irrigation Project east

of Ouray, Utah. Such diversion would require releasing water from the

White River Dam which would flow downstream to the point of diversion,

and then be pipelined south to the project location.

Tosco has filed an application with the Utah Division of Water

Rights to appropriate an additional 10,000 acre-feet of water per year.

This application also includes provisions for a 19,890 acre-feet reser­

voir which would cover a land area of about 560 acres. Prior to any

final reservoir site selection, an overall environmental and engineering

assessment will be made to determine the consequences on land use (both

in the immediate area and the affected lands downstream) and the geo­

logic suitability of alternative sites.

5. Air Quality Impacts

Tosco properties are located in a Class II PSD Area. Air quality

at the Sand Wash Project will be affected in at least two ways. First,

dust will be generated by construction, transportation, and process

activities, adding to the suspended particulate matter in the air.

Secondly, gaseous emissions will be released from the plant, mining and

reclamation equipment and employee vehicles.

-50-

Since the Tosco Sand Wash Project will be using similar technolo­

gies and development plans as is being used at their Colony Project in

Colorado, some conclusions on air quality impacts from the Colony Pro­

ject might be relevant to the Sand Wash site. At Colony, Tosco employ­

ees Venturi water scrubbers on all stacks to remove particulate matter.

Ammonia and sulfur recovery and coking units are to be used to reduce

emissions of No S09 and hydrocarbons. Contained arsenic is also re-

moved and disposed of as a solid waste.

The crushing and conveying facilities will use bag dust collection

units to remove dust, and the equipment will be enclosed to prevent

windblown dust during movement. The stacker/reclaimer on the spent

shale pile will use a water spray dust suppression system, and dust

prevention techniques will be used for spent shale disposal.

In July 1979, the U.S. Environmental Protection Agency issued a PSD

permit, claiming that Colony's proposed emissions monitoring program

will adequately assess the air quality impacts and assure continued

compliance with the conditions of the PSD permit.

6. Socioeconomic Impacts

As mentioned earlier, Tosco1s Sand Wash Project is situated 34

miles south of Vernal, Utah. Vernal, located in the center of an agri­

cultural valley, is the closest major town to the leases and is the

Uintah County seat with a population of approximately 8,000. The Uinta

and Ouray Indian Reservation is directly north of the Sand Wash Project,

and the nearest permanent dwellings are in the vicinity of the reserva­

tion hamlet of Ouray. In addition to these areas, Roosevelt, Utah,

(located 38 miles west of Vernal on U.S. Highway 40) will also be im­

pacted by the Sand Wash Project.

-51-

Socioeconomic analyses conducted by Tosco indicate that a 47,000

BPD commercial oil shale facility will generate 2,400 construction jobs,

1,000 permanent operating jobs, and roughly 3,400 jobs in related areas

of employment; a total of 6,800 new temporary and permanent jobs. While

the Sand Wash Project could potentially triple the tax base of Uintah

County, there is a "tax lead time" of approximately five years. Conse­

quently, increased demand on roads, housing, schools, water, sewer, and

other infrastructures pose serious problems for the small rural communi­

ties of this area.

7. Program for Disposal of Spent Shale

After the kerogen has been removed from the oil shale, the retorted

shale is cooled and water added to bring its moisture content to approx­

imately 13 percent. Immediately after retorting, the processed (or

spent) shale has the consistency of fluffy black dust and the addition

of water makes it denser, impervious to wind, and more easily trans­

ported and compacted. The processed shale is then transported by cover­

ed conveyor to a nearby yet to be identified canyon or valley where it

is spread and compacted in terraced embankments. At the full production

level of 47,000 BPD there will be generated approximately 72,200 TPD or

23,900,000 TPY of spent shale.

Extensive revegetation studies have been conducted by Tosco at both

the Colony and Sand Wash sites, involving experimental revegetation

plots of about 500 square feet. In cooperation with the U.S. Forest

Service and the Plant Materials Center at Meeker, Colorado, a total of

75 different species of grass, trees, shrubs and other flowering plants

have been grown successfully in spent shale.

-52-

In May 1976, Tosco hauled approximately 360 tons of spent shale

from Colony to Sand Wash to test the ability of native Utah plants to

grow in spent shale. Several designs were used in planting. Prelimi­

nary results showed that plants receiving supplemental water through

drip irrigation were green and growing sooner than those not receiving

water. Five native species and two introduced species showed excellent

promise in revegetation of spent shale. These included the native

Gardner saltbush, Broadcastle saltbush, Bonneville saltbush, Shortwinged

saltbush, and Fourwing saltbush. The introduced species were Mediter­

ranean camphorfume and Prostrate summer cypress. Thus far, the Fourwing

saltbush has shown the best survival and growth of all species planted.

8. Construction and Production Schedules

As discussed earlier, several uncertainties still exist concerning

the actual construction and production of a commercial facility. Under

the Unitization Agreement, Tosco is committed to spend a minimum of $8

million in development activities by 1984.

According to generic schedules, Phase I (development stage) will

last five years and employ 500 people at the end of the period. Phase

II (plant construction stage) is scheduled for years six through nine.

Employment will peak in the eighth month of the eighth year at 3,075 and

then decline to 1,175 at the end of construction. Phase III (operation

stage) will occur in years 10 through 20 with employment running steady

at 1,000 to 1,200 employees.

9. Project Participants and/or Sponsors

The Tosco Corporation is the sole participant in the Sand Wash

project and receives some sponsorship from DOE.

-53-

D. Geokinetics Inc. In-situ Project

Geokinetics Inc. is the only oil shale operation in the state to

have actually produced oil from shale in any significant amount. The

company's production in 1976 was 166 barrels. In 1977, production was

1,780 barrels, and in 1978, 3,434 barrels.30 Production for 1979 is

estimated at 5,000 barrels. Geokinetics has been shipping their shale

oil via tanker trucks to the Plateau Refining Company at

Roosevelt, Utah, where it has been blended with normal refinery feed­

stock and refined to yield gasoline and diesel fuel. The company has

recently contracted to sell their product to the U.S. Department of

Defense.

In terms of corporate structure and financial resources, Geokinet­

ics is miniscule; especially in comparison to the White River Shale

Project and the Tosco Sand Wash Project. Geokinetics began its field

activities five years ago, working out of tents at its isolated Tavaputs

Plateau site as a small, single-family operation. It has since obtained

funding from the U.S. Department of Energy and continues to classify its

activities as Research and Development.

Mitchell A. Lekas is president of the company and inventor of what

he terms the "Lofreco Process" (an acronym derived from low front end

cost) which comprises a horizontal in-situ retorting process. Not only

does the method minimize the need for substantial front-end capital

expenses, but it is also best adapted to thinner beds of low-grade shale

which might not otherwise appear commercially feasible for development.

Geokinetics plans to commence with commercial operations by 1983 at

2,000 BPD and eventually to scale up to 20,000 BPD by 1990. Table III-5

is a summary of the statistical data on Geokinetics.

-54-

Table III-5

GEDKItETICS OIL SHALE PROJECT

SITE Uintah County, Utah Section 2, T. 14 S., R. 22 E.

Approx. 3,000 acres on state lease

PRODUCTION 2,000 to 20,000 BPD

First Production: 1982

WATER REQUIREMENTS

EMPLOYMENT

PROCESS

MINING OPERATION

Usage:

Source:

Peak Construction:

Operation:

Technology:

Spent Shale:

Type:

Production:

Grade of Shale:

None for processing

Underground for workers

50

50 to 500

In-situ, modified horiz

None (remains undergrou

None

None

23 GPT

-55-

1. Oil Shale Resource

Geokinetics holds both state and private oil shale leases on ap­

proximately 30,000 acres. About 3,000 acres of state leases are suit­

able for their horizontal in-situ process with an estimated 120 million

barrels of recoverable shale oil. These leases are located approxi­

mately 70 miles south of Vernal, Utah, (see figure III-l) in the remote

Tavaputs Plateau area (Section 2, T. 14 S. , R. 22 E.). The area con­

tains relatively thin shale seams (20 to 30 feet thick) lying under

shallow overburden (ranging from 0 to 150 feet deep). Average grade of

the resource is 23 gallons per ton, and the company expects to achieve a

50 percent recovery rate on in-place oil.

2. Processing Technology

Geokinetics version of the in-situ retorting process involves an

in-place rubblization of the shale seam and the creation of a minimum

void space. In this process, a pattern of blastholes is drilled from

the surface, through the overburden, and into the oil shale bed. The

holes are loaded with explosives and fired, using a carefully planned

blast system. The blast results in a well fragmented mass of oil shale,

with a high permeability. The void space in the fragmented zone comes

from lifting the overburden and producing a small uplift of the surface.

The fragmented zone constitutes an in-situ retort. The bottom of

the retort is sloped to provide drainage for the kerogen to a sump where

it is lifted by a number of production wells. Air injection holes are

drilled at one end of the retort and off gas holes are drilled at the

other end.

The oil shale is ignited at the air injection wells to establish

and maintain a burning front that occupies the full thickness of the

-56-

fragmented zone. The front is moved in a horizontal direction through

the fractured shale towards the off gas wells at the far end of the

retort. The burning front heats the oil shale ahead of the front,

driving out the kerogen, which drains to the bottom of the retort where

it flows along the sloping bottom to the production wells. As the burn

front moves from the air-in to the air-out wells, it burns the residual

coke in the retorted shale as fuel. The combustion gases are recovered

at the air-out wells. These gases are combustible and could be used for

power generation. Progress of the burn front is monitored by thermo­

couples set in thermocouple wells.

Although the process was designed to retort relatively thin oil

shale beds under shallow overburden, the basic horizontal burn can

potentially be applied as a secondary recovery process for room and

pillar mining operations to recover shale oil from pillars and from

lower grade oil shales above and below the mined zone.

3. Market and Transportation of Shale Oil

Geokinetics is trying to establish markets at refineries in

Salt Lake City and Roosevelt, Utah, and Fruita, Colorado. In order to

make their shale oil acceptable to these refineries, they are investi­

gating the feasibility of controlled blending of shale oil with normal

refinery feedstock, and upgrading shale oil (removing excess nitrogen

content) by hydrotreating processes.

The company intends to continue using tanker trucks for the trans­

portation of their R & D output. By mid-1982, Geokinetics expects to

have completed its R & D program and to be ready to commence commercial

production of 2,000 barrels per day. The company hopes to be able to

establish a pipeline linkage to existing common carrier lines to

Salt Lake City.

-57-

4. Water Requirements

Geokinetics1 method of oil shale production requires no water. In

fact, water is produced as about 50 percent of the total liquids re­

covered from their in-situ retorts. At the present time, the firm is

using an evaporation pond to dispose of excess water.

The only water requirements necessary for their continued activi­

ties is that which is used in maintaining their camp (Kamp Kerogen).

The camp is presently using a well which was drilled 1,300 feet below

the surface. This aquifer will not be affected by the retorting process

due to its depth and the impermeability of the rock above it.

5. Air Quality Impacts

Geokinetics' properties are located in a Class II PSD Area. Stud­

ies have been underway since January 1978 to collect baseline values for

local climatic conditions and to provide a data base for a future Impact

Analysis.

6. Socioeconomic Impacts

Due to the remote location of the test site and poor communication

systems, Geokinetics established Kamp Kerogen in 1975 as a

fully-equipped, self-contained living facility for employees and their

dependents. The camp's present census consists of 26 men, 13 women, and

12 children. Housing and utilities are furnished by Geokinetics.

Vernal, Utah, will be impacted to the extent that outside supplies and

professional services will be required by Kamp Kerogen residents.

Present employment (approximately 30) will be expanded to about 50

to operate a commercial unit of 2,000 barrels per day. Employment will

be expanded in accordance to the number of units eventually put on

commercial production.

-58-

7. Program for Disposal of Spent Shale

Since this project utilizes an in-situ retort for production of the

shale oil there will be no spent shale. However, the blasting and

retorting of the oil shale zone causes disruption of the ground surface

and destroys all the surface vegetation. Two factors are at work here.

First, the larger vegetation such as trees must be removed to facilitate

the uplifting of the ground surface which results from the below surface

blasting. The surface uplift is necessary in order to obtain the needed

void space in the oil shale zone. Secondly, the remaining vegetation is

destroyed by the heat flux rising to the surface from the burning re­

tort.

These two factors result in total destruction of all surface vege­

tation. Therefore, a revegetation program will accompany the commercial

production program.

8. Construction and Production Schedules

In its five years of operations, Geokinetics has blasted 23 experi­

mental retorts and burned 13. Dimensions have ranged from 30 to 182

feet in length and 10 to 220 feet in width. Best recovery was obtained

from retort #16 (2,067 barrels) with dimensions of 87 feet long 62 feet

wide, and 20 feet thick.

This year Geokinetics plans to continue testing retorting pro­

cedures in an effort to optimize oil recovery. They have just blasted a

full commercial-sized retort (220 x 220 x 30 feet) for further testing.

In 1980, the company will blast a cluster of three full-sized retorts,

and in 1981, burn this cluster and blast a second three-retort cluster.

By 1982, Geokinetics plans to burn this second cluster and by mid-year

expects to have achieved their overall R & D objectives. If results are

-59-

favorable, the company will at that time commence production of 2,000

barrels of shale oil per day.

9. Project Participants

The participants in this project are Geokinetics Inc. and the U.S.

Department of Energy.

-60-

IV. TAR SAND PROJECTS IN UTAH

A. Sohio Natural Resources Company Project

On October 15, 1977, the State of Utah Board of State Lands ap­

proved a "Commitment to Cooperative Development Plan" submitted by Sohio

31

Petroleum Company, now Sohio Natural Resources Company. The plan pro­

vided that Sohio would pursue the common development of tar sand de­

posits on leases located on Asphalt Ridge in Uintah County.

The Cooperative Development Plan requires Sohio to complete two

specific tasks. The first was to perform additional geological work

concerning the resource in the cooperative plan area. The second task

requires Sohio to prepare a mining plan including information on the

mining and processing methods anticipated for development of the tar

sand resource contained within Sohio held leases on Asphalt Ridge. This

plan has been submitted to the Division of State Lands for review.

The Sohio project expects to produce approximately 5,000 BPD to

demonstrate the technology and then to scale up to 25,000 BPD by 1990.

At full production the processing plant would require approximately

103,200 TPD or 34,000,000 TPY of raw tar sand. This is over three times

the total Utah coal mining output for 1979. Table IV-1 summarizes the

project data for Sohio.

1. Tar Sand Resource

The Asphalt Ridge bituminous sandstone deposit is located on a

northwest-trending cuesta about 15 miles long which cuts diagonally

principally across T. 5 S. , R. 21 E. in Uintah County. The areal extent

of this deposit is about 20 to 25 square miles consisting of two to five

separate pay zones of a minimum thickness of five feet each. In-place

resources at Asphalt Ridge are currently estimated to be 1,150 million

-62-

Table IV-1

SOHIO TAR SAND PROJF.CT

SITE Uintah County, Utah Section 31, T. 5 S., R. 22 E.

1,828 acres on state lease and fee land

PRODUCTION 5,000 to 25,000 BPD

First Production: 1989

WATER REQUIREMENTS

EMPLOYMENT

PROCESS

Usage:

Source:

Peak Construction:

Operation:

Mi ne:

Technology:

Spent Sand

3,600 acre-feet/year

Green River

N/A

N/A

N/A

Surface, solvent/water extraction

17,900 to 89,800 TPD 5,914,000 to 29,630,000 TPY

MINING OPERATION Type:

Production:

Grade of Tar Sand:

Surface, strip mining

20,600 to 103,200 TPD 6,800,000 to 34,000,000 TPY

20 gal/yd3 or 11.3 GPT

-63-

barrels and analyses of these deposits indicate that this tar sand

contains from 6.4 to 29 gallons of bitumen per ton of material with an

average of about 11.3 GPT for the Sohio leases.

The Sohio leases are located throughout the Asphalt Ridge deposit.

The pilot plant and mine sites are to be located in Section 31, T. 5 S.,

R. 22 E. on Fee land. Sohio has 1,508 acres of State Oil, Gas and other

Hydrocarbon leases and 320 acres of free land for a total of 1,828 acres

for the Cooperative Development Plan (see figure IV-1).

2. Processing Technology

Sohio has developed on a laboratory scale two bitumen extraction

processes that can be applied to the Asphalt Ridge tar sand resource.

Of the two processes, the "continuous counter current solvent assisted

bitumen extraction process," or Sohio process, has been determined to be

the most successful using the Asphalt Ridge resource. Sohio has been

approached by several organizations that have bitumen extraction tech­

nologies they feel are ready for field testing. Negotiations are cur­

rently going on between Sohio and technology developers with the possi­

bility that one or more of these technologies will be tested with or in

place of the Sohio Process.

The steps involved in the Sohio process are:

(1) mining,

(2) conditioning,

(3) screening,

(4) extraction,

(5) recovery, and

(6) up-grading.

-64-

Figure IV - 1

Asphalt Ridge Tar Sand Deposit

LETC IN-SITU FIELD EXPERIMENT

R 20 E R 21 E R 22 E

I I I I I

The mining operation anticipated to be employed by Sohio for the

removal of the tar sand deposit on Asphalt Ridge is an open cut method.

Tar sand will be mined from a partially exposed pay zone averaging 36

feet in thickness. Mining will be done using bulldozers equipped with

ripper teeth to loosen the bitumen laden sand deposits. The loosened

material will be removed by front-end loaders. The mine will provide

two to three tons per hour of crushed tar sand ore to the pilot plant.

During the conditioning step fresh water is mixed with the crushed

tar sand and fed into the conditioner where mixing with a sodium car­

bonate solution takes place and bitumen is separated from the sand.

After the conditioning step, the sand is screened to remove over­

sized material. This material is returned to the conditioner while the

tar sand "pulp" is introduced into the extraction column. There, water,

solvent and sand are mixed and separated from the hydrocarbon stream.

The slurry of sand and water is allowed to separate with the sand being

sent to disposal and recovered water pumped to a water tank to be re­

cycled. The hydrocarbon solvent stream, having been separated from the

sand and water slurry, then undergoes further processing to extract the

solvent from the bitumen resulting in the recovery of 99 wt. percent of

the bitumen originally present in the tar sand. The pilot plant facili­

ty will produce one barrel of bitumen (42 gallons) per hour.

3. Market and Transportation of the Product

A market for raw bitumen already exists in Utah for paving asphalt,

however, with additional processing the upgraded bitumen can be produced

into a more valuable product and thereby extending its market. During

the pilot plant demonstration bitumen will be handled for distribution

to final destinations by tanker truck.

-66-

4. Water Requirements

The Green River will be the source of water for the pilot plant

facility on Asphalt Ridge. Sohio Natural Resources Company owns an

approved water right application to 3,600 acre-feet from the

Green River.

Net water requirements for the Sonio Process are anticipated to be

about 3.5 barrels of fresh water per barrel of bitumen or 39.6 gallons

of water per ton of tar sand. Recycling of water during the extraction

of bitumen is considered by company officials to be an essential feature

of the Sohio Process. This recycled water is used during the condi­

tioning step. Water loses for the Sohio process are 1.03 gallons of

fresh water per barrel of bitumen extracted.

5. Air Quality Impacts

The Sohio Development Plan indicates that the pilot plant facility

will comply with all applicable federal, state, and local air emissions

regulations. Dust generation will be controlled by wet suppression in

the mining area and paving of main access roads and other heavy traffic

areas. Emissions of sulfur dioxide and nitrogen oxides will be control­

led by use of low sulfur fuel for heating and boilers with appropriate

burner designs.

6. Socioeconomic Impacts

At this time, socioeconomic impacts of the proposed pilot plant

have not been addressed.

7. Program for Disposal of Waste Materials

For each ton of Sohio tar sand processed there will be approxi­

mately 0.87 ton of spent sand to dispose of. Therefore, at full pro­

duction there will be approximately 90,100 TPD or 30 million TPY of

spent sand for disposal.

-67-

During the mining process, overburden that is removed will be

stockpiled for future reclamation use upon completion of the pilot plant

program. Reclamation will involve replacement of overburden and pro­

cessed sand into the mined out area. The area will be graded in a

fashion that will be as near to the original contours as possible and

revegetated with Indian ricegrass, Utah sweetvetch, Winterfat, Russian

wildrye and Alkali sacton.

The ability to recycle process water will almost eliminate the need

to handle waste water. Process water that is generated for disposal

will be stored in lined evaporation ponds.

Sanitary wastes will be handled by an on-site packaged system. No

wastes will be discharged.

8. Construction and Production Schedules

Sohio proposes to implement a phased approach to the development of

the tar sand resource on Asphalt Ridge. The proposed approach calls for

the design and construction of a processing plant by the end of 1982.

Scale up of the process and construction of a commercial facility by

June 1989 is planned pending the outcome of the field process develop­

ment work.

Phase I will involve three tasks:

(1) completion of laboratory process development work,

(2) design of the pilot plant, and

(3) obtaining necessary permits and approvals, and completing

notification procedures.

The design of the pilot plant will require twelve months. This

work will involve detailed process and mechanical design of the condi­

tioning, screening, extraction, solvent recovery, sand dewatering, water

-68-

recycle, and material handling systems. Details of the mining opera­

tion, waste sand disposal, and environmental protection equipment will

be developed.

Necessary permits and approvals will be obtained. All notifica­

tions that need to be made will be performed during Phase I. Phase I

should be completed by the end of 1981.

Phase II will also involve three tasks:

(1) construction of the pilot plant,

(2) operation of the pilot plant, and

(3) completion of a commercial feasibility study.

The pilot plant will be constructed on cooperative area property

and will be operated for up to two years following construction. The

site has been used previously for pilot plant operations by others.

Associated with construction of the processing facility will be the

development of a surface mine that will provide tar sand to the facili­

ty. Topsoil will be removed and stockpiled for site reclamation in the

future.

An evaluation of the Sohio process for application to a commercial

operation will be performed upon the successful completion of the pilot

plant program. Assuming that the pilot plant program is successful, the

commercial feasibility study will require twelve months to complete.

The work will include technical and economic assessments of a commercial

scale operation. The results of this study will be the primary basis

for making a decision whether to proceed with design, construction, and

operation of a 5,000 to 25,000 BP0 commercial facility.

Phase II will require three years and four months overall to com­

plete. At the end of this period, Sohio will have the technical and

-69-

economic data necessary to move into Phase III. Phase III will involve

the completion of three tasks:

(1) design of the commercial facility,

(2) preparation of a detailed development plan, and

(3) acquisition of necessary construction permits and approvals,

and completion of all necessary modifications.

Phase III is expected to require two years and eight months to complete.

In Phase IV, the construction of the commercial facility will begin

as soon as the necessary permits and approvals have been received. This

will be near the end of 1987 based on the current schedule. Construc­

tion is expected to take eighteen months. Operation of the commercial

facility is projected to start in 1989. The facility will use Utah

Power and Light power and water from the Green River.

9. Project Participants

Sohio Natural Resources Company is the sole project participant.

B. Great National Corporation Project

Great National Corporation currently holds leases on state and

private tracts within the Sunnyside tar sand deposits in Carbon County,

Utah. The Sunnyside deposit is considered a major oil resource deposit

containing an estimated 3.5 to 4 billion barrels of in-place bitumen.

The Sunnyside deposit is considered an excellent prospect for develop­

ment due to a good surface minable resource, excellent pay-zone thick­

ness, high bitumen saturation, moderate overburden to pay-zone ratio,

• 32 low bitumen sulfur content, and good access by road and rail.

Currently, the Great National Corporation, in conjunction with

Ford, Bacon & Davis Utah, Inc., (FB&DU), has submitted a proposal for a

-70-

pilot plant development of a refinery grade crude oil extracting pro-

33 cess. This pilot plant would process 150 TPD of tar sand to produce

80 BPD of bitumen. The design of the proposed pilot plant is based upon

research work done at the University of Utah under the direction of

Dr. Alex Oblad and funded by DOE. Work done to date by FB&DU and Great

National using private funding has indicated that the technology and

process developed by the University of Utah is both technically and

economically feasible.

The scope of the pilot plant includes the design, construction,

testing, and operation of the combined hot water - thermal tar sand

process. The capacity of the pilot plant is to be 80 BPD requiring 150

tons of tar sand per day. The objectives of the pilot plant are:

(1) Demonstrate the feasibility of the hybrid process in an 80 BPD

pilot plant for the production of a snythetic crude suitable

for further refining.

(2) Collect operating data from the principal process equipment to

ascertain optimal process operating variables, i.e., flows,

temperatures, pressures, residence times, compositions, recy­

cle rates, and others.

(3) Study effects of various feed compositions on the principal

process equipment and the viability of producing hydrogen from

light gases to be used to hydro-treat the oil, to saturate the

olefins, and to remove nitrogen and sulfur.

(4) Study effects on process equipment, i.e., wear rates, resist­

ant material, maintenance schedules, etc.

(5) Determine the feasibility of constructing a facility to pro­

cess the tar sand on a commercial basis.

(6) Determine coke yield.

-71-

After the pilot plant is successfully demonstrated it is expected

that a commercial facility would be constructed to produce from 8,000 to

25,000 BPD. At full production the facility would require 103,200 TPD

or 34 million TPY of raw tar sand feed. Table IV-2 summarizes the

project data for Great National.

1. Tar Sand Resource

The Sunnyside tar sand deposit is located in Carbon County, Utah in

Townships 12, 13, and 14 South, Ranges 13, 14, and 15 East. The deposit

outcrops for nine miles along the southwest side near the top of the

Book Cliffs. The dominant lithologies in which the deposit occurs are

sandstone and siltstone. The formations in which the deposits are

located are the Upper Wasatch and the basal Green River, both of the

Eocene period. The areal extent of the entire deposit ranges from 35 to

34 90 square miles and contains three to 12 principal pay zones. Gross

thickness of the pay range is estimated between 15 to 500 feet and the

overburden thickness ranges between 0 to 500 feet.

The Great National Project leases are located in Sections 3, 4, 9

and 10 of T. 14 S., R. 14 E. The plant site is to be located in Section

17, T. 14 S., R. 14 E. The resource location and plant site is shown in

figure IV-2.

2. Processing Technology

Under the guidance of the University of Utah Department of Mining,

Metallurgical and Fuels Engineering two separate processes for tar sand

recovery have been developed. These processes are a hot water process

where a thick bitumen is produced, and a high temperature thermal proc­

ess where a low pour point synthetic oil is produced. The Great Nation­

al Project will use a hybrid of these processes. The work done to date

-72-

Table IV-2

SITE Carbon County, Utah Sections 3, 4, 9, 10, 17, T. 14 S., R. 14 E.

Approx. 1,200 acres on fee land

PRODUCTION

WATER REQUIREMENTS

EMPLOYMENT

PROCESS

8,000 to 25,

First Produc

Usage:

Source:

Peak Constru

Operation:

Mi ne:

Technology:

Spent Sand:

000 BPD

tion:

iction:

1989

3,600 acre-

N/A

N/A

N/A

N/A

Surface, hi extraction

28,800 to !

-feet/year

Dt water/thermal

90,100 TPD 9,500,000 to 30,000,000 TPY

MINING OPERATION Type:

Production:

Grade of Tar Sand:

Surface, strip mining

33,000 to 103,200 TPD 10,900,000 to 34,000,000 TPY

20 gal/yd3 or 11.3 GPT

-73-

Figure IV - 2

Sunnyside Tar Sand Deposit

R14E R15E

-74-

indicates that the hybrid process offers the potential for combining the

advantages of both processes and excluding the disadvantages of each.

Extraction of bitumen from the sand is optimally performed by the hot

water extraction process whereby the production of the final product is

through the thermal process.

The hot water extraction process is divided into two separate

phases, the digesting phase and the flotation phase. The digesting

phase is designed to disengage the bitumen from the solid sand. The

flotation phase is characterized by injection of a mixture of water and

air which allows the bitumen to "float" to the surface where it can be

skimmed off. This final bitumen is thick and has a high viscosity.

The thermal heating process is similar to the process of petroleum

cracking. Crushed tar sand is subjected to mild pressure and high

temperature in a reactor vessel. The product is then recovered as a

synthetic crude oil.

The proposed hybrid process is still in the laboratory stage. The

principle technical and economic issues which remain to be resolved and

which require larger scale verification are a marriage of the hot water

and thermal process, confirmation on overall yield and oil recovery from

the sand, confirmation on overall thermal balance, maintenance and wear

for certain critical equipment items, and suitability of the crude oil

produced for refinery feed stock. Company officials believe the pro­

posed pilot plant will be of sufficient size to provide usable data to

address these issues.

3. Market and Transportation of Tar Sand Product

As in the case for shale oil, tar sand products will most likely be

utilized regionally or at points east of the region. Tar sand products

-75-

are chemically similar to conventional petroleum, thus, they are quite

suitable as feedstocks to existing refineries. A portion of the tar

sand production may well be used to supply state and regional needs for

asphalt.

4. Water Requirements

The water requirements for this technology have not been firmly

established. Water requirements for the hot water process will probably

fall between two to five barrels of water per barrel of product. Water

requirements for the thermal process may be somewhat less. The question

of water supply has not been firmly answered at this time.

5. Air Quality Impacts

Specific air quality impacts have not been addressed. It is as­

sumed that particulates generated from mining activity will be similar

to other strip mines in the west. The hot water process is expected to

have virtually no emissions, while the thermal process may have small

amounts of sulfur gas emissions. Processing or conversion facilities

will have emissions similar to those experienced for equivalent proces­

ses in modern refineries.

6. Socioeconomic Impact

At this time, socioeconomic impacts of the proposed development

have not been addressed.

7. Program for Disposal of Waste Materials

The program for disposal of processed sand has not been specified

at this time. At full production there will be 90,100 TPD or 30 million

TPY of Spent Sand for disposal.

8. Construction and Production Schedules

The program plan and schedule for the pilot plant demonstration is:

-76-

(1) Phase I - organization, engineering, and design (four months).

(2) Phase II - detail drawings, procurement, and construction (12

months).

(3) Phase III - Component testing, start-up activities, data

taking, and continuous operation demonstration (12 months).

Thus, total time involved in the pilot plant demonstration is 28 months.

Current plans are to construct the commercial plant in three separ­

ate modules, each handling one third of the design output (approximately

25,000 BPD). The hot water digestion and flotation cell units would re­

quire five subunits in each of the modules. Expected life of the com­

mercial plant is 40 years.

9. Project Participants

The project participants are Great National Corporation and Ford,

Bacon and Davis Utah, Inc.

-77-

References

1. Prien, C.H., "Oil Shale Resources," in Pollution Control Guidance for Oil Shale Development, E.R. Bates and T.L. Thoem, eds., Environmental Protection Agency, July, 1979, p. 1-6.

2. Ibid., p. 1-8.

3. Ibid., p. 1-7.

4. Science and Public Policy Program, University of Oklahoma, Energy Resource Development Systems Report Volume III: Oil Shale Environmental Protection Agency, E.P.A.-600/7-79-060c, March 1979.

5. Ritzma, H.R., Utah's Tar Sand Resource: Geology, Politics and Economics, paper No. 107A, Symposium on Oil Shale and Tar Sands, American Institute of Chemical Engineers, Los Angeles, California, November 20, 1975.

6. Bunger, J.W., Utah State Science Advisor, Personal Communication, November, 1979.

7. U.S. Senate, Report by the Subcommittee on Synthetic Fuels of the Committee on the Budget, Synthetic fuels, U.S. Government Printing Office, Washington, D.C., 1979, p. 11.

8. Ritzma, H.R., Map 47: Oil-Impregnated Rock Deposits of Utah, Utah Geological and Mineral Survey, Salt Lake City, Utah, January, 1979.

9. Ritzma, H.R. Op. Cit., 1975.

10. Bunger, J.W., Development of Utah Tar Sands - A Status Report, Mines and Minerals Report #5, University of Utah, Salt Lake City, Utah, October, 1977, p. 10.

11. Thoem, T. L., Director, Energy Policy Coordination Office, U.S. Environmental Protection Agency, Memorandum, March 25, 1979.

12. Glassett, J.M., and, Glassett, J.A., Tar Sands Mining Methods, Erying Research Institute, Provo, Utah, August, 1977, p. 1-5.

13. Bunger, J.W., Utah State Science Advisor, Written Communication, November, 1979.

14. Sohio Natural Resources Company, Development Plan for the Ashphalt Ridge Cooperative Area, Sohio Natural Resources Company, October 12, 1979.

15. Leavell, L.D., Vice Pres., Santa Fe Energy Co., written communication to Senator Moroni Jensen, Chairman Tar Sand Task Force, Utah, March 24, 1980.

-78-

16. Marchant, L.C., Tar Sands Project Manager, Laramie Technology Center, U.S. Department of Energy, Presentation before the Utah Tar Sands Task Force, March 27, 1980.

17. U.S. Congress, H.R. 6478, A bill to amend the Mineral Leasing Act of February, 25, 1920, sponsored by McKay-McDade, 96th Congress 2nd Session, February 11, 1980.

18. Cameron Engineers, Inc., Shale Oil Status Report, Denver, Colorado,

July 1979, p. 20.

19. Ritzma, H.R., Op. Cit. 1979.

20. Bunger, J.W. Op. Cit. ref. 13.

21. Cameron Engineers, Op. City p. 21.

22. U.S. Dept. of Energy, Synthetic Fuels and the Environment: An En­vironmental and Regulatory Impact Analysis, Office of Technology

23. Weaver, R., "Water-Energy Policy Issues Facing Utah", in Utah Economic and Business Review, Vol. 38, No. 9, September, 1978, p. 2.

24. Petzrick, Paul, Oil Shale Operations Manager, U.S. D.O.E., personal communication, April 11, 1980.

25. White River Shale Project, Detailed Development Plan for Federal Lease Tracts U-a and U^, Vol. I and II, White River Shale Project, June, 1976.

26. Ibid., Vol. I., p. 1.5-5.

27. Ibid., Vol. II., p. 7.17-3.

28. Paraho Development Corporation, Proposal for the Design arid Demon­stration Plan for a Surface Oil Shale Retorting Module, Vol. I Proposal Abstract, Paraho Dev. Corp. July 30, 1979.

29. Tosco Corporation, Sand Wash Project, Tosco Corporation, Vernal, Utah, January 1978.

30. Hutchinson, D.L., Geokinetics, Inc., Personal Correspondence, November, 1979.

31. Sohio Natural Resources Company, Development Plan for the Asphalt Ridge Cooperative Area, opt. cit.

32. Glassett, J.M., and, Glassett, J.A., The Production of Oil From Intermountain West Tar Sands Deposits, Erying Research Institute, Provo, Utah, March, 1976, p. 64.

33. Ford, Bacon and Davis Utah Inc., Proposal for Pilot Plant Construction and Operation of Crude Oil Production from Utah Tar Sands, F.B. & D. Utah Inc., January, 1980.

34. Ritzma, H.R. op. cit., 1979.

-79-