&EPA
United States
Environmental Protection
Agency
Office of
Energy, Minerals and Industry
Washington DC 20460
EPA-600/9-79-025
July 1979
Research and Development
Program Conference Report:
Oil Shale
Proceedings of the
EPA/Industry Forum
January 23-24, 1979
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EPA-600/9-79-025
July 1979
EPA PROGRAM CONFERENCE REPORT:
OIL SHALE
Proceedings of the EPA/Industry Forum
January 23-24, 1979
Prepared by
H.F. Coffer
C.K. GeoEnergy Corporation
5030 Paradise Road
Suite A103
Las Vegas, Nevada 89119
Alden Christiansen
Cincinnati, Ohio 45268
William N. McCarthy, Jr.
Office of Energy,
Minerals and Industry
Environmental Protection Agency
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EPA REVIEW NOTICE
This report has been reviewed by the Office of Research and Development, EPA, and approved
for publication. Approval does not signify that the contents necessarily reflect the views and policies
of the Environmental Protection Agency, nor does mention of trade names or commercial products
constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Information Service,
Springfield, VA 22151.
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FOREWORD
Within EPA's Office of Research and Development (ORD) is the Office of Energy, Minerals and
Industry (OEMI). This office was created in response to the need for priority development of coal
and alternative energy sources as a result of the Arab oil embargo of 1973-1974. The Industrial
Environmental Research Laboratory (IERL) within OEMI at Cincinnati, Ohio, has the responsibility for
implementing OEMI's energy program pertaining to oil shale. The major goal of this research facilities'
program is the assessment and development of control technology in accordance with the mandates laid
down by the Clean Air Act (CAA), the Clean Water Act (CWA), the Resource Conservation and
Recovery Act (RCRA) and the Toxic Substances Control Act (TSCA). Whereas the objective of this
program is to service the research needs of the regulatory offices of EPA, the program must also be
responsive, in a time frame not to impede commercialization, to the Department of Energy's (DOE)
need to develop the emerging energy technologies in an environmentally acceptable manner. OEMI
supports the EPA regulatory offices by providing research data and criteria information for the
standard setting function. OEMI supports DOE and the other federal agencies engaged in energy-
related research and development through funding of cooperative efforts, and by assessing and
providing expertise for the development and implementation of the best available control technology
(BACT).
The EPA/Industry Forum meeting that is covered in this report is one of two that have been
planned for this year. The objective of these meetings is to bring together, in forum style, the
developers of oil shale retorting processes and the large owners of shale oil properties with the
research and regulatory personnel in EPA:
o for discussion of the environmental concerns that are limiting faster development,
o for exploration of cooperative research efforts that could mitigate these concerns, and
o for effecting other activities that would foster clear and worthwhile communications
between government and industry.
It has been my impression that the forum is succeeding in the above goals.
Steven R. Reznek'
Deputy Assistant Administrator
Energy, Minerals, and Industry
in
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PREFACE
The U.S. Environmental Protection Agency is involved in oil shale research and development
through projects for which it provides funds, and stays abreast of projects funded by other
governmental and industrial sources. Research provides data for defining ecological and health
effects and for developing cost-effective control technology that can be used by government and in-
dustry to minimize degradation of the environment.
This report presents the proceedings of the first EPA/Industry Oil Shale Forum.
This report is submitted in partial fulfillment of Contract Number 68-01-5029 by C.K. GeoEnergy
Corporation under the sponsorship of the U.S. Environmental Protection Agency's Office of Energy,
Minerals and Industry, Headquarters, and its Industrial Environmental Research Laboratory,
Cincinnati, Ohio.
Funding for the publication of this report was accomplished under EPA Grant R-806156 with
the Denver Research Institute.
iv
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ABSTRACT
The first meeting of the joint EPA/Industry Forum, which addressed research, technical and
regulatory problems relating to oil shale, was held in Denver, January 23-24, 1979. Attending were
federal representatives from the EPA and DOE, state representatives from Colorado, and personnel
from all of the companies active in oil shale development and research programs. The main purpose
of the meeting was to establish a closer working relationship between the EPA and industry and to
develop better channels of communications.
Alan Merson, regional administrator of the EPA, and DOE's deputy undersecretary for commer-
cialization, Jackson Gouraud, outlined the government's plans and schedules for oil shale development.
Both stressed the need for an oil shale industry, while insisting that a few commercial-sized modules
should be built initially to provide real data on potential environmental problems from large-scale
developments. These presentations elicited a number of questions from industry representatives.
These questions were frankly and succinctly answered.
Informative presentations also were made by the chief of the Oil Shale Environmental Assessment
Program, Alden Christiansen, and the EPA's Region. VIII deputy director of the Office of Energy,
Terry Thoem, who reviewed the research program and discussed the current and proposed regulations
relating to oil shale.
On the industry side, an excellent overview of the progress of oil shale development was pre-
sented at the First EPA/Industry Forum by representatives of those companies actively working in
this area: Colony Development [Les Ludlam], Equity Oil [Paul M. Dougan], Geokinetics [Steve
Mankowski], Multi Mineral Corporation [Ben Weichman], Occidental (C-b) [W. F. McDermott], Rio
Blanco (C-a) [J. B. Miller], Sohio [Harry Pforzheimer], Superior Oil [John H. Knight], TOSCO
[H. Michael Spence], White River [Rees Madsen], and Union Oil [Ron Bissinger]. Discussions des-
cribed the current status of each of the projects and projected future activities.
Penetrating questions and discussions characterized the interchange between industry and govern-
ment personnel throughout the two-day meeting. From the response of both government and industry
representatives, it was clear that the meeting was successful. Such open exchanges of information
and opinion should point the way to cooperation between the EPA and industry in bringing oil shale
into production in a manner that is both feasible and environmentally satisfactory.
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ACKNOWLEDGMENTS
The Environmental Protection Agency wishes to acknowledge its gratitude and appreciation to the
managements of the oil shale companies or ventures for their participation at the first meeting of the
EPA/industry oil shale forum. The management of EPA's oil shale program recognizes that the forum
concept would not be successful without the full and enthusiastic participation of the overall industry.
The authors wish to thank Paul Westcott of the Denver Research Institute for supervision of the
editing and camera copy preparation, and Paul E. Mills, lERL-Ci, who provided the financial and
administrative support to the Denver Research Institute. The Denver Research Institute Word
Processing Center also deserves thanks for its invaluable help in revising and producing the camera
copy.
VI
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CONTENTS
Page
Foreword m
Preface iv
Abstract v
Acknowledgment vi
Figures viii
Introduction/Executive Overview 1
Welcoming Addresses 5
Introduction 5
EPA, Alan Merson 5
EPA, Kurt Jakobson 6
DOE, Jackson Gouraud 6
Questions 7
Company Oil Shale Project Status 9
Colony Development, Les Ludlam 9
Equity Oil Co., Paul Dougan 13
Geokinetics, Steve Mankowski 15
Multi Mineral Corp., Ben Weichman 16
Occidental (C-b), Bill McDermott 17
Rio Blanco (C-a), Elaine Miller 18
Sohio, Harry Pforzheimer 19
Superior, John Knight 23
TOSCO, Mike Spence 27
Union Oil, Allen Randle 27
White River, Rees Madsen 28
EPA, DOE, and Colorado Status Presentations 33
Talley Industries, Andy Decora 33
Colorado Department of Natural Resources, Robert Siek 34
Environmental Advisory Panel, Henry O. Ash 36
EPA Research Program, Alden Christiansen 37
EPA Regulations, Terry L. Thoem 41
Permitting Process, Harry McCarthy, SAI 47
General Discussion 49
Introduction, Hank Coffer, C.K. GeoEnergy Corporation 49
Harry Pforzheimer, Sohio 49
Elaine Miller, Rio Blanco (C-a) 49
Alden Christiansen, EPA 49
Bob Thomason, Occidental (C-b) 49
Rees Madsen, White River 50
Charlie Sullivan, Superior 51
John Maziuk, Mobil 51
Eugene Harris, Guidance Document Comment 51
Hank Coffer, C.K. GeoEnergy Corporation 52
Terry Thoem, EPA 52
List of Attendees 55
vn
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FIGURES
Number
1 Areas of Dawsonite and Nahcolite 25
2 Structural Cross Section A - A' Showing Pilot Adit and Pilot Mine .'.'.'.'.'.. 25
3 Block Diagram Multi-Mineral Process '.'.'.'.'.. 25
4 Photosorting System '.'.'... 26
5 Conceptual View of Circular Grate Retort 26
6 Conceptual Design Soda Ash Plant 26
6-A Alumina and Soda Ash Recovery Process 26
7 WRSP Location 31
8 WRSP Organization Chart 31
9 Monitoring Stations and Drilling Locations 31
10 State of Utah Proposed Dam and Reservoir on White River 31
viii
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INTRODUCTION/
EXECUTIVE OVERVIEW
FIRST MEETING OF JOINT EPA/INDUSTRY
OIL SHALE WORKING GROUP
Denver Stouffer Inn
Denver, Colorado
January 23-24, 1979
Seventy-five representatives of industry,
the Environmental Protection Agency, the De-
partment of Energy, and the Colorado state
government participated in the first EPA/
Industry oil shale forum. Highlights of the
meeting included presentations by the EPA
Region VIII administrator, Alan Merson, and the
DOE deputy undersecretary for commercializa-
tion, Jackson Gouraud, and reviews of eleven
active oil shale development projects by repre-
sentatives of the operating companies.
A brief summation of each speaker's re-
marks follows.
EPA-REGION VIII, ALAN MERSON, REGIONAL
ADMINISTRATOR
Merson summarized the types of environ-
mental questions that need answering before a
large oil shale industry can be developed.
These include: groundwater quality and con-
tamination, disposal and revegetation of spent
shale, NOX and SO2 contamination, air quality,
trace element concentrations, applicability of
pollution control and technology, and the
population growth associated with oil shale
development.
Merson believes that answers to most of
these questions can be found by a rigorous
testing program built around prototype
commercial-scale facilities. Facilities capable of
producing about 150,000 BOPD would be ade-
quate to determine the environmental impact of
an oil shale industry. He strongly advocates
working jointly with industry and DOE in order
to achieve commercialization in an environmen-
tally acceptable manner.
EPA-WASHINGTON, KURT JAKOBSON
SENIOR STAFF ENGINEER
Jakobson welcomed the attendees and
extended greetings from Stephan Gage. After
outlining the types of discussions hope for,
Jakobson expressed the desire for closer co-
operation between the EPA and the oil shale
industry.
DOE, JACKSON GOURAUD, DEPUTY-
UNDERSECRETARY FOR COMMERCIALIZATION
Gouraud outlined the steps DOE is taking
to get a commercial oil shale industry underway.
It is expected that the $3.00/bbl tax credit will
be enacted by this session of Congress, and
hopefully, with this inducement, the industry
will move forward.
Gouraud believes that the development of a
±50,000 BOPD modular commercial facility by
1985 represents a sensible approach. He
stressed that an oil shale industry is needed,
but it should only be developed through proper
testing to assure that extensive damage to the
environment does not occur.
COLONY DEVELOPMENT OPERATIONS,
LES LUDLAM, MANAGER
Ludlam reviewed the history of the Colony
project. It began in 1964 and progressed
through the completion of a semiworks Tosco II
retort capable of processing 1,000 ton/day of oil
shale. A design of a commercial-size plant was
begun by C.F. Braun and Company in 1972.
Construction of a 60,000 ton/day commercial
complex was to have been started in 1975, but
inflation raised projected costs from $350 million-
to $900 million, and construction plans were
suspended.
Since 1974, Colony has worked to maintain
its ability to reactivate construction plans.
They have continued the required permitting
process.
Ludlam reviewed Colony's environmental
work and pointed out some of the problems
encountered with air quality, water quality, and
solid waste disposal. He advocated methods
where industrial-scale impacts could be ac-
curately measured.
EQUITY OIL COMPANY, PAUL DOUGAN,
COOPERATIVE SECRETARY
Dougan reviewed the plans for the Equity/
DOE experiment in the Piceance Creek Basin.
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Steam at 1,000°F and 1,500 psi will be injected
into the leached zone to retort the oil shale in
place. Over a two-year period approximately
1 trillion BTU of heat will be injected.
A typical five-spot well pattern, with
spacing of 68 feet between injection and produc-
tion wells, will be utilized. A bottom hole
temperature between 900°F and 950°F will be
maintained.
Dougan described the experimental plans
and the environmental analysis. Environmental
impact of this "true" in situ process would be
expected to be minimal, since natural gas is the
fuel and all gaseous products will be burned.
It is hoped that the experiment can be started
early this year.
Environmental monitoring is continuing.
About 250 people are now working at C-b.
This force will grow to about 400 by midyear.
Traffic problems have been reduced by provi-
ding three-shift bus service to the site from
both Meeker and Rifle.
McDermott reviewed the work on in situ
combustion at the DA site. Retort #6 is cur-
rently being burned. This retort is 52 inches
square by 260 feet high, and it has produced
23,000 barrels of oil. It is currently producing
about 300 BPD.
Occidental is deeply involved in an eco-
nomic evaluation of C-b. There is concern about
changing conditions, as well as potential EPA
regulations, that may affect the economics.
GEOKINETICS, STEVE MANKOWSKI
STAFF ENGINEER
Mankowski discussed the Geokinetics/DOE
experiment in Utah. An in situ retorting
process designed for thin shale beds with no
more than 150 feet of overburden is being
used. The shale is about thirty feet thick and
yields 20-23 gal/ton.
Retorts are prepared by heaving the
overburden with explosives. To date eighteen
retorts have been prepared and eleven burned.
Total production has been about 5,000 barrels
of oil, which represents 50% recovery from the
broken shale.
RIO BLANCO OIL SHALE, BLAINE MILLER,
PRESIDENT
Miller reviewed the status of the Rio
Blanco project. The modular development phase
of this project has begun, entailing the prepar-
ation and burn of five retorts ranging in size
from 30 x 30 x 140 feet to 100 x 100 x 400 feet.
Several rubbling schemes will be tried in order
to optimize particle size and permeability distri-
bution. Plans call for obtaining sufficient
retorting data by 1982 to enable a decision on
proceeding with a commercial plant. If favor-
able results are obtained, a 76,000 BPD plant
would be constructed, with scheduled operation
beginning in 1987.
MULTI MINERAL CORP., BEN WEICHMAN,
PRESIDENT
The Multi Mineral Corporation has proposed
a joint test, with the government, of their inte-
grated in situ process. Weichman believes that
their process is ideally suited for the lower
shale zone of the Piceance Basin, which con-
tains nahcolite and dawsonite.
In the Multi Mineral proposal, the eight
foot diameter shaft drilled into the oil shale by
the Bureau of Mines would be used. A bulk
sampling program would be conducted to pro-
duce about 5,000 tons of nahcolite for use in a
full-scale power plant scrubbing experiment.
In addition, they would mine out stations for
rock mechanics measurements in the lower zone.
OCCIDENTAL OIL SHALE, BILL MCDERMOTT,
EXECUTIVE VICE-PRESIDENT
Occidental began actual work on the "C-b"
tract in November 1977. Two large production
shafts and a small ventilation shaft are
scheduled for completion in January 1981.
SOHIO NATURAL RESOURCES,
HARRY PFORZHEIMER, PROGRAM DIRECTOR
Pforzheimer reviewed Sohio's involvement
in oil shale and the experience leading up to
and through the Paraho design and operation.
He discussed the various types of incentives
that could be used by the federal government
to help in the development of an oil shale
industry.
Pforzheimer does not believe that the
environmental problems are insurmountable,
and, therefore, believes that we should proceed
to commercial-size modules. This would provide
government and industry with real data for a
rigorous evaluation of the economics of shale oil
production and any potential environmental
impacts.
SUPERIOR OIL COMPANY, JOHN KNIGHT
ASSISTANT DIVISION MANAGER
Knight reviewed Superior's development of
the multi-mineral process. During a five year
testing and development project, Superior has
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tried to consummate a land exchange program in
order to obtain a block of land suitable for an
economical mining configuration.
Superior has concentrated on recovery of
the dawsonite and nahcolite along with the oil
from oil shale. In pilot retorting a circular
grate was used with which a high thermal
efficiency was obtained (product yields over
98%).
Knight discussed interactions with the EPA
and outlined the major areas of concern to
Superior. He felt that the lack of long-term
stability in environmental laws and regulations
was the major problem.
TOSCO, MIKE SPENCE, ATTORNEY AT LAW
Spence reviewed the work that TOSCO had
done in trying to get an oil shale project
started on its Utah holdings. A unit has been
formed, and site development is scheduled to
start in 1979.
TOSCO is looking at various problems such
as water, transportation, environmental issues,
and socioeconomic concerns that must be con-
sidered in a commercial project.
UNION OIL, ALLEN RANDLE,
MANAGER OF RETORT OPERATIONS
Randle reviewed the work done by Union
in preparation for building a commercial-size
retort. There are too many unknowns to justify
moving forward on a full size 50,000 barrels/day
plant at this time. Instead, a single, full size
commercial retort is being considered.
Union feels that the proposed $3.00 per
barrel tax credit, if enacted, will allow the
building of a single retort module. This will
provide better data on potential environmental
impacts and full-scale economics. Union has
applied for the necessary permits so that is can
be ready to proceed when the $3.00 per barrel
tax credit is enacted by Congress.
WHITE RIVER, REES MADSEN,
ENVIRONMENTAL COORDINATOR
Madsen outlined the status of the White
River project, which is owned by Sohio,
Phillips, and Sun. Work thus far has involved
gathering baseline environmental data and
drawing up a detailed development plan.
The White River project is presently in a
holding pattern. It was originally delayed by
environmental problems, but now the major
problem is land ownership: state vs. federal.
This is currently being considered in federal
court.
Madsen presented some recommendations
for helping to solve the environmental problem:
(1) reduce the number of permitting agencies,
(2) complete the EPA guidelines document,
(3) revise the ozone standard, (4) resolve how
process shale fits in with the Conservation
Recovery Act, and (5) put a freeze on com-
pliance standards so that they will not be
constantly changing.
DOE-LARAMIE ENERGY TECHNOLOGY CENTER,
ANDY DECORA, DIRECTOR
Decora reviewed the work done under the
Talley contract near Rock Springs, Wyoming.
The Talley experiment was designed as a true
in situ process where the oil shale would be
broken up by use of an explosive in a hydrau-
lically fractured system. In the experiment, a
60,000 pound explosive charge was detonated in
a 40 foot shale bed at a depth of about 200 feet.
The permeablility of the shale following the
explosion was not as high as expected, and the
contract has been terminated.
COLORADO DEPT. OF NATURAL RESOURCES,
ROBERT SIEK, DEPUTY DIRECTOR
Siek outlined Colorado's approach to get-
ting modular testing and the development of the
oil shale industry underway. Ten project roles
have been defined to cover the interaction of
state and local governments with industry in
efforts to develop the oil shale resource.
Attempts are being made to simplify interactions
of the various agencies and departments and to
minimize unnecessary conflicts. Early informa-
tion on proposed developments is needed so that
all who are concerned can be fully informed.
ENVIRONMENTAL ADVISORY PANEL,
HENRY O. ASH, EXECUTIVE DIRECTOR
This panel operates under the Federal
Advisory Act. Its members are representatives
of departments and agencies of the federal,
state, and county governments. Its new mem-
bership will include two industry represen-
tatives .
EPA-IERL, ALDEN CHRISTIANSON DIRECTOR,
PROGRAM OPERATION OFFICE
The purpose of the EPA is to maintain and
enhance environmental quality and protect
human health and welfare. It carries out a
comprehensive research program to provide
technical data for standards and regulations,
standardized methods of measurements, pollution
control technology, and methodologies to balance
environmental management options against com-
peting needs.
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EPA's emphasis on energy related research
has increased, with most of its funding going to
research in the areas of coal, oil, and gas.
Programs related to oil shale are conducted at
over one-half of EPA's fifteen laboratories.
These programs include instrument development
and quality assurance procedures as well as
field monitoring.
Christiansen reviewed the activities of the
various EPA research labs as they affect oil
shale development. These labs are interested
in determining, as soon as possible, any poten-
tial environmental impact resulting from
development of an oil shale industry.
EPA is currently working on a guidelines
document for oil shale development. This will
include preliminary regulatory implications and
environmental goals for the industry. It is
planned to bring industry into the review of
this document. A draft will be submitted to
each participant in the early summer asking for
their comments. It is hoped that by identifying
environmental problem areas early, oil shale
development can proceed without delays.
Drinking Water Act, the Resource Conservation
and Recovery Act (RCRA), and the National
Governmental Policy Act, which regulates pilot
module oil shale facilities to insure compliance
with existing standards.
After a presention of suggested interim
guidelines for air, water, and solid and haz-
ardous wastes, Thoem discussed a number of
issues that have been raised in the past by the
oil shale industry. These included: (1) num-
ber of permits, (2) high background air quality
levels, (3) inclusion of fugitive dust, (4) con-
cern over soon-to-be proposed New Source
Performance Standards (NSPS) for electric
facilities using shale oil, (5) definitions of
hazardous wastes, and (6) uncertainties in the
regulatory framework.
There has been concern that the EPA's
rules are not clear or concise. The EPA is
trying to remedy this by preparing the oil shale
guidance document discussed by Christiansen.
Because of our need for petroleum, the EPA
supports the limited development of oil shale.
EPA-REGION VIII, TERRY L. THOEM,
DIRECTOR
Thoem reviewed EPA's regulatory program.
Congress established environmental legislation
that also offers a framework for state regu-
lations .
EPA has a research program that provides
a data base to enable it to fulfill its regulatory
responsibilities. The goals are to protect the
environment while allowing growth of an oil
shale industry- Under the Clean Air Act, oil
shale developers must employ best available
control technology (BACT), must not violate the
National Ambient Air Quality Standards
(NAAQS), must abide by the Prevention of
Significant Deterioration (PSD) regulations,
must not degrade the visibility in Class I areas,
and obtain baseline data prior to applying for a
PSD permit.
Thoem also discussed other legislation,
including the Clean Water Act, the Safe
GENERAL DISCUSSION
A number of questions were asked regard-
ing the regulations and their interpretations.
These are covered fully in the minutes along
with discussions of what this forum could do to
improve communications between industry and
the EPA.
A brief disussion of the permitting problem
was presented by Harry McCarthy of SAI.
Under contract to DOE, a pert chart has been
prepared for obtaining permits required by the
various agencies.
Further discussion ensued about the EPA
oil shale guidance document and how industry
could contribute to it. A draft of the document
will be submitted to the participants, before the
next meeting, for review, and it will be a sub-
ject for discussion at that meeting. The time
frame for completion of the document is early
summer 1979.
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WELCOMING ADDRESSES
The meeting was opened by Henry F.
Coffer, chairman, at 9:00 a.m. Attendees,
listed in the Appendix, were asked to stand, to
introduce themselves, and to give their company
affiliation.
Henry Coffer welcomed the seventy-five
persons attending. He announced that eleven
companies working on oil shale projects would
present talks describing their present status
and their plans for the future. The talks will
include an emphasis on environmental problems
and other concerns. He said the meeting was
designed to encourage further discussions
between the EPA and industry.
The first speaker, Alan Merson, Regional
Administrator, EPA-Region VIII, was introduced
by Coffer.
EPA-REGION VIII, ALAN MERSON,
REGIONAL ADMINISTRATOR
Last Friday I met with the governor of
Washington, and I think that I well understand
some of the concerns about EPA and some of
the hostility that may exist with EPA's role in
dampening progress in energy development. I
talked to the governor at great length to under-
stand their state's feelings about our agency
and environmental legislations that mandate our
actions.
Basically, I am just a figurehead. I am
not a technical person, nor do I have any
strong biases. I think EPA positions on issues
ought not to be the result of any deeply held
personal biases but basically an outgrowth of
our mandated legislation. The first principle is
one of honesty, recognizing things for what
they are.
To begin with, we have to make a state-
ment that mining and the conversion of oil shale
are going to degrade air quality, going to con-
sume water resources, may degrade the surface
and perhaps even groundwater quality. They
are going to create solid and hazardous waste,
and they are going to create significant popu-
lation growth in a rural setting that may not be
able to handle it very well. I think that is just
recognizing facts as they are. Does that mean
that we should not proceed with the develop-
ment of this resource? Of course not. Any
development is going to create problems. The
real issue is how we cope with these problems.
What is the magnitude of the problem, and what
can we bring to bear on solving the problem
that will mitigate those impacts. That really is
the concern of the EPA, and I do not think it
is fair to see us as taking either a pro or
antidevelopment stance with respect to this.
Your job, in industry or DOE, has a positive
obligation to push ahead and explore ways of
getting the job done in a fashion that, hope-
fully, can meet some of the concerns that we
are discussing. The kinds of questions that
have to be considered, from an environmental
standpoint, are:
1. How much groundwater will be inter-
cepted during mining? (Some of
these questions are being answered
by people engaged in some prototype
projects right now.)
2. What will the quality of potential
discharges be?
3. Can groundwater quality be protected
during and after in situ retorting?
4. Can processed shale be disposed of
properly without degrading ground or
surface water quality?
5. Will revegetation of processed shale
be successful over the long term? (I
have had a chance to visit some of
the sites in the Piceance Basin and
there are examples of revegetation on
retorted shale.)
6. What are the concentrations of various
sulfur species in retort off-gas
streams?
7. What will be the air quality and
visibility impacts on the Flat Tops
Wilderness Area, which lies east of
the Piceance Basin. (In other words,
how far can we go in containing
whatever air impacts there will be so
that the Class I status for that wil-
derness area is not interrupted?)
8. What are the expected trace element
concentrations in air, water, and
solid waste residual streams?
9. Is conventional pollution control
technology directly applicable to oil
shale residuals? Is it effective?
(How far can we go to encourage
innovations, perhaps at the expense
of maintaining levels of quality, with
respect to air and water? What is the
mix between experimentation and
trying to maintain at least a certain
threshold of air quality?)
10. What is the expected population
growth associated with the develop-
ment of an oil shale industry?
These are all questions that you have been
asking, and that we have been asking. I think
the real nut now is to figure out, jointly, the
best way to answer these questions. I am
convinced that answers can be found. Some
can be found without doing anything. You can
go out basically with some limited-scope, field
investigations doing some theoretical research
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work and answer some of these questions. The
remaining questions will have to be answered
through rigorous testing programs and data
analysis performed on representative prototype
commercial-scale facilities. It is clear that
EPA's position is to have industry construct
and operate commercial-scale modules of dif-
ferent surface and in-site retort technologies.
Representative mining rates and methods should
be evaluated.
We have been asked what size facilities,
how much, what would be the maximum that you
think could be supported on this basis? We are
arriving at about 150,000 barrels per day being
a scale that could be reached prior to having
the ultimate federal and state decisions being
made on additional growth of the industry. We
have a lot of confidence in the prototype
"Leasing Program." We think it is a well de-
signed program that should proceed to com-
pletion before additional leasing is proposed. It
provides enough maneuvering room and will
provide a good enough basis for answering
these questions. We ought to take it seriously,
and complete that job before we go ahead and
make it a total commitment for a full-scale
production.
I suspect that most of you representing
industry probably would like to have the an-
swers to these questions as well. We are very
concerned about some proposals to proceed to
500,000 barrels per day by 1985. There is a
feeling on our part that we will not have the
answers to the questions I have recited if we
proceed on that basis. There are too many
uncertainties associated with oil shale develop-
ment to permit such a scale this soon. It seems
foolish, however, not to proceed with the
prototype facilities, with some commercial-scale
modules now, so that we get the answers we
need. In talking with Governor Ray of
Washington, while she is very prodevelopment
and concerned with rapid development of energy
resources, she is also zealous to guard state
prerogatives in resource development. It is a
tricky area, because we are dealing with both
federal and state concerns, and I think there
will be a bad atmosphere generated if the
federal government appears both on the envi-
ronmental front and on a prodevelopment to be
overriding state interest in this resource. I am
interested in hearing from industry and Jackson
Gouraud's view about the DOE's approach to the
issue. My feeling is that we can work together,
and in the interest of the American people, we
can proceed now with development to get us on
the road to commercialization and also answer
the environmental questions.
EPA-WASHINGTON, KURT JAKOBSON,
SENIOR STAFF ENGINEER
Thank you for showing an interest in our
nation's '; energy future by coming here to
Denver to help out with the country's energy
technology development. Today and tomorrow
we will be discussing those problems that are
influencing the commercialization of this coun-
try's oil shale development. We will find out
what the EPA is doing in research and develop-
ment to eliminate the problems, and we hope
that you will assist us by sharing your
evaluations of these efforts. We will be
showing you the type of resources that we have
available to assist you in solving generic devel-
opment problems. We will learn how EPA
interfaces with the Department of Interior's area
oil shale supervisor's office, and which require-
ments the EPA feels obligated by law to impose
on these developments. We will also be given
some insight as to our affirmative application
processing, which should be generally helpful
to you.
We have invited the Department of Energy,
which is represented today by the undersecre-
tary of commercialization, Jackson Gouraud.
Secretary Gouraud will review DOE's time plans
for a commercialized industry evaluating his
priorities with respect to priorities of other
emergent energy technology and world energy
supplies. The purpose of this meeting, the
first of a planned series of interactions between
industry and the EPA, is to enlist your cooper-
ation and join federal/industry efforts that will
expedite the collection of information to provide
the remaining answers concerning environmental
uncertainties.
To the extent that you are willing to
commit your firm and to agree that such a
commitment is possible, rests the effectiveness
of this endeavor. Dr. Gage has asked me to
assure you that he intends to take a personal
interest in and assume a continuing responsi-
bility for the success of each and every project
that we initiate. It is his hope that you will
adopt the same philosophy. With this I think
we are interested in hearing the technical
presentations.
Dr. Coffer introduced Jackson Gouraud,
deputy undersecretary for commercialization,
DOE.
DOE, JACKSON GOURAUD, DEPUTY-
UNDERSECRETARY OF COMMERCIALIZATION
I would like to discuss with you DOE's
position on oil shale. I respect the modesty of
Alan Merson's comment that he is a figurehead.
It is my impression that an EPA regional admin-
istrator has more power than do most agency
secretaries, and there are times when I wish we
had the solid clout he does.
Last April, I met here with representatives
of the oil shale industry as well as the EPA,
and listened to statements of what industry
wanted in the way of oil shale support. At
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that time, industry stipulated that if the federal
government would allow a $3.00 tax credit and
provide entitlement treatment for oil shale (if
there is still an entitlement program), these
would be sufficient to move the industry
forward.
As we all know, the oil shale industry has
been about to move forward for the last twenty
years, but has never really taken any substan-
tive steps to do so, despite various efforts that
have been made. So we incorporated the indus-
try statement into formal legislation to be
presented to Congress in February along with a
supporting Environmental Impact Statement.
As far as I know, we are doing our part.
If you do not do your part, it will probably be
the last time we can be led down this "garden
path."
As recently as three weeks ago, members
of Congress said, "I don't believe it. They'll
just say three dollars; then they'll turn around
and say four, and if they get four they'll want
five." I personally called half a dozen of the
companies that are represented here, and had
assurance that they intended to move with this
credit if it were allowed.
As you know, since April we have been
structuring what I consider an intelligent effort
with respect to commercialization. We have
defined those technologies that we think are
important to pursue. The secretary identified
eight of them as winners. Oil shale was not
included for a reason that I will mention
shortly.
We have appointed a resource manager
(industry refers to this position as "product
manager") to head each technology, giving a
point of focus within the department to each.
This is expected to encourage development.
Shale oil production is one of these tech-
nologies .
In all the documents written—concept
statement, readiness report, etc.--as well as in
the government's role and our own perception
of reality, the environmental issues absolutely
govern. The development must be carried
forward from an environmental point of view;
otherwise, it just will not happen.
I should say at this point that we do not
sustain any such unrealisitc goal as half-a-
million barrels per day by 1985. The depart-
ment is perfectly prepared to accept your
150,000 barrels per day as a reasonable goal for
1985. I absolutely endorse the concept, along
with Secretary Schlesinger, that we have to
have in place a reasonable commercial facility.
Hopefully, too, the EPA can make intelligent
appraisals of the technology.
Obviously, the State of Colorado is critical.
We are very conscious that no one is going to
allow an influx of larger numbers of companies
working in the western portion of the state in
an unstructured and uncontrolled manner. DOE
will not support it; the governor will not sup-
port it, and I do not think you gentlemen are
going to allow it.
I believe, however, that in the low six
figure range (under 150,000 barrels) we can
get a couple of plants going, get other modules
on test, and hopefully have a commercial plant
with both in situ and surface retorting working
by 1985. The legislation that is going forward
will have a sunset clause, in that if you are not
in business by a given date, possibly within
the 1980 decade, you will not be entitled to the
same treatment. There also will be a phase-out
with respect to the price of oil.
Additionally, Congress appropriated
$15 million to move ahead with other projects.
The intent of Congress was clear, and these
efforts will all proceed in tandem. What I
would like to see developing in respect to the
state, the EPA, and industry, is careful,
prudent, organized progress on what must be
developed in this country. We have to have an
oil shale industry, but we must develop it
properly so that everything else does not spoil
in the meantime. That is the position of the
Department of Energy.
We can only do so much. We can create
budget incentives; we can encourage industry
to move; we can take a position in regard to
the State of Colorado and work closely with its
people. But we are not going to do anything
that the Environmental Agency of Colorado
would find objectionable.
I trust that I have clarified the position of
the government on this matter. Many people
are interested, myself particularly. We will do
what is sensible. We really do need some sort
of mechanism at your level so that we can
frequently touch base with each other to keep
up with what is going on.
Question: (Dick Lieber, Rio Blanco Oil Shale)
Due to limited development by 1985,
we believe that it will be too early to
get any significant production by the
late 1980s. Consequently, we will
not be able to take advantage of the
$3.00 tax credit incentive.
Answer: I appreciate your point. We are
trying to get production by 1985,
and we want to assure that com-
panies will be protected in their
early investments. We will try to
work out the necessary language to
accomplish these goals.
Question: (Bill Daniel, Tenneco) Are you
contemplating any barrel limit on tax
credit?
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Answer: No.
Question: What are your thoughts on phase out
and price level?
Answer: From $20.00 on a sliding scale.
Question: (Bill McDermott, Occidental Oil) In
regard to the $20.00 phase out, are
you realizing that by 1985 with the
7% escalation per year, the price of
oil will be over the $20.00?
Answer: We understand this and will take this
into consideration. We will not give
you any package that you are not
going to respond to.
Question: (Harry Pf orzheimer, Sohio Natural
Resources) I supported the $3.00
barrel tax credit but only as one of
the number of incentives that I feel
are needed. Some of these plants
will not be profitable at all or
slightly profitable. A $3.00/barrel
tax credit will not be any good to a
company that is simply going into
the oil shale business. It will help a
major integrated company only if
they have taxable income from other
operations to offset the $3.00 tax
credit. The most aggressive of the
major companies in order to comply
with the Department of Energy, are
drilling all over the U.S. and the
world and are creating tax deduc-
tions that result in many of these
companies not paying any taxes at
all. The tax credit will not help
them either. I am still very much in
favor of this as it will help some
people, but to draw the conclusion
that DOE has drawn, that this is all
we need and industry must therefore
comply once we get it, I think is
erroneous. You have to follow many
of the other incentives that are
proposed and are available.
Answer: I assure you that at DOE your
position is recognized. We under-
stand, and this is true of every
technology we deal with, that there
is not any one answer to the way we
approach these problems.
Question: (Mike Spence, TOSCO) You mentioned
you had $15 million and knew what
you were going to do with it. I
wonder if you would elaborate on
that?
Answer: The Interior Appropriations Com-
mittee directed that the funds be
used to solicit industrial interest and
design studies to secure engineering
plans for module construction.
Those portions of the department
that have direct responsibility for
this, including ET, have come in
with specific recommendations.
These are in the hands of the under-
secretary who will make that decision
within a few days. We are really
interested in design studies. This
will be public information by the end
of February-
Question: (Hank Ash, Interior Department) In
your DOE selection of eight winners,
oil shale was excluded. Was that for
environmental reasons?
Answer: The technologies defined as winners
were: enhanced oil recovery, uncon-
ventional gas, industrial atmospheric
fluidized bed, wood, conservation,
and three types of solar--passive,
hot water and industrial processed
heat. These were characterized as
technologies that no longer need
more research and development or
support. Therefore, they were
technically ready. However, they
may possibly need other incentives
to get them going. The contracts
will be issued October 1 of next year
on a floor-sharing base. But these
technologies were all technically
there. DOE has to get funds to
take care of start-ups. It seems
inaccurate to say that shale from an
in situ proposition is "there."
Before shale is declared a "winner"
and given a green light for rapid
development, a great deal more data
must be assembled and evaluated.
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Henry F. Coffer introduced Les Ludlam
who gave a report on the status of the Colony
project. He talked from slides, but provided a
copy of his remarks, which follows.
COLONY DEVELOPMENT OPERATIONS,
LES LUDLAM, MANAGER
I am delighted to be here today and to
have this opportunity to tell you more about the
Colony Development Operation. I would like to
tell you where Colony stands today with respect
to our commercialization plans.
Introduction
The Colony Development Operation is a
joint venture of Atlantic Richfield Company and
Tosco Corporation. Since the venture was
formed in 1964, a total of about $75 million has
been spent on development, demonstration, and
commercialization. This does not include pur-
chase of the reserves.
From 1969 through 1972 the venture re-
vamped from the 1,000 ton/day semi-works
Tosco II retort built in 1965. Testing was
undertaken in 1971-72 to demonstrate retort
operability and to obtain data necessary for the
design of a commercial mining, retorting, and
upgrading complex. These further operations,
which lasted until May 1972, included over 100
programs to assess the potential impacts upon
air, land wildlife, water, vegetation, and socio-
economic conditions that could result from
construction and operation of a commercial
complex.
Studies included exhaustive documentation
of existing conditions, determination of design
parameters for pollution control equipment,
mathematical modeling of air pollutant dispersion,
and so on. The information obtained from
environmental assessments was utilized in the
engineering design of the commercial facility.
For instance, Colony originally intended to
locate retorting and upgrading facilities in
Parachute Creek Valley, but diffusion modeling
and a series of tracer studies led us to the
conclusion that "trapping," or stagnation mete-
orological conditions, might occur, resulting in
unacceptable concentrations of air pollutants.
As a result, we relocated the plan on the
plateau.
Following completion of semiworks programs
in 1972, we retained the engineering firm of
C.F. Braun and Company to prepare a defin-
itive design and cost estimate for the commercial
plant, to be located on the plateau, at an
elevation of 8,200 feet. The mine portal bench
and primary crushing operation will be at the
head of Parachute Creek, approximately 700 feet
above the valley floor.
Disposal of processed shale takes place in
nearby Davis Gulch. A product pipeline would
leave the property in a westerly direction.
Access to the plant and mine will be by way of
Parachute Creek Valley. This corridor can
contain vehicle traffic, a water pipeline, etc.
Office and terminal facilities will be located to
the north of the town of Grand Valley.
Looking closer at the commercial complex,
we expect to mine approximately 66,000 tons per
day of ore, using conventional room and pillar
techniques. The mined rock will be crushed to
a nominal nine inch minus at the mine portal,
conveyed through an inclined tunnel to the
plateau, stored in an open storage pile, and
then crushed to a nominal one-half inch minus
size before being fed to the retorts.
The retorting operation will utilize the
Tosco II process. There will be six of these
units in the complex, each having a capacity of
11,000 TPD. Raw shale oil will be upgraded on
site, producing a premium quality fuel suitable
for a number of different markets. This pro-
duct is then transported by pipeline.
Disposal operations will require that pro-
cessed shale be placed in an embankment and
then compacted. The compacted shale is quite
dense, and is not susceptible to significant
percolation, so that it makes an ideal landfill
that can be used for the disposal of other solid
wastes.
Control of surface runoff requires the
construction of catchment dams; the water will
be recycled, so that there will be no water
discharge. Dust emissions will be controlled
using water on all working surfaces, and all
permanent surfaces will be revegetated for
long-term erosion control.
By 1974 we had expended over 400,000
engineering man hours in the development of
this design,, with necessary equipment specifi-
cations, schedules, etc. for a 66,000 ton/day
commercial complex. We planned to start con-
struction in 1975. During 1974, however,
inflation had caused the cost of the project to
increase from $350 million to about $900 million.
At that point, it was necessary for us to
suspend our construction plans, except for the
completion of a pioneer road to the plateau and
a railroad spur in Grand Valley. Plans to
begin construction have remained suspended
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since then. Since 1974, we have worked to
maintain the venture's ability to reactivate
construction plans. A number of approvals and
permits have been obtained or are being sought.
Colony must obtain a large number of
permits or approvals from the federal govern-
ment, and we are seeking the critical ones.
The Bureau of Land Management completed
Colony's final environmental impact statement in
June of 1977, after about three years prepara-
tion. They will be the permitting or approving
agency for our pipeline right-of-way across
public lands, as well as for rights-of-way for
power lines, access roads, etc., which cross
public lands.
The U.S. Army Corps of Engineers must
grant permits for river and stream crossings,
and for the construction of a water pump station
on the Colorado River. We have completed
these applications and have submitted them.
Colony will need some water from storage to
supplement its commercial direct diversion
rights from the Colorado River. We have
requested that the Bureau of Reclamation re-
open contract negotiations.
The EPA must approve spill prevention,
control and countermeasure plans, and must
grant a "PSD" permit to assure the prevention
of significant air quality deterioration. We
submitted this application last June.
There are a number of isolated parcels of
federal land within our property. A proposed
land exchange with the federal government to
eliminate these windows is now nearing
completion.
There are another twenty or so approvals
required at the state and local levels, and again
we are proceeding on those that appear critical
at this time.
Our air quality permits from the state were
applied for this fall. The application requires
the completion of forty-five different forms,
which are not required for the federal permit.
Our state mined land reclamation plan, which
must be approved by the mined land reclamation
board, is being prepared now. We expect to
submit it in 1979.
Finally, we have received conditional
approval from the Garfield County Commissioners
for the U.U.D. filed for the new community to
be developed in conjunction with our plant. In
addition to this, there are about twenty-seven
more permits required for this community. My
purpose in reviewing these permits is twofold.
First, I want to make the point that Colony is
well along in acquiring its major permits. But
more importantly, I confess the fear that the
EPA might conclude that oil shale development
may be ready to proceed... "if only we had some
more regulations." I submit that we are already
regulated at least adequately -
Since the purpose of this meeting is to
discuss where EPA oil shale research might best
be directed, I will touch on what we think we
have learned from all the environmental studies
conducted in support of our permit activities.
I would like to cover the areas of air,
water, and solid waste disposal. For each of
these, I propose to follow the environmental
impact statement format of describing what is
already there, and then telling you how we
might impact upon these existing conditions.
Air Quality
We have baseline air quality data for all of
the air contaminants that are currently regu-
lated by the EPA. These are reported for
various time averaging intervals to conform to
the National Ambient Air Quality Standards
(NAAQS).
First, most continuous analyzers are in-
capable of detecting the concentrations of
pollutants that normally exist. We appear to be
the proud owners of volumes of expensive data,
which are mostly zeros.
I call your attention to the predicted
maximum incremental particulate concentration of
28 mg/m3 (which is far less than can be attri-
buted to any health or environmental effects)
no more than once per year at any point off the
property. This value, then, as low as it is,
does not in any way indicate a persistent or
widespread air quality impact. The PSD regu-
lations are a lot more stringent than most
people realize in this regard.
Water Quality
The existing water quality of Parachute
Creek is easily summarized. The flows in
Middle Fork and Davis Gulch, the two drainages
to be affected, are each 150-800 acre feet per
year, with notable yearly and seasonal varia-
tions. Salinity, which is the primary water
quality parameter of concern, averages about
500 mg/i.
By the time the creek reaches Grand
Valley, the flow has increased to about 20,000
acre feet per year on the average, and salinity
has increased to about 1,000 mg/£. The
Colorado River flows at an average rate of
about 2^-3 million acre feet per year, with an
average salinity of about 500 mg/£.
Water requirements for the commercial
plant will be about 12 CFS or 9,000 acre feet
per year. A very minor portion of this re-
quirement can be satisfied by retaining runoff
from Davis Gulch and Middle Fork of Parachute
Creek, and/or utilizing any water encountered
in the mining operation. Essentially all of this
water must then be pumped from the Colorado
River to the plant site.
10
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Although Colony has pumping rights from
the river, they are not of sufficient seniority to
guarantee a continuous supply. We estimate,
based upon computer modeling of the river,
flow and water demands over a thirty year
period, that we need a backup supply of about
4,500 acre feet per year to assure continuous
operations through the drier years. This
means some supplemental water supply will be
necessary from storage reservoirs.
We have requested options for water from
existing reservoirs, from the Bureau of Recla-
mation, and we are also working with the
Colorado River Water Conservation District,
which would coordinate construction of any new
reservoirs.
But secondly, there are occasional values,
in the case of particulates and hydrocarbons,
which exceed the NAAQS. The high levels of
particulates are a result of the semiarid, dusty
nature of the region, and the hydrocarbons
apparently come from the pine trees and sage-
brush. Fortunately, the EPA has judged,
administratively, that these "natural violations"
of the standards need not be counted against
the increments that the plant will be allowed.
The commercial plant will emit about 1,900
tons per year of particulates and 1,200 tons per
year of sulfur dioxide. These will result pri-
marily from material handling operations and
fuel combustion, respectively. There will also
be emissions of hydrocarbons and nitrogen
oxides. These numbers look better if they
were expressed in tons per hour instead of tons
per year.
It provides some perspective to recognize
that particulate emissions are about 0.01% of
material handled, and sulfur emissions corre-
spond to less than 1% of the sulfur contained in
the raw shale oil. These numbers reflect the
application of "best available control technology"
as required by state and federal regulations.
As a point of comparison, these emission rates
are about 20% and 1% respectively, of those
from the Jim Bridger power plant.
I might add that these numbers are dif-
ferent than those included in the final environ-
mental impact statement. In response to the
Colorado Air Pollution Control Division, the
EPA, and the New Clean Air Act amendment
requirements, we have included estimates of
fugitive dust emissions (i.e., dust from unen-
closed sources such as storage piles), and we
have committed to operating twelve of the
principal wet scrubbers with increased energy
input, if necessary, in order to meet reduced
emission limitations.
Two dispersion models have been used to
evaluate the impacts that commercial operations
will have upon ambient air quality. The first
of these was sponsored by Colony, at a cost of
about $250,000 during the commercial plant
design phase. The 1977 Clean Air Act amend-
ments dictated, however, that we use models
developed by the EPA, at least in the case of
particulates and SO2-
The environmental impacts of our operations
of water, aside from the possible construction
of a new reservoir (with positive and negative
impacts), will be a consumption of one-third of
one percent of the average flow of the Colorado
River. A very theoretical calculation predicts
an increase in salinity of 1/60 of 1% at Hoover
Dam when 9,000 acre feet are removed at Grand
Valley. During periods of release from storage,
the salinity may actually decrease.
There will be some minor diversion of
water in the upper reaches of Parachute Creek,
e.g., due to the construction of catchment
dams. We will, of course, be required to have
an approved augmentation plan to protect the
rights of downstream users. One might expect
an increase in turbidity in Parachute Creek
during construction, but this can be minimized
by the use of sedimentation ponds, etc. There
will be no water discharges from the plant: All
process waters will be recycled or used to
moisten the processed shale.
In summary, water quality impacts will be
pretty minimal.
Solid Wastes
We will have a large volume of solids
wastes, primarily in the form of processed
shale, to consider. There is more than enough
room for the disposal of processed shale in
Davis Gulch. Not all of the solid wastes will
consist of processed shale. There will be about
1,400 tons per day of dust and sludge collected
by air pollution control devices, and there will
be 800 tons per day of coke that may not be
readily marketable. An average of 3 TPD of
spent catalysts and chemicals must also be
disposed of or recycled.
But processed shale is by far our major
solid waste. Processed shale from the Tosco II
process is a fine-grained material, and it is
black due to a residual coating of carbon. The
addition of about 13% moisture is required for
optimum dust control and compaction. When
compacted, it forms a crust, and is not suscep-
tible to wind erosion. Still it is necessary to
revegetate the processed shale embankment for
long-term control of erosion. We have spent
more than a decade in developing revegetation
technology. More than seventy-five species of
plants have been grown successfully.
After compact, the surface is watered to
leach naturally occurring salts below the root
zone, and it is planted with a mixture of
species, including wheat grass, Russian wild
rye, yellow sweet clover, flowering saltbush,
11
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and Indian rice grass. The surface is covered
with a mulch material to help retain the water
and to protect the seedlings from excessive
solar radiation, fertilized, and planted with
seeds innoculated with essential microorganisms.
The plants are watered for the next two years,
and then become self-sustaining.
Environmentally acceptable surface disposal
methods have ranked high on our list of tech-
nology development needs. Since 1965, there
have been nine separate disposal embankments
developed on the Colony property, eight of
which were developed by Colony. Each plot
represents one more advance in the disposal
state-of-the-art. A need, we perceive, is to
demonstrate a combination of the disposal and
revegetation techniques developed so far.
Colony has budgeted some funds for such a
demonstration plot in 1979.
One other area where research could prove
useful is in underground disposal of processed
shale. So far, we have not seen a method that
is not prohibitively expensive and more impor-
tantly, one that is significantly better, from a
long-term environmental impact standpoint, than
surface disposal.
I would like to close by making two points:
First, from Colony's viewpoint, there are a
number of questions about the impacts of oil
shale development that may not be wholly ad-
dressed, much less answered, until commercial
complexes incorporating mining, retorting, shale
oil processing, water supply and other support
facilities, product transportation systems, and
community facilities are constructed and oper-
ated. Beyond some point, modeling and extrap-
olation will not substitute for "the real thing."
I suggest then that the EPA look beyond indus-
try's present development and demonstration
phase and attempt to define research programs
that could become more meaningful, if data
were obtained from full-scale plants. It cer-
tainly would not disappoint Colony if the EPA
were to conclude that it is desirable for the
government to support development of at least a
few fully integrated, commercial shale oil com-
plexes, so that industrial scale impacts can be
accurately measured.
Second, when we talk about environmental
protection, we are in essence talking about
regulations, because that is the means that we
have available for environmental protection.
And surely we all agree we need regulations:
That has little to do with my observations that
we already have a great many of them.
I propose that it is in order, though, not
only to discuss the impact of oil shale
development upon the environment, but to
consider the impact of environmental regulations
upon oil shale development. We must, at least,
be aware that this is a two-way street.
Reviewing the more recent Colony history
briefly, we resumed semiworks activities in
1969. In 1970, Congress passed NEPA. Sud-
denly we had new rules and new uncertainties:
Must an EIS cover the entire project, or only
those portions of it directly requiring federal
action? Environmental baseline data were
required--how much? Even on private property?
And how long will it take for the government to
complete an EIS?
And so we began the process of preparing
an environmental impact analysis.
Much of the effort was well spent; we
learned that there were better ways of doing
some things. But much of the effort was
expended because the rules were not clear, and
we recognized the need to avoid court
challenges.
And in 1970, Congress also passed Clean
Air Act amendments, requiring the EPA to
promulgate new ambient standards and new
standards of performance, preparation of state
implementation plans, etc. The act provided
for multilayered federal/state administration,
which left considerable doubt as to who was
going to eventually be responsible for doing
what, and to whom (or, at least, who was going
to be doing what).
But we proceeded with $12 million of
design work anyway, feeling that reason must
prevail.. .that was in 1972. But also in 1972,
the courts ruled that the "protect and enhance"
language of the Clean Air Act required the
promulgation of regulations prohibiting
"significant deterioration" of air quality in clean
air areas. After about two years, new regula-
tions were promulgated, with new layers of
administration and review imposed upon permit
applicants. Again, there were many unanswered
questions and consequent litigation regarding
administration, allowable increments, allowable
concentrations, measurement technologies,
classification of areas, review procedures, etc.
During all of this time, the state of
Colorado exercised its right to enact air quality
standards more strict than the federal stan-
dards. Hearings and amendments bounced
around for several years. At the present time,
the state standards appear not to present a
severe obstacle, but still we need to remember
that state prerogatives exist, (and rightfully
so); they have the authority to set new rules,
too.
Even now, the state is developing a state
implementation plan to conform to the 1977 Clean
Air Act amendments. It will likely be many
months before we can determine the impact of
these new regulations. And, of course, we
have no reason to believe that a "normal"
amount of litigation will not accompany the new
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Clean Air Act amendments—a number of suits
have already been filed, in fact. We still do
not know, then, what tomorrow's rules will
bring.
In conclusion, I would like to confess that
I only briefly touched on the issue of the day,
i.e., "what new environmental research may be
required." Instead, I have attempted to develop
an argument that many critical concerns have
already been analyzed in depth, and that ade-
quate regulations have already been developed
for environmental protection. I urge that as
the EPA develops research programs and formu-
lates new course performance standards, you
thoughtfully consider whether or not the point
of diminishing returns for environmental protec-
tion has been reached and whether or not the
data needed could be better obtained from
operating integrated commercial complexes.
Question: (Hank Coffer, C.K. GeoEnergy
Corp.) When are you going to build
the plant?
Answer: It would take about a year and
one-half to get construction under-
way after a go-ahead decision is
made.
Question: What is the $3.00 barrel incentive
going to do for you?
Answer: It will help, but Colony will not
necessarily go ahead if the tax
credit becomes law.
Question: (Jackson Gouraud, DOE) That is not
what you told me in April.
Answer: Nothing has changed since we talked
in April. It is pretty much the
same, but a number of other things
have to happen before the project
gets underway.
Dr. Coffer then introduced Paul Dougan of
Equity Oil Company who spoke on the BX
Project.
EQUITY OIL COMPANY, PAUL DOUGAN,
COOPERATIVE SECRETARY
Introduction
The "BX In Situ Oil Shale Project" is
based upon in situ oil shale research conducted
by Equity Oil Company from 1962 to 1971. The
project is predicated in one basic premise: In
the central portion of the Piceanse Creek Basin
of northwestern Colorado, there is a section of
oil shale bearing rocks in the Parachute Creek
member of the Green River Formation commonly
referred to as the Leached Zone, which contains
very large reserves of oil in place of oil shale.
This section, or Leached Zone, has enough
permeability and porosity to permit in situ
retorting of the oil shale contained therein
without resorting to mining and/or other frac-
turing techniques to create permeability and
porosity prior to retorting.
The purpose of the BX In Situ Oil Shale
Project is to demonstrate the technical feasibility
of using superheated steam at 1,000°F and
1,500 psig as a heat carrying medium to retort
in situ oil shale of the Leached Zone and to
provide a mechanism for the recovery of this oil
with a minimum impact on the environment.
More specifically, the oil shale will be
retorted by injecting superheated steam into the
leached zone through an array of injection wells
and recovering the steam/water/oil and gas
produced from the Leached Zone through an
array of production wells. The injection into
and production from the Leached Zone will be
accomplished in a manner which will promote a
diagonal sweep of the entire leached zone.
During a two-year period, approximately
1 trillion BTU of heat will be injected into a
Leached Zone site, which is 540 feet thick and
covers 7/10 of an acre.
The measure of success for this project
will be whether: (1) The injection goals can be
met; (2) The target amount of oil shale can be
raised to retorting temperature; and (3) A
reasonable percentage of the retorted oil can be
recovered.
The project is being performed under a
cooperative agreement between Equity Oil Com-
pany and the U.S. Department of Energy.
Under that agreement, Equity pays 14% of the
costs and the government pays 86%. Equity, as
the industrial participant, agreed to perform
four basic project tasks:
A. Leached Zone Site Evaluation
B. Laboratory Experimentation
C. Field Project
D. Environmental Research Plan
The cooperative agreement was entered
into on March 1, 1977, and the length of the
project is estimated to encompass fifty-five
months.
The BX In Situ Oil Shale Project site is
located in the center of the Piceance Creek
Basin of northwestern Colorado. The zones of
the Parachute Creek member that have attracted
principal interest in the recovery of oil from oil
shale are the Mahogany Zone and the Basal
Zone containing large amounts of nahcolite,
dawsonite, and halite. These zones are for all
practical purposes impermeable and nonporous
and require permeability to be created if the oil
shale of the zones is to be retorted in situ.
The Leached Zone lying between the Mahogany
Zone and the Basal saline zone is filled with
saline water, which is a barrier to certain
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mining and retorting techniques that might
otherwise be applied, but which is salutatory to
the technical approach embodied in the BX In
Situ Oil Shale Project.
The Leached Zone varies in thickness,
being thickest near the basin center and thinner
at the edges. At the BX Project Site, the zone
is 540 feet thick and contains oil shale with an
average grade of 24.39 gallons per ton.
The intent of the well pattern selection
was to develop a central fivespot pattern in full
field development, while at the same time using
the minimum number of wells external to this
pattern to confine it. This need was coupled
with considerations of steam injection capacity
and the injection rate required in each of the
injectors to insure that a bottom hole tempera-
ture of 900 to 950°F could be achieved. The
pattern is developed with a consistent spacing
from injection to production wells of 68 feet and
covers a total area of 0.7 of an acre. In the
0.7 acre pattern, there are approximately
636,000 barrels of oil in place as oil shale in
the 540 foot thick Leached Zone.
Field Project Equipment
To facilitate the injection of superheated
steam at 1,000°F and 1,500 psig at a rate of
57 MM BTU/hour or 2,784 barrels/day (42 gallon
barrels) required a reasonably sophisticated
steam generating plant, a water treatment
plant, water storage facilities, and an instru-
mentation system to monitor both equipment and
project performance. The operating sequence is
as follows: Water is produced from the Leached
Zone and stored in the water storage pit until
it can be processed in the water treatment
plants. After treatment in the two water treat-
ment plants, the treated water is stored in
five, 400-barrel water storage tanks. Treated
water is fed to two steam generators capable of
producing dry steam at 1,600 psig and 605°F.
These two streams of dry steam are then fed to
the superheater where the steam is superheated
to 1,000°F at 1,500 psig. From the super-
heater, the steam is distributed to eight
injection wells, the quantity going to each being
proportionately controlled by automatic control
valves. The steam is injected into the injection
wells through insulated 2-3/8 inch steel tubing,
which is suspended in 7 inch steel casing
perforated at the top and bottom of the Leached
Zone. After the steam enters the Leached
Zone, it gives up its heat and is produced as
water accompanied by retorted oil and gas at
the five production wells.
Each production well is equipped with a
"gas lift" system to assist in producing the
wells at a high production rate. From the
production wells, the product stream goes
through a free-water knockout and a heater
treater to separate oil, gas, and water. Water
is returned to the water storage pit for reuse,
oil is stored, and gas is recovered for use as
steam generator fuel gas. A test separator is
included in the production equipment to test
individual production wells.
Monitoring of all equipment functions and
project variables is provided by a data logging
system that continuously logs temperatures,
pressures, and flow rates, including the down
hole temperatures observed in the three temper-
ature observation wells.
I will briefly describe the elements and
theory of the project and then point out the
primary areas of environmental concern and
what is being done to monitor the environmental
effect of the project.
As a part of the BX Project, an "Environ-
mental Research Plan" has been developed.
The major concerns that this plan addresses
are:
1. Transport and fate of pollutants and
gaseous effluents expected to be released
by the research facilities
2. Transport and fate of recycled water
3. Changes in ground water chemistry, tem-
perature, and potentiometric head during
operations
4. Alteration of the geologic, chemical and
engineering properties of the retorted oil
shale formation
5. Changes in downstream surface water
quality in Black Sulfur Creek
The small number of project employees
(five full time operators with a maximum of
three on duty at one time) does not create a
significant impact on the biological system,
health, or social environment of the project
area. And in a similar fashion, the small
physical area occupied by the project (total of
fiveacres) mitigates any significant effect on the
project lands or those lands adjacent to the
project area.
The two principal areas of environmental
concern are the effects of the project on air
and water quality.
Air Quality
Fuel is natural gas supplied by Western
Slope Gas Company plus produced formation
gas. The only pollutant that it now appears
may be of concern is SO2 produced as a product
of combustion from burying produced formation
gas, which will contain H2S. Wind speed, wind
direction, and temperature will be monitored
continuously- Fuel gas will be monitored for
composition by periodic grab sampling and
chromatographic analysis, and continuous
monitoring for total sulphur and/or SO2 will
also take place.
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Water Quality
A. Surface—Black Sulphur Creek
1. pH, conductance, temperature,
and flow
2. water quality analysis
3. monitoring up and downstream of
project site
B. Hydro Geology
Leached Zone (B Aquifer)
1
2.
3.
Upper Aquifer (A Aquifer)
Alluvium (Ground water)
a. Use project wells to monitor
Leached Zone and Upper
Aquifer
b. Alluvial aquifer monitoring
wells
c. Pond leakage wells
Site specific data will be collected to
determine :
1. Transmission and storage properties of the
Leached Zone, the overlapping aquifers,
and possible interconnection between the
two
2. Existing quality of water in the two zones,
nearby springs, and adjacent alluvium
3. Rates of flow in the two zones across the
project site
4. Accumulation of water from leakage from
the process waterholding pond
5. Changes in ground water chemistry, tem-
perature and potentometric head during
the operational and post-operational phases
of the project
Project rationale is to develop data on this
project that can be extrapolated as necessary to
estimate impact of commercial development.
Question: What is the difference in perme-
ability in the upper and lower
aquifer?
Answer: I think there is a difference but I
cannot give you an accurate answer.
Question: I understand that in your program
you would plan to reuse the pro-
duced water.
Answer: What we do is produce the water
from the Leached Zone, put it in a
pond, put it through a water treat-
ment plant and use that for make-up
water for the boiler. In the water
treatment plant we have some waste
water, and we have 20% of the water
blown down through the steam gener-
ator in order to get dry steam.
That water in turn is injected back
into the Leached Zone in other wells
on the project. All the water and
all the minerals that came out of the
water go back into the same place
they came from. There is no
discharge at the surface externally
other than evaporation.
Question: (Bill McDermott, Occidental) What is
your anticipated daily production?
Answer: I did not give a production rate, I
said 636,000 barrels of oil in place.
Question: What is the goal?
Answer: I would be very happy if we got
300-400 barrels per day.
Question: (Don Hessling, Cities Service Co.)
Did you mention the barrels of steam
per barrel of oil?
Answer: No. You can choose any number
you want. It becomes pretty clear
that if the barrels of oil per barrel
of steam go down too far it is too
costly to produce, treat, and heat
the water to make steam. If we
have decent recovery then it is
probably workable. We are trying to
create an oil reservoir effectively,
and that is pretty tough.
GEOKINETICS, STEVE MANKOWSKI,
STAFF ENGINEER
Geokinetics is in a cooperative government/
industry venture between Geokinetics and the
Department of Energy. This was a joint ven-
ture between Geokinetics and Aminoil, until
recently. The field operations have been going
on for about three and one-half years at the
site in Utah, and we expect to continue with
experimental work until probably about 1982.
Our project is located seventy miles due south
of Vernal in Book Cliffs. We have about
thirty-five employees and their families in a
self-contained mining camp on the site. To
date we have prepared eighteen retorts ranging
from very small size to about 60% of commercial
size. We have burned eleven of these to date,
and so far it appears that the process will
work. We have recovered up to approximately
50% of the oil in the broken shale. To date, we
have produced a little bit less than 5,000 bar-
rels of shale oil, of which about half has been
sold to a local refinery in Utah. The remainder
of this has gone to DOE and DOD for testing.
Let me give a quick rundown on the pro-
cess. We are using a horizontal in situ
retorting process basically designed for thin
shale beds under no more than 150 feet of
overburden. We see this as a viable alternative
to strip mining. The shale we are using aver-
ages about thirty feet in thickness and has a
yield of 20-23 gallons/ton.
The retorts are prepared by heaving the
overburden by the use of explosives. This is
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done by drilling a pattern of wells into the
shale, loading the shale section of the well with
explosive, and simultaneously detonating the
explosive in the series of wells. After the
shale is broken, the burn equipment is installed
and the in situ retorting begins. Air is in-
jected in one end of the horizontal retort, and
production wells pump the retorted oil and
retort water from the other end. Most of the
oil is recovered by pumping, with about 5%
recovered from the exhaust gases. Water goes
to the holding pond, oil to the storage tanks,
and the exhaust gas to an incinerator. After
the burn is completed, the equipment is moved
to the next location, and revegetation is begun.
Our environmental program includes a
baseline study covering plants, animals, subsur-
face water, air quality, meteorology, and
socio-economic and cultural structures of the
Uintah Basin and a study of the Uintah Basin.
The research program includes a study on how
retorting affects the movement and contami-
nation levels of subsurface water.
The exhaust gases from this process are
similar to other retorting processes. Any
impact of a full-scale industry would be minimal
since the operation would be spread over several
sections. One problem still being studied is
leakage of the exhaust gases from the retort
through surface cracks.
By 1982 Geokinetics hopes to have devel-
oped a commercially viable process and be
producing 2,000 BOPD.
MULTI MINERAL CORPORATION,
BEN WEICHMAN, PRESIDENT
The Multi Mineral Corporation was started
last year to propose to the federal government
a cooperative agreement for constructing and
testing a full-scale module oil shale plant.
Multi Mineral was formed as a vehicle so that
private industry could raise the money, and we
could go to the federal government with the
proposal. The corporation was formed, and as
of December of last year, we submitted our
proposal jointly to the Secretary of the Interior
and to the Secretary of Energy for this pro-
gram. A five-year program was designed to
test the integrated in situ process. The basic
work in this has been completed. All pilot
work is finalized and is ready for a module
test. We have not yet had a response from the
federal government on our proposal, a program
involving about $130 million.
Let me tell you what the program and
process is. We did a study to determine what
kind of oil production would be required and
our best estimate was somewhere in the neigh-
borhood of five million barrels a day. We
looked at tar sands, oil shale, and coal. How
are you going to get it from oil shale? Four
processes are available: in situ, modified in
situ, surface retorting, and the Superior/Multi
Mineral Process.
What can each one of them do? In situ—
nothing substantial; it is still experimental and
we cannot see that. The surface plants, if
they work as well as they hope, might deliver
about one million barrels per day before we get
into some logistics problem. The one that looks
great is modified in situ, which can theoretically
provide the amount of oil needed at costs less
than we are paying for imports. However, two
problems remain: channeling and the water
problems. The Multi Mineral Process stands
head and shoulders, economically, above the
other, but it also has a problem with logistics.
How much can oil shale do? We made an
optimization study and asked what we could
expect from each of the four recovery methods,
and we were surprised when we found out that
oil shale can do it. We found that by inte-
grating the process we came up with a solution
that we call the "Integrated In Situ Process."
This is a product of the Multi Mineral tech-
nology applied to a modified in situ method.
The Multi Mineral Process solves the channeling
problem as well as the water problem. We do
not run into the same logistics barriers in this
super-large unit until we get to ten million
barrels a day. We think this is pretty good,
and we are ready to put our money up to prove
it. So we have made this proposal to the
federal government to fill a big hole in the oil
shale program.
We have different types of oil shale re-
sources. The Mahogany Zone resource that is
applicable to modified in situ and surface plant
processing; the lower zone oil shale resource is
equally as big but also has nahcolite and
dawsonite in it. The combination type processes
are not amenable to the lower oil shale, nor is
the Multi Mineral Process amenable or applicable
to the Mahogany Zone. We have to make this
point very strongly to the federal government.
Oil shale is the cheapest and the closest to
commercialization, so we have to get the most of
it. Then we will go to other less acceptable
forms of energy to make up the balance. That
means that we must have processes tested on
the Mahogany Zone; surface processes must be
tested, because the modified in situ process
still requires surface processing. Each one has
to have the opportunity to go into full-scale
testing to see what it can do for an optimum
program. We must have the Multi Mineral
Process because it addresses two timely
scenarios, oil recovery and coal clean up. The
second scenario is one that will come to a
crucial stage sooner than the liquid. We have
been saying all along that nahcolite is the best
scrubbing agent that we know.
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There is a big hole in the federal program
for oil shale. That big hole is the lack of real
motion in the multi-mineral area of our oil shale
resources. This is the hole we are trying to
fill. We are trying to go to them with a pro-
gram that, is ready for module testing. We are
willing to put up our money because it may
very well be the only economic approach that
does not need outside support. I think we
should have the opportunity to prove it.
Now I would like to disagree with
Alan Merson who said we should not put up any
more leases until we have tested the two proto-
type leases—well that is just great for the
Mahogany Zone. But it does not tell us much
about what we have to know about the lower
saline zone. There should be an available lease
for testing and proving in the Multi Mineral
Process. We have a second and separate
program.
We have made a proposal and given a
letter of intent to the Bureau of Mines to con-
duct a program this year in the eight inch
diameter shaft out there. I believe meetings
are being held today to find out what they are
going to do with it. They have before them a
proposal from Multi Mineral Corporation to
immediately take over that shaft cooperatively
with the Bureau of Mines to conduct two levels
of testing. The first step of testing is the
bulk sampling program. The intent is to pull
out about five thousand tons of nahcolite from
the Nahcolite Zone from that shaft, to be used
primarily in two test areas. The first is that
we propose to use a good deal of that nahcolite
to support a full power plant as a scrubbing
agent. The second one is to supply the
Charter Company with a large amount of nah-
colite. They are conducting some meaningful
tests regarding desulfurization within refineries,
which look very promising.
There will also be nahcolite available for
other tests and that is the purpose, to make it
available for any testing that would be meaning-
ful. The second part of that program this year
is to go into the lower part of the saline zone
and to cut two stations, two drifts out beyond
the shaft pillar. These two test stations would
be used to determine rock mechanics and mining
health and safety—a number of things we need
to do so that we can plan on mine safety regula-
tions for mining the saline zone. We also
propose, then, to cut a stope between these
two levels and do some testing regarding the
Integrated In Situ Process relative to the stope
concept of oil shale mining.
OCCIDENTAL OIL SHALE, BILL MCDERMOTT,
EXECUTIVE VICE-PRESIDENT
"C-b" tract was originally awarded back in
April of 1974 for a bid price of $117 million.
Originally the partners were Arco, Ashland,
Shell, and TOSCO, and up until recently that
had come down to Occidental and Ashland Oil.
Ashland Oil has announced their withdrawal
effective February 14 of this year. We have
started on the tract very similar to what
Elaine Miller has explained in the line of pre-
development monitoring, actually got on the
tract and started physical work in Novem-
ber 1977, which was over a year ago. Since
that time we have erected three test frames,
one of which is over the DE ventilation
escape shaft and is a fifteen foot diameter
shaft. The second is a 313 foot concrete slip
form, a head frame over a 29 foot production
shaft, and the third is a 178 foot head frame
over a 34 foot diameter service shaft. Those
head frames were all completed in November of
last year.
We have, in the meantime, outfitted those
head frames so that we could commence the
sinking of the shafts. The first shaft com-
menced sinking January 16. This is the fifteen
foot diameter ventilation escape shaft. We
expect that shaft to progress at the rate of
about 45 feet per week. That shaft was col-
lared at 65 feet, and we will bottom out about
May 1, 1980, at a total depth of about
2,000 feet. The other two shafts are scheduled
to start later this year (1979), one about
February 1 and the other about April 1. Those
two shafts will not be completed until
January 1, 1981. We will be using the DE
shaft that is to be completed in the middle of
1980 to start some development mining over in
the direction of the other two shafts.
We are now continuing with our air moni-
toring. We have two stations, one on tract,
one off tract. This was a reduction from the
five we used on the baseline study work. We
have another station that is solely erected for
measuring total particulates. Recently, in con-
junction with C-a and with EPA, we established
a station for monitoring visibility sites on and
off tract. We have about 250 people working at
C-b now, mostly contract people in the shaft
sinking operation. That will grow to about 400
by midyear, when we will be sinking simulta-
neously all three shafts. In the area of socio-
economic, work we are busing out employees
from both Rifle and Meeker. We have two
buses every shift coming from Rifle, one from
Meeker. This is to mitigate highway congestion
problems. It also helps out from the air quality
standpoint and causes less impact on wildlife.
This has been very effective.
About 80% of our employees take these
buses. We have some staging areas in both of
the communities, and the workers drive to that
area and are bused up to the site. (These are
new Greyhound-type buses with soft music
playing both to and from work.) In the
housing area we have provided financing for
housing at both Meeker and Rifle and have
about fifty units at both places. At Rifle we
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have built a 100-pad mobile home court, which
is about two-thirds occupied. We opened that
up to non-Occidental employees and noncontract
employees. That summarizes the activity at
C-b.
I would like to say something on DA Shale.
(DA Shale happens to be the initials and the
name of the man that owned the property before
Oxy acquired it, and since his name was
Mr. Shale and his initials were D.A., it fits in
with the two letter acronyms C-b and U-a,
etc.) We are in the process of completing a
cooperative agreement with DOE. This was a
program that was started back in November of
1976 for a total amount of almost $20 million.
This involves the forming and firing of
full-scale retorts.
Retort #6 is currently being burned. It is
a retort that is 52 feet square by approximately
260 feet high. This retort was fired in
September, and it has produced to date about
23,000 barrels of oil. We are looking at the
rate of well over 300 barrels a day now. Last
winter was not an easy operating winter, with
all the zero weather and the power outages we
have had, but we have learned to work with
thess adversities as we are going to have to
learn in the high country in the wintertime.
In addition to that, there is a totally Oxy
funded program going on at the DA Shale, and
that is a rock fragmentation, learning how to
blast the rocks. This is a very fundamental
part of the modified in situ program. This
program was started last year and is continuing
well into this year. Some rather large retorts
are blasted and tested as far as the per-
meability. We have about 100 people working at
the DA Shale operation, and that will grow. We
also have before the DOE a proposal to extend
the Phase I program through the development of
two additional retorts. This was originally
conceived to be done at the C-b site for full
production there, but because of the timing it
is better to do that at the DA operations at a
much lower cost. This proposal would involve
the mining, rubblization, and the burning of
two retorts simultaneously. That really covers
the operations.
Let me make a few more comments. We are
deeply involved in an economic evaluation for
C-b, having an engineering company doing a
full study. The moving target of world oil
price is making it difficult in getting a firm
grip on what the economics are for an oil shale
operation. Also we are a little nervous about
the EPA schedule for new regulations. That is
hanging over our heads, and we really do not
know what is coming down the track. It can
seriously effect economics. The other is the
visibility study. How is that going to impact
the oil shale industry? As for the hazardous
substance problem, just where is that going to
hit the oil shale industry? (One of our fellows
interpreted that regulation to say that spent
shale is going to have to be put into 55-gallon
barrels and buried underground.) The third
one would be the Resource Conservation and
Recovery Act. Just what is that going to mean
to the oil shale industry? We see in a lot of
places that there is wide application of regula-
tion or interpretation of regulations without
specific data, and this really hurts. We are
working very diligently and with the coopera-
tion of the various agencies to acquire the data
that is necessary. We realize the pressure
position that some of the agencies are put into
at times. It makes us nervous that these broad
applications are made when we really do not
have the specific data that we need to apply
them to the oil shale industry.
RIO BLANCO OIL SHALE, "ELAINE MILLER,
PRESIDENT
Rio Blanco is approximately one year into
what started out to be a four-year test develop-
ment program and is slowly edging toward four
and one-half years. We call it our modular
development phase. This program is fully
authorized and funded by Gulf and Standard
and was expected to cost about $100 million.
That figure has risen. Since this is an
EPA/Industry workshop, I should probably
mention that prior to any significant tract
development the two-year environmental baseline
data gathering program was initiated at a cost
of about $5.2 million. Then we had an interim
monitoring program that lasted through the
one-year extension period that cost about
$1 million. We expect through the remainder of
our modular development phase that our moni-
toring program will cost about $4 million. So
you can see environmental monitoring alone is a
full 10% of the cost of the program. And, even
then, this is not considering the costs of the
program for obtaining and reporting on various
environmental permits or the tasks of pollution
control planning equipment and expense. The
point I wish to make is that Rio Blanco is
operating a very comprehensive environmental
program that we believe is more than adequate
to assess the effects caused by our activity.
The modular development phase, as we are
currently implementing it, requires a fifteen
foot diameter shaft. This shaft gives us access
to the retort area and provides for the removal
of material that is generated by the driving of
drifts and void volume for expansion of the
rubble in the retorts. A ten foot diameter
shaft is also required for mine ventilation
purposes. At the present time our fifteen foot
surface production shaft is at 646 feet with a
projected total depth of 977 feet, and it is
expected to be reached by about midyear.
Although we have had some water, hydro-
gen sulfide, bad ground, and other problems,
the shaft sinking is making rapid progress.
18
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Considerable drifting for horizontal excavation
has been done at several levels. The "C" and
"E" levels of the shaft and shaft sinking should
progress at a rate of about eight to ten feet
per day. Once the shaft is completed and
equipped, drifts will be driven to the retort
area where we plan to rubblize and burn five
retorts of progressively larger sizes. The first
of these retorts is programmed to be 30 x 30
x 140 feet tall and should be burned in late
1979. The last of these-retorts, at the present
time, is expected to be 100 x 100 x 400 feet
tall, and we anticipate that from this information
we will be able to prove the reliability of com-
mercial scale retorts significantly larger than
the last one burned during this program.
Several rubbling schemes are under inves-
tigation, some of which have the potential of
greatly reducing mining costs. The purpose of
our modular development phase is to answer the
several technological, environmental, and eco-
nomic questions that we have regarding the
process and hopefully allowing us at the end of
this program in 1982 to be able to make a
commercial decision. Assuming the most
favorable results are obtained, the detailed
development plans that have been approved by
the area oil shale supervisor, call for the
construction of a commercial scale plant of
76,000 barrels a day to be in operation by
1987. We believe that this is an optimistic
appraisal and that it will probably be necessary
to carry out additional modular experiments
before we can justify the over $1 billion expen-
diture needed for a commercial plant. In sum-
mary then, Rio Blanco is progressing pretty
much on schedule and fully intends to complete
the program.
At the completion of this program, Rio
Blanco will have more than $260 million invested
in tract "C-a," which should give you a measure
of our confidence of eventual success. The
timing of success is far more questionable, and
I personally believe that, in very large measure,
is dependent on governmental attitudes. If the
government gives a commitment to oil shale
development, I believe that commercial produc-
tion in the 1987 area is possible. If the
governmental attitude towards oil shale develop-
ment is negative, that time schedule will not be
possible.
Question: On the first burn, will it be next
summer?
Answer: As of the last meeting we have had
the burn programmed for Septem-
ber 1, but that has slipped a bit.
It will be before the end of the
year.
Question: Any daily production predictions?
Answer: No. Daily production anywhere in
the modular tests is really not
applicable. We are producing about
140 thousand barrels total out of the
five retorts.
SOHIO NATURAL RESOURCES,
HARRY PFORZHEIMER, VICE PRESIDENT
Perspective
I have the greatest respect for Jackson
Gouraud and Alan Merson not only because they
are here and are conducting this program, but
because they are willing to come out, spend
their time to look at what we are all doing, get
first hand information, and draw their own
conclusions. This permits them to distinguish
between the real and the unreal. To me, the
real in oil shale is shale oil. Until you produce
a lot of shale oil you are not quite real.
We are not here to talk about the fact that
the country has a $15 billion balance of payment
deficit. We are not here to talk about the fact
that half of our oil is coming from foreign
countries. We are not here to talk about the
fact that during the Arab embargo, close to 90%
of the fuel for our Navy fleets disappeared.
We are not here to talk about the fact that if
we had another embargo of any duration, we
would not be able to muster a significant effort
in our own economic or national defense.
We are really here to talk about the envi-
ronment, conservation, and production. I think
we must view these problems in the light of the
seriousness of our energy situation. For
example, if conservation is a major objective, do
we begin oil shale development by starting an
open pit mine about where the C-a lease is
located and proceed to mine, the whole basin? I
personally do not think so, but with good
above-ground retorting that is the method for
obtaining the highest yield of oil from the rock
available.
If, as presently planned, we do not do
open pit mining, the next best way to go would
be underground mining with a combination of
above-ground and in situ retorting. The first
step would be to mine the rock, put it through
an above-ground retort and get a high yield of
oil and gas. Then, fragment the rock around
the mined out cavities, retort this rock in situ,
and hopefully, get another high yield. Any
talk here about in situ versus above-ground
retorting would be unrealistic and out of place
if conservation is an objective.
Sohio became involved in domestic tar sand
in 1956 and in domestic oil shale in 1963. Our
reasons for doing so were as much strategic as
economic. The strategic reason was to reduce
Sohio's vulnerability as a major purchaser of
crude oil. At that time Sohio's management
correctly anticipated that crude oil production
in the United States would soon begin to decline
19
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and that worldwide demand would exceed world-
wide production of natural crude oil in the
foreseeable future. Well, U.S. production has
been declining. Our current estimate that
worldwide demand will exceed worldwide produc-
tion by 1989 is beginning to look overly
optimistic.
Sohio had not been sufficiently successful
in its crude oil exploration efforts prior to 1963
to improve its ratio of crude oil production to
refining. The billions of barrels of oil in-place
in the tar sand deposits of the United States
made a very large and tempting target. The
trillions of barrels of oil in-place in the U.S.
oil shales, particularly in the Green River
formation of Colorado, Utah, and Wyoming were
a larger and more tempting target. We felt our
strengths, at that time, were in refining and
marketing. We also had a pretty good reputa-
tion in secondary crude oil recovery using
unique production techniques. We wanted to
capitalize on our capabilities and try to correct
our weaknesses.
Everything changed for Sohio in 1969 when
Sohio acquired British Petroleum's interest in
Prudhoe Bay. We have had to develop that
field on the North Slope of Alaska. We, with
British Petroleum, own a major portion of the
trans-Alaskan pipeline. Sohio put $6 billion
into Alaska. Just prior to our involvement with
British Petroleum, Sohio was an $800 million
corporation. During the past 10 years, the
company has grown into an $8 billion corpora-
tion. This has required a phenomenal job of
financing. Most of the growth was realized by
borrowing money which must now be paid back
with interest. Very large increases in Sohio's
revenue will be required to accomplish this.
Sohio has evolved as a major domestic
crude oil producer. This has not in any way
dimmed its interest in oil shale and tar sand.
Our preliminary economic analyses, going back
to 1963, indicated that oil shale development
had a certain amount of justification. This was
based on the assumption that a workable pro-
cess could be developed. Our general
objectives from the very beginning have been to
acquire oil shale reserves, develop workable
processes, and get into commercial production.
These objectives have not changed.
Our projections for oil shale commercializa-
tion have been periodically upgraded. We know
from the work that we have done, particularly
with Paraho, that the economics are improving.
These benefits have been due, in part, to the
success of our field work. It has also been
due, in part, to the legislative and administra-
tive actions that we have helped obtain for oil
shale and tar sand at the state and federal
levels.
What has been accomplished in the legisla-
tive and administrative areas? We obtained
exemption from price control for shale oil. We
got shale oil qualified for entitlements. We
originally thought that when we obtained the
price control exemption that we automatically
qualified for entitlements. However, we found
out with a change in administration that one
had to go through the action of getting it
qualified. So we went through the actions.
Shale oil and tar sand oil are now qualified for
entitlements. In addition, the last Congress
approved an extra 10% investment credit.
In generating economic figures for a hypo-
thetical commercial oil shale plant, we must
assume that the process works. This has never
been demonstrated in a full-size, single module
for any of the candidate processes. But, if
you make that assumption for a cash flow paper
study, you will find that it takes about 10
years of operation of an oil shale plant before
you run out of tax deductions and tax credit.
Only then would you begin to look for some-
thing like the proposed $3.00 a barrel tax
credit. It takes a long time in an investment
intensive business, such as oil shale, before
you finally run out of tax offsets.
The new extra 10% investment credit did
not noticeably improve the marginal economics of
a hypothetical, pioneer oil shale plant run as a
corporation. But, such a plant run as a ven-
ture by a profitable parent company or by a
group of companies would show an improvement.
This assumes other taxable profits are available.
Then the extra 10% investment credit could be
taken directly into the parent company or
companies year by year. This improves the
economics of the oil shale plant for a venture.
Such a venture could use both 10% investment
credits and the proposed $3.00 a barrel tax
credit to help make the shale oil plant look more
attractive. However, there are a lot of com-
panies that may not be able to do this.
Another bill passed by the last Congress
covers alternate fuel acceptability in lieu of coal
conversion. That is, you could use shale oil or
tar sand oil, if they were available, as boiler
fuel instead of having to convert to coal.
Conversion to coal can be very expensive.
This bill is going to help shale and tar sand
some time down the road.
Recently, the government participated in
funding a 100,000 barrel shale oil production,
shipment, and refining program. The produc-
tion was done by Paraho and the refining by
Sohio. Both programs have been completed.
Important progress was made. We are ready to
scale-up the Paraho technology into a single,
full-size module.
Finally, by way of Congressional action,
$15 million was appropriated by the 95th Con-
gress to initiate a full-size, above-ground
module program. There are still some risks
involved even with the Paraho process. We
20
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should scale-up one or more processes that
have been demonstrated in semiworks equipment
to module size before proceeding to commercial
production. The Congress has already provided
the Department of Energy with the necessary
tools to get started. The Governor of Colorado
is dedicated to the module concept for oil shale.
Gradual oil shale development would be desir-
able. This is true not only from the
government's point of view but also from
industry's point of view. We never know who
is going to stab us in the back next. As a
result, we do not want to have too many billion
dollars on the table. As a matter of fact, we
do not even want to have too many million
dollars on the table. So, we do need stability
and additional safeguards. We need incentives.
We need to know that the government really
wants us to proceed with oil shale development.
No better indication could be obtained than the
DOE's implementation of the joint government-
industry funded, above-ground retort module
program.
Many of the people here have talked about
the technological and the environmental aspects
of oil shale. I will go a little bit more into the
policy and political side of it. I do not mean to
say this in a disrespectful way, but there have
been less than friendly and often illogical
government postures toward oil shale. Industry
will get going in one direction, such as the
prototype leasing program or the Paraho Oil
Shale Demonstration, and all of a sudden some-
thing gets in the way. I have tried to identify
what caused these changes without success.
There has got to be somebody in there some-
where that is saying, "Let's change the
signals." When this happens it usually shuts
off on-going programs or operations which are
moving ahead at a reasonable pace. I hope this
does not continue to happen.
In addition to the $3.00 a barrel tax
credit, which I pointed out will be helpful in
certain circumstances to certain people, there
are other things that need to be done. Above
all I think the DOE needs to implement the
$15 million program which Congress has already
approved. This should be done before we go
back to Congress and ask for more. This
would certainly get some people going who are
not attracted at all by the $3.00 a barrel tax
credit.
Let's also support the Department of
Defense which has favored large guaranteed
purchase contracts at prices high enough to
encourage shale oil production. One problem
with a purchase contract for shale oil is that
you cannot "bank" it because bankers will look
at it and laugh at you since nobody has ever
run that kind of a facility before. Bankers are
not about to lend money using as collateral a
plant that they are not sure will work. One
way we may be able to help borrowers convince
bankers that a proposed oil shale plant is good
collateral, is for the developer to be able to
show that he is going to use a process that has
been successfully demonstrated in a full-sized
module. Here are the results of the demonstra-
tion. This process does work. The only other
way is through a government guaranteed loan.
However, such loans will be helpful to some
people, but they are of little attraction to the
major companies. It is alright to be able to say
you can fall back on the government to pay the
debt in the event the plant goes bad, but major
companies could not afford to let that loan go
bad and hurt their credit rating.
To summarize, there are many incentives
needed to encourage oil shale development by a
wide range of different types of potential de-
velopers. I believe they should have a wide
range of incentives from which to choose as it
is very important to this country to begin oil
shale development in an orderly fashion now.
Progress in this regard is being made in ob-
taining incentives. We already have:
1. Exemption from price controls and
qualification for entitlements. Both of
these will be phased out with the
phasing out of crude oil price
controls.
2. An extra 10% investment credit in
addition to the normal 10% investment
credit.
3. Acceptability of shale oil as boiler
fuel in lieu of converting to coal.
4. The $15 million appropriation to
initiate a joint government-industry,
above-ground oil shale module
program. Its early implementation by
the DOE, using its existing authority,
is needed.
5. Loan guarantee authority, but no
appropriation.
Unfortunately, • the Department of Energy
is not making full use of the tools we already
have. As a result, little of substance, little
that is real, is being accomplished.
Now we are proposing the $3.00 a barrel
tax credit as an additional incentive. While I
agree with this, I do not feel it should be done
to the exclusion of the already approved joint
government-industry funded module program
nor to the exclusion of loan guarantees or
purchase contracts. We need to get the
Defense Production Act extended and the pur-
chase of crude shale oil and synthetic crude
included. It was unwise last year to get hung
up trying to pass only one thing, the $3.00 a
barrel tax credit. Let's not have to regret
making the same mistake twice. With a well
structured, diversified incentive program, we
can minimize our maximum regrets.
Status
Since 1963, Sohio has acquired a very
significant spread of oil shale properties and
21
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water rights in Colorado and Utah. Much of
this property is held jointly with other people.
One of our ventures is the White River Shale
Project, which we jointly support with Sun and
Phillips. Rees Madsen will talk about the White
River Shale Project. Sohio holds the U-b lease
which is dedicated to the White River Shale
Project. We also hold the Skyline #1 and
Skyline #2 properties which are adjacent to the
U-b lease. Sohio and Cleveland-Cliffs Iron
Company hold the Pacific property in Colorado.
We are in these ventures because we mean to do
something about oil shale if the incentives are
right.
Although we are no longer a member,
Sohio organized Colony Development in 1964.
Colony attempted to demonstrate the TOSCO
process. The results were not encouraging
enough for Sohio to be willing to join with
TOSCO and Arco in their proposed commercial
plant. This plant was deferred indefinitely in
1974 and has remained just over the horizon
ever since.
In 1971, Sohio began to organize the
Paraho Oil Shale Demonstration. That group
eventually included Arco, Exxon, Texaco,
Mobil, Shell, Amoco, Chevron, Marathon,
Phillips, Sun, Gulf, Southern California Edison,
Kerr McGee, Cleveland-Cliffs Iron Co., a group
of independents headed by Webb Resources,
and Arthur G. McKee & Co. Most of these
people joined the Paraho group only after
making a thorough study of what was going on.
They have had a significant influence in the
Paraho operations. However, they do not own
Paraho, which is still a small business, but
they have the right to license the Paraho oil
shale process at a very reasonable royalty rate.
We think the success of the Paraho Oil
Shale Demonstration, including a small 10,000
barrel refining program conducted by the Navy,
led to the DOD/DOE program to produce, ship,
and refine up to 100,000 barrels of Paraho
crude shale oil.
Since the completion of the 100,000 barrel
program, which was terminated prematurely by
the DOE, Paraho has phased out its operations.
It was necessary to release a great number of
Paraho's people because the $15 million appro-
priation to initiate a full-size module program
was not being implemented by the DOE. Paraho
has been able to pick up a minor contract to
terminal all of the shale oil for all of the other
projects that the DOE has been sponsoring.
These other projects are all in situ projects.
This oil is costing a great deal more to produce
than was Paraho's oil. We think in situ can
make a very important companion contribution to
the conversion of oil shale to shale oil. But,
we do wish that these in situ people would
produce more oil. The amount we have received
for storage has made for pretty lean pickings in
the storage business.
Paraho has been pushing for a module
since 1974. First we discovered that Paraho
did not have enough shale mining authority to
be able to feed a module. We went to the
Department of Interior to get additional shale.
The Department of Interior referred us to the
Navy since Anvil Points is located on the Naval
Reserve. The Secretary of Navy, after con-
ferring with the Chairmen of the Armed
Services Committees of the House and Senate,
authorized the use of 11 million tons of shale.
We began organizing to build the Paraho
module about the time President Ford came out
to see us in 1975. We took him through the
plant and told him what we had accomplished
and what we wanted to do. The President was
very favorably impressed and encouraged us to
proceed. We think, at this time, we had
enough industry support that it could have
been done with private funds. A short time
after President Ford left, one of the ERDA
environmentalists came to Anvil Points. He said
that we were not going to be allowed to build a
module unless we got an Environmental Impact
Statement (EIS). That was in the third quarter
of 1975. We advised ERDA that we already had
an Environmental Impact Statement and we had
designed our proposed module to fit within it.
However, the Colorado Open Space Council had
written a letter and said that if ERDA did not
require Paraho to get an Environmental Impact
Statement that they would be sued. ERDA did
not want to be sued, so we had to get a new
impact statement. ERDA's representatives said
they would work very diligently with Paraho
and would have the EIS out in nine months.
This was in September of 1975. It is now
almost 3H years later.. We still do not have the
Environmental Impact Statement.
Our new EIS became involved in a jurisdic-
tional dispute between different offices within
the ERDA organization. Then the DOE took
over. Additional delays followed. The EIS is
now in the final draft form. I am told we
should have the Environmental Impact Statement
about the time we have the go-ahead from the
DOE to initiate the module under the $15 million
program.
I hope all these module pieces fit together.
Alternate energy development is important to
our country. We are not trying to do anthing
objectionable. We are trying to prove a pro-
cess. We are trying to do it in the open where
everybody can come and observe. If we cannot
do it well, then we do not deserve to do it
commercially. The same standards should be
applied to others. We think everyone ought to
have this chance.
In an effort to go ahead with the
$15 million program, which the previous Con-
gress passed, Paraho submitted an unsolicited
proposal to get it underway the day after
President Carter signed the bill. We had the
22
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complete cooperation of the Colorado Congres-
sional Delegation, the Governor of Colorado,
and all the members of his office. We were
ready to go. We had contracts with firm com-
mitments for the industry portion of this joint
government-industry funded program with The
Standard Oil Company of Ohio, Phillips
Petroleum Company, The Cleveland-Cliffs Iron
Co. and Arthur G. McKee Engineering Co.
These companies all wrote to Dale Myers to let
him know that they would back up this program.
Unfortunately, while not accepting Paraho's
proposal the DOE decided to make a request for
proposals. This will delay the program by
about one more year.
In conclusion, I believe we have ample
justification for doubting that the government,
particularly the DOE, really wants us to pro-
ceed with oil shale development. If this
conclusion is wrong or if the government's
position has changed, I would like to see some
positive signs to counteract all of the negative
signs we have received. This requires that the
DOE actually get involved in the above-ground
retorting by carrying out the joint government-
industry module program, initiation of which
has been authorized and appropriated by the
Congress. If this is done, and if successful
experience in oil shale retorting in the semi-
works scale means anything to the government
in selecting a process, I am sure Paraho will
have a place in the program. Such a program
is badly needed and is long overdue. We
cannot be sure any process will work commer-
cially until we actually build a module and try
it out in full-size.
Dr. Coffer introduced John Knight, man-
ager of the Superior Oil Shale Project. He
presented a talk based on slides outlining the
multi-mineral processes status. We are pre-
senting it in the minutes along with selected
copies of the slides.
SUPERIOR OIL CO., JOHN KNIGHT.
ASSISTANT DIVISION MANAGER
Where
Northwestern Colorado on the northern
edge of the Piceance Basin about twenty-two
miles west of Meeker and thirty-five miles east
of Rangley (Figure 1, Figure 2).
What
Multi-mineral process for recovering oil,
alumina, nahcolite and soda ash from oil shale
(Figure 3).
When
As an historical introduction, Superior's
multi-mineral oil shale program entails surface
processing for producing nahcolite, oil, alumina,
and sodium compounds. Over the past five
years, we have constructed and operated pilot
plants on all steps in the processing and deter-
mined the technical viability and economics
involved. However, during this time we have
not been able to consummate a 1973 land ex-
change application to block our lands into an
economical mining configuration. Our resource
lays in a long narrow L shape that requires
prohibitive ventilation, haulage, and access
cost. The Bureau of Land Management seems to
have made considerable progress in the last six
months, which includes an ES preparation,
etc., so that a decision on this exchange appli-
cation can be made. Currently, to maintain our
technical staff and position, we are licensing
retorting and mineral recovery technology
domestically and internationally. We have
reduced our number of employees from more
than seventy during pilot plant work to twelve
key technical people at the present time.
How: Nahcolite Recovery
Nahcolite is separated from the mine run
material by a selective crushing and photo-
sorting technique. The nahcolite occurs in
nodules in the base shale, and being more
friable can be selectively crushed and released
from the shale. Commercial size photosorting
equipment has been used to separate commercial
grade nahcolite from the shale (Figure 4).
Nahcolite has been used in pilot tests as a
scrubbing agent to reduce SO2, NOX, and
particulates form coal-burning electric generat-
ing facilities in Colorado and other states.
These successful pilot tests hold the promise of
reducing emissions in many generating facilities
as well as use in various chemcial and refinery
clean-up operations.
Oil Recovery
Both circular and straight grates have
long been in commercial use for iron ore pellet
sintering, cooling, and other kiln applications.
Superior's process development effort focuses
on adaptation of the circular grate process for
oil shale retorting. This effort included con-
struction and operation of an adiabatic fixed-bed
retort designed to simulate the conditions
encountered by a section of solids as it travels
through the separate processing zones in the
circular grate. The adiabatic retort tests iden-
tified the significant process variables and their
effect(s) on cost responses such as through-put
rate, thermal efficiency, product yield, etc.
Cost sensitivity analyses established optimum
ranges in which to design and operate the
circular grate oil shale pilot retort, which was
later constructed (Figure 5).
The pilot circular grate retort operations
defined design and scale-up information for the
oil removal system, which had never been
tested in prior circular grate applications.
23
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Pilot plant operations also confirmed the mechan-
ical reliability of solids flow on four types of
shale. The primary results of this process
development effort have been:
1. Attainment of thermal efficiency for the
crossflow circular grate that approaches
those achieved in countercurrent flow
devices
2. Product oil yields of .over
Assay
of Fischer
3. Development of a proved oil recovery
system
4. Optimized throughput and gas rates per ton
of oil shale processed
These successful process development
results can now be combined with the proven
mechancial reliability of commercial-size circular
grate heating-cooling equipment for oil shale
retorting.
Alumina and Soda Ash Recovery
We plan to meet our plant and processing
needs for water requirements from the deeper
salt content groundwater aquifers. These
saltwater requirements total approximately 7
ft3/sec gross production. They are predomi-
nately for the alumina and soda ash recovery
processes (Figure 6).
The salt water is used for leaching and
washing the retorted shale of mineral content.
A mineral rich pregnant mother liquor is pro-
duced. Multi-effect evaporators and crystal-
lizers generate water condensate from the
pregnant mother liquor in production of alumina
and soda ash products. The resulting water
condensate is used for the major plant fresh-
water needs. Minor plant freshwater needs,
such as construction drinking water, etc.,
totaling approximately 0.177 ft3/sec, will be met
from our surface water rights either through
irrigation or conditional decreed surface rights.
Actual replacement, storage, or exchange for
our surface water is in the process of refine-
ment and are not defined at this time.
Environmental
Key environmental aspects of Superior's
multi-mineral shale processing are:
1. Use of low quality energy in the
mineral winning processes; alumina-
soda ash for an overall very thermal
efficient interfaced processing complex
2. Return of leached spent shale to the
mine (Figure 6-A)
3. Use of salt water from the Leach Zone
vs. fresher surface water, thus
decreasing salt content in the White,
Green, and Colorado rivers
4. No water discharge from Superior's
project
EPA Decisions That Affect Venture
Economics in GeneTaT
The actions and decisions of the Environ-
mental Protection Agencies indeed affect all
ventures or facilities that produce goods for the
citizens of our society and the world. Goods
are food, energy, building materials, etc.
These are economical effects that determine the
bottom line risk evaluation. The venture eco-
nomics are the real test of a venture's worth to
society.
In an economic evaluation and a risk
analysis four things are of major concern:
1. Processing risks, engineering risks,
and marketing risks are private in-
dustries' historical burden of doing a
good job in the management and tech-
nical areas, so that these investors'
risks are minimized to the point they
are willing to be accepted.
2. How long will a society allow the
investor(s) to own the facility? Stable
ownership laws have existed in the
U.S. since our birth as a nation. We
tend to take stable ownership for
granted in the U.S. If society's needs
change, compensation is extended to
the owners.
3. What will be your yearly rent? Taxes,
interest rate of return to draw capital,
are fairly straight forward. In a
stable society these can usually be
predicted for a reasonable economic
life.
4. Jf you obey the rules, laws, and
regulations now, will you be allowed to
operate and realize production of goods
when the unit is started up some years
in the future? Thus, do these rules,
laws, and regulations have a reasonable
economic life?
The effect on a discounted cash flow
analysis is essentially the same: if (1) society
nationalized your facilities after five years or
(2) lets you build the facilities, but does not
allow operation or use for five years because it
has decided to change the rules.
The lack of stability or long-term commit-
ment by a society on environmental laws and
regulations makes risk evaluation very tenuous
in this area.
24
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THE SUPERIOR OIL COMPANY
THE SUPERIOR OIL COMPANY
STRUCTURAL CROSS SECTION A - A'
SHOWING
PILOT ADIT AND PILOT MINE
.
STEP 1 !VU
SPENT SHALE '
DISPOSAL
SHALE
1
STEP 2 1
BLOCK DIAGRAM
LTI-MINERAL PROCESS
T
SPENT SHALE
1 STEP 3 1 STEP
4
NflHCOL,TE SHAU >| OIL AS" >| ™™**
RECOVERY | ^ RECOVERY | ^ MgAMH
NAHCOLITE
OIL
SODA ASH ALUMINA
Figure 2. Structural Cross Section A - A1
Showing Pilot Adit and Pilot Mine
Figure 3. Block Diagram Multi-Mineral Process
-------
CT)
THE SUPERIOR OIL COMPANY
PHOTOSORTING SYSTEM
FEEDER
A
SCANNER'
e:
BELT CONVEYOR
:gv»
<7«
AIR •
.BLAST
WASTE
BELT
; ACCEPT
BELT
Figure 4. Photosorting System
THE SUPERIOR OIL COMPANY
CONCEPTUAL DESIGN
SODA ASH PLANT
' MULTIPLE EFFECT
CRVSTALLIZERS
CONDENSED
WATER
PERIODIC PURGE
TO SPENT SHALE
•ODAASH|<
Figure 6. Conceptual Design Soda Ash Plant
THE SUPERIOR OIL COMPANY
AFTEI AMHUi G McKEE A CO.
Conceptual View of Circulw Crate Retort
Figure 5. Conceptual View of Circular
Grate Retort
THE SUPERIOR OIL COMMNV
ALUMINA AND SODA ASH RECOVERY PROCESS
Figure 6-A. Alumina and Soda Ash
Recovery Process
-------
TSOSCO, MIKE SPENCE
TOSCO Corporation has an active oil shale
project in Utah and is also a participant in the
Colony Development Operation project in
Colorado, which was previously described by
Les Ludlam. In addition, TOSCO has other oil
shale land holdings in Colorado, including both
patented and unpatented lands. The Sand Wash
Project, located in Uintah County, Utah, is in
the early stages of development by TOSCO Cor-
poration. The project is located south of
Vernal, approximately fifteen miles west of
federal lease tracts U-a and U-b. TOSCO
acquired some 20,000 acres of state leases,
located in noncontiguous blocks, in the early
1970s. Thereafter the five major lease tracts,
which comprise some 14,000 acres, were unitized
by action of the Utah State Land Board and the
Board of Oil, Gas and Mining. The unit is
called Sand Wash Unit and TOSCO operates the
unit under unit agreement and a cooperative
plan of development approved by the State of
Utah.
Following approval of the unit agreement
TOSCO filed a mining plan with the State Board
of Gas and Mining to conduct environmental
work and resource evaluation, and field studies
have been conducted in both those areas during
the past several years. In 1978 TOSCO filed
an amendment for their plan calling for the
sinking of an experimental mine shaft to be
followed by experimental mining. The amend-
ment was approved by the state in late 1978
along with the air quality permits that were
required to carry out the project. Under the
unit agreement, Tosco is required to spend
some $8 million in development costs over an
eight year period in $2 million increments every
two years. The first $2 million increment was
completed in December of 1978.
Under the plan, which has just been
approved, TOSCO will start site preparation
and field work on the experimental mine shaft
in 1979. Shaft drilling will begin in late 1979
or early 1980 and will take a period of eighteen
months to two years to complete. Shaft sinking
will be followed by a period of two to three
years experimental mining.
'"''At this point TOSCO regards commercial
development of the Sand Wash Project as a long
range project. However, study of plant design,
water, transportation, socioeconomics, and all
the various other matters that go into commer-
cial project planning are being examined.
TOSCO maintains a field office in Vernal,
which has been staffed by three or four people
over the last several years. Once the mining
development program commences that staff will
increase.
UNION OIL, ALLEN HANDLE
Union Oil Company of California became
interested in oil shale more than fifty years
ago, when it started acquiring oil shale lands.
The principal portion of these holdings are
30,000 acres north of Grand Valley, Colorado.
Twenty thousand of these acres are oil shale
bearing. Water rights were obtained along with
the lands so that we now have sufficient water
rights to supply a commercial plant.
Union has conducted continuing research
on oil shale retorting technology over the
years. A highlight occurred between 1954 and
1958 when Union operated a semiworks plant
located on its Colorado property. This plant
demonstrated Union's "Retort A" process.
Since 1974 Union has been studying the
best method to commercialize its technology. A
new semiworks plant was considered and found
to be too costly to be justified by the know-
ledge to be gained. A full-scale 50 MB/D
plant, consisting of six to eight retorts, was
also studied but was found to be very costly
and premature for the current state of the
technology.
An experimental plant consisting of a
single commercial-sized retort was selected as
the next logical step in the technical develop-
ment. A single commercial retort represents
the minimum size needed to obtain necessary
information, such as determination of operating
limits of a full-size retort, development of
process improvements that can only be
accomplished in a large facility, gathering of
economic data for future commerical develop-
ment, and development of techniques to secure
the best attainable control of environmental
impacts.
When environmental issues are resolved
and economic conditions are improved enough to
justify the expenditure, Union is prepared to
start construction of its Long Ridge Experimen-
tal Shale Oil Project.
Although other incentives would be useful,
we at Union firmly believe that a $3/bbl tax
credit is a proper economic incentive to assure
construction of the first experimental facility.
This incentive has the following advantages:
1. It is production oriented.
2. The developer assumes the technolog-
ical risk.
3. It does not require government selec-
tion of one process but allows
construction of a number of pioneer
plants using various technologies.
27
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4. There is no cost to the government
until and unless production begins.
5. The cost to government in lost income
tax revenues is offset by lower imports
and improved balance of payments.
6. This incentive is simple and inexpen-
sive to administer.
Application has been made for the following
permits:
1. Prevention of significant deterioration
from the Environmental Protection
Agency
2. Emission permit from the Colorado Air
Pollution Control Division
3. Regular operations permit from the
Colorado Mined Land Reclamation Board
4. Special and conditional use permits
from Garfield County
The use permits from Garfield County were
granted in November 1979. The others are
under review by the agencies.
We believe that we can operate a shale oil
plant that will comply with all existing environ-
mental regulations. However there are several
new laws that are currently being translated
into regulations. These regulations must be
worded to achieve the legislative intent of these
new laws and without placing so great a burden
upon the oil shale industry that it is prevented
from developing.
Union believes that the next step in oil
shale commercialization is construction of one or
more single commercial retorts using various
technologies. Union has the resources to do
this and is ready to proceed when a proper
economic climate is provided and when all per-
mits are obtained.
Question: (Sam Farlane, DDE-Denver) What
would you do if you built the best
retort and failed because of techno-
logical and engineering reasons?
Answer: Frankly, I have not considered that
possibility.
Question: (Arnold Pelofsky, SAI) What is your
cost of the single modular program?
Answer:
Question:
In the neighborhood
$128 million.
of $100 to
(Pelofsky, SAI) If it were close to a
billion dollars, would Union still feel
the same about the $3.00 tax credit?
Answer: I really cannot speak to that. I do
not even know if it has been evalu-
ated in that light. Our feeling is
that this commercial-size retort and
that the experimental program at
that level is going to allow us to
make improvements in the technology
that are going to improve its eco-
nomics .
Question: (Les McMillion, EPA-Las Vegas) What
is the estimated yield of the single
unit?
Answer: Approximately nine thousand barrels
per day.
Question: Are you super hygrading? What is
the yield of your oil shale?
Answer: Forty-two gallons per ton.
Question: Is that typical of your reserve?
Answer: No our reserve varies quite a bit.
The seam is about 120 feet thick.
Question: Is it economically viable below the
forty-two gallon per ton? If it were
thirty gallons per ton, would the
$3.00 help you very much? Would it
make it economically viable?
Answer: Probably not.
Dr. Coffer next presented Rees Madsen of
White River who gave his review of their pro-
ject using a series of slides for illustration.
WHITE RIVER OIL SHALE, REES C. MADSEN,
ENVIRONMENTAL COORDINATOR
The White River Shale Project is a joint
venture of three oil companies, Sohio Natural
Resources Company, Phillips Petroleum Com-
pany, and Sunoco Energy Development
Company. These three companies established
the White River Shale Project for the sole
purpose of developing the two federal orototype
oil shale program lease tracts in Utah
(U-a/U-b).
These tracts are located about fifty miles
from Vernal, Utah, each one of them is a 5,120
acre tract, 10,240 acres in total size, and are
located in northeastern Utah (Figure 7).
The purposes of the federal prototype oil
shale leasing program have been discussed and
the need to proceed with the concept has been
explained. We still feel that the idea of
demonstrating oil shale technology in the field
and answering the questions about economics
and environmental concerns and technical
28
-------
constraint is important. We still subscribe to
the goals and to the concepts of the prototype
program.
White River Shale Project (WRSP) is not
now a company. It is a joint venture respon-
sible to the three owner companies. We are an
operating entity in essence, responsible solely
for the development of tracts U-a and U-b.
Over the last several years, starting in 1974
when WRSP was formed, we have used contrac-
tor services to carry out.our various activities
(Figure 8). One of the things that we have
been doing since 1974 is environmental type
work. One of the things that has been accom-
plished is the "Detailed Development Plan" that
proposed a program for providing a 100,000
barrel per day facility on U-a and U-b. We
have done other things since the submission of
that "Detailed Development Plan" in June 1976.
The geologic exploration program is typical of
the program that was carried out on the other
federal prototype lease tracts. There were
over twenty holes drilled, some of them were
for core samples and some of them were for
hydrologic studies. Some serviced a dual
purpose in defining the geology and hydrology
of the area. Our environmental studies were
dictated by the terms of our leases on U-a and
U-b and involved a two-year program to review
all aspects of the environment (Figure 9).
EPA people and DOE people as well as
industry are familiar with the trials and tribu-
lations of the baseline program. Our cost to
date for the on-going environmental program is
almost $8 million and that combined with the
$6 million engineering plan brings us up to a
pretty hefty investment to date. If you add in
the $72 million that has been paid to the federal
government as the first three lease bonus
payments, you can see our owner companies
have invested over $85 million in the program to
date.
Some of the things that we developed as
far as engineering studies are concerned are
technology evaluations and economic evaluations.
These were all included in the preparation of
the "Detailed Development Plan." It describes
in detail what we will be doing in regard, to
developing the properties.
The two-year baseline program was an
effort to develop an expertise insofar as how
these things should be done in future leasing
programs by the federal government. I am
sure that we would never do them again the
way that we did, knowing what we know now.
These programs should not be taken as prece-
dents for future leases or future monitoring
programs—we should be able to learn from what
we did and go forward. I have seen occasions
where the baseline program for the federal
leases has been used as models and frameworks
for discussing baseline programs for other
programs. I think we need to take a close look
at that before we do go in that direction.
As far as the "Detailed Development Plan"
was concerned at the time we submitted it, it
was clear to us and the owner companies that
modular development was required to prove the
technology and also to create a better basis for
developing economic evaluations and to answer
the environmental questions that would allow us
to plan for a commercial facility. We also
identified several problems that needed to be
addressed such as air quality, which I will
describe in a little more detail later, national
energy policy, and some of the lease provisions
under the prototype program.
The "Detailed Development Plan" is des-
cribed in the plans for our operation. We are
talking about a deep room and pillar operation
about 1,000 feet below the surface of the
ground. In our original "Detailed Development
Plan" our approach was a surface retorting
technology. We are now investigating the
application of an in situ technology as a secon-
dary recovery process. But the concept we are
still working on as a primary concept is room
and pillar mining, bringing the material to the
surface and retorting it. Since the submission
of the "Detailed Development Plan" we have
continued exploration studies and continued our
evaluation of retorts.
It might be good to point out at this time
that we are not in the technology development
business. The White River Shale Project's
expressed goal is to use demonstrated tech-
nology in the development of our properties.
We have done some tests where we have pro-
cessed Utah shale through both the Paraho
process and the Union process. We have run
shale oil combustion tests and continue to do
environmental studies, especially in areas of
concern like ozone levels that have been mea-
sured as being quite high, and in regard to
revegetation research, which has not been
completely defined in the Utah area. We still
consider shale oil to be the closest synthetic
fuel to commercialization as far as liquids are
concerned. We still feel that this is correct
and have not seen anything to change our
minds. To date our three companies are com-
mitted to the eventual development of the oil
shale resources.
Water is a prime ingredient in any kind of
processing. We are looking to the White River
dam in the State of Utah to satisfy our water
requirements. This dam has been approved and
accepted by the State of Utah. In fact they
are the ones who will construct it. Bond issues
have been passed in the state so that the dam
will be financed by the state. We expect this
to be successfully constructed and to provide
water not only for our operation but also for
other oil shale developers in the State of Utah.
29
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The White River Shale Project is presently
delayed from moving forward in the field of
development activities. The original delay was
environmental, one having to do with an ozone
level that was recorded near our site and was
above the national ambient air quality stan-
dards. That was started in November of 1976.
Before that one-year suspension ended, we ran
into problems concerning the title to the proper-
ty, and we are presently waiting for litigation
to be concluded that will provide us a way of
knowing that we do have a lease on the proper-
ty and we can plan for development for the
future. Economics and technology development
needs also bear on our inability to go forward
at this time. But we are securing our position
and working toward resolution of these prob-
lems. One of the things that we are here to
talk about is how we get through some of the
regulatory problems—get down to the bottom
where we can mine some oil shale and produce
some shale oil and do that in an environmentally
acceptable manner. This group has a real role
to play in this.
Let's look at some environmental factors of
concern to us. I know the EPA is not respon-
sible for all of these factors or problems.
Neither is the Department of Energy, but this
is what we as developers see when we look out
at the regulatory picture. We see things like
dealing with wilderness classifications where
these areas might become "Class I" prevention
of significant air quality degradation areas that
might be located fairly close to areas of de-
velopment. We see air quality regulations, both
existing and proposed, that increase concerns
over our ability to meet such stringent require-
ments. We see the classification of areas like
Dinosaur National Monument as "Class I" that
will provide questionable environmental pro-
tection, but have a potential adverse effect
upon the development of oil shale.
We see problems in getting environmental
impact statements prepared. The White River
Dam is ready to be constructed (Figure 10).
The money is ready through bonds, yet we are
having difficulty in getting the environmental
impact statement procedures started. We worry
about wild and scenic river classifications, toxic
substance control regulations, resource recov-
ery and conservation act regulations having to
do with hazardous substances, and mine land
reclamation. We are watching very closely the
efforts to decide whether or not to put shale
mining under the auspices of the Coal Surface
Mining Reclamation Act. Also of concern in our
planning are existing and evolving water quality
standards, endangered plant and animal regula-
tions and, of course, efforts to solve the
socioeconomic problems associated with develop-
ment. I think the overall point here is these
moving targets. We are not in a position to
clearly know what all the rules are and what all
the regulations are that we have to face. If we
can gain a better appreciation of each others'
problems as a result of today's meeting, it
certainly would be a help.
Some of the steps that we see as important
and are progressing on are:
1. Reduce the number of permitting
agencies.
2. Complete the "Handbook" that we
understand EPA is working on that will
be available to those of us who are
working in the permit area. This will
help guide us and save us from making
false steps and false starts. It should
help us pull together the interpreta-
tions and administrative ideas as well
as regulations that bear on getting
permits for our operation.
3. Revise the Ozone standard.
4. Resolve how processed shale fits in
with the Resource Conservation and
Recovery Act.
5. Provide a grandfather clause, or the
freezing of compliance standards, so
that when we get a permit we know in
that permit what kind of standards and
what kind of performances are re-
quired. This should allow us to be
relieved from compliance with some of
the requirements that will evolve in
the future and certain kinds of regula-
tory changes.
In summary, all three companies have a
major commitment to oil shale development.
Money expended to date represents $85 million.
We are also still looking at bonus payments
under our leases of $48 million. We have
conducted extensive tests. Utah is supportive
of the oil shale business. We believe that a
modular demonstration program is a must
whether it is done by us or by those who are
developing technology at other locations.
30
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WRSP
LOCATION
Utah
Area of location map
WRSP ORGANIZATION CHART
Scale in miles
PHILLIPS
PETROLEUM
COMPANY
1
1
CLEVELAND CLIFFS
IRON COMPANY
Mining consultant
SUNOCO ENERGY
DEVELOPMENT
COMPANY
WRSP
Operating entity
BECHTEL INC.
Overall engineering
management
^•MMH
SOHIO
PETROLEUM
COMPANY
1
CONSULTANTS
• Bingham Engineering
• Western Environ-
mental Associates
• Utah State University
1
VTN
Environmental
studies
Figure 7. WRSP Location
MONITORING STATIONS
AND
DRILLING LOCATIONS
Monitoring station
Drilling location
Proposed plant site
Figure 9. Monitoring Stations and
Drilling Locations
Figure 8. WRSP Organization Chart
STATE OF UTAH
PROPOSED DAM AND RESERVOIR
ON WHITE RIVER
(-»Lease boundary
Figure 10. State of Utah Proposed Dam
and Reservoir on White River
-------
EPA, DOE AND STATE
PRESENTATIONS
DOE-LARAMIE ENERGY TECHNOLOGY CENTER,
ANDY DECORA, DIRECTOR
When Deputy Undersecretary Gouraud was
here and talked to many of you about the
constraints of the oil industry last April, many
of you pointed out that the permit process was
one which was a very large roadblock. The
deputy undersecretary heard you at that time
and started a study funded through our office
and contracted out to Science Applications,
Incorporated, to try to unravel a lot of that
process. The first phase of that study has
been completed, and we can entertain through
my office requests from many of you who are
interested in hearing about that. We will send
the Phase I report to you to indicate some of
the level of work that was done there. I think
the deputy undersecretary should be commended
from the standpoint of attacking this very
considerable area insofar as restraints on de-
velopment are concerned. , Phase I is done, and
we are proceeding with other elements of that.
The two investigators are Dr. Harry McCarthy
and Phil Aramis of Science Applications.
Many of you have heard of the cessation of
Talley Industries fracturing experiments in
Southwestern Wyoming. You will recall that
under the department's program opportunity,
known as #2, that there were five in situ type
cooperative concerns with industry shared by
the DOE; one of those was with Occidental, one
with Equity, one with Geokinetics, one with
Dow, and one was with Talley Energy in South-
western Wyoming. All five of those particular
operations dealt with one or another category of
in situ experimentation and had various form-
ulas insofar as either cost sharing or the total
commitment on the part of the government in
the funding of the project.
The Talley contract was one which was
100% funded by the federal government and was
operating first in the fracturing phase and
second, depending upon the success of that
phase, a retorting phase in a forty foot zone
of about twenty-five gallon per ton shale in
southwestern Wyoming. The experiment was
something over $1 million, I think $1.3 million
for that first phase, and did have an evaluation
step that was required by the contract at the
time of the completion of the evaluation of the
fracturing of the experiment.
Talley, in about late summer 1978, deto-
nated about 60,000 pounds of their explosive in
the 40 foot zone of shale about 200 feet below
the surface. I was present witnessing that
shot, and it was quite a bang! Following the
detonation an extensive period of evaluation
went on—the site was very highly instrumented
by Sandia Laboratories and other contracted
laboratories to Talley, the subcontractor under
the basic contract. About the first week in
December some thirty technical people repre-
senting National Laboratories, the Laramie
Energy Technology Center, and a couple of
other contractors were gathered together in
Laramie, at which time about six technologists
from Talley gave a very extensive project
review on the analysis of down hole camera
shots of the fractured zone. The technologists
pretty much agreed that many of the sought
after results were not in fact obtained from the
experiment. While it did yield much data, the
expected extent of fracturing had not been
achieved and therefore, that panel of tech-
nologists rendered a recommendation to program
people in DOE in Washington that the first
phase of that contract be considered complete,
and that the retorting phase not be done for
that particular location.
One chief factor that was entered into that
judgment was the fact that simultaneously the
Laramie Energy Technology Center had been
working on its site 12 for a similar kind of
experiment. We were looking to the actual
ignition and the retorting of that site rather
than to run two at the same time. We believe
we had a better level of success in site 12 than
obtained in the Talley Experiment, and, there-
fore, site 12 should go into retorting phase.
.So we are now awaiting the results from Rock
Springs site 12. That site was ignited last
month, and with some difficulty the ignition is
being sustained. Some of the pressures and
flows are not exactly what is wanted at this
particular time. -Those of you in this field
know that the true in situ technology is by far
the most highly speculative and also the one
which we know the least about. We know we
generally cannot get the amount of permeability
that we are actually looking for.
So that is where we are at this present
time. The first phase of the Talley contract,
which was simply one of fracturing the formation
with explosive, was deemed complete. The
exact results as were required by the contract
were not really met—through no fault of the
companies—just the permeability and the extent
of the fracturing were not as good as we
needed.
One final comment--you all know that basis
of work that the LETC has been performing
under the Bureau of Mines, under ERDA, and
then the DOE. Essentially we have the respon-
sibility of the assistant secretary for energy
technology for basic development and assembly
of industry and government data for analysis
across the board of the oil shale technology
33
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development. We have some 166 different task
elements that are represented by work done
both at Laramie and among the National Labora-
tories and among industry. Those things cover
such things as retort modeling, environmental
support, control technology work, process
diagnostic evaluation, and other similar pro-
grams. The financial plan for all of that this
present year is about $26 million.
Question: Would you care to speculate on what
the plan is going to be for next
year?
Answer: It is public and published, but we
do not have our copy.
COLORADO DEPT. OF NATURAL RESOURCES, .
ROBERT SIEK, DEPUTY DIRECTOR
I am the deputy for the Department of
Natural Resources and serve also as the director
of the Office of Mineral Resource Development.
Colorado is anticipating increased activity in the
development of its natural resources. If the
state is to intelligently manage this development,
it will be necessary to have methods in place to
provide a thorough, comprehensive and efficient
review of proposals. Oil shale development is
potentially one of the most difficult to deal with
due to the uncertain nature of the technology
to be used.
To address the oil shale issue, Colorado
with support from DOE is attempting to prepare
a trial for modular development in commercializa-
tion when it occurs. Let me explain briefly
some of the current projects we have under way
in Colorado. The program in the area of air
and water pollution is under the jurisdiction of
the Colorado Department of Health, and our
working relationship is close and we intend to
coordinate as much as possible. We have heard
a lot today of permits, and Colorado is now in
the process of trying to address the permit
situation. We are as aware as anyone of the
confusion and are trying to take steps with the
DOE to alleviate the problem as much as we
can—especially as they appear from all levels of
government, not just state government.
We have several programs going in
Colorado anticipating oil shale development. We
have asked the Colorado Energy Research
Institute to develop criteria for us to judge the
relative success of oil shale technology. They
are working on that now, they have a contract
with Booz-Allen and that will be a continual
program for the next few years. DOE is under
contract to some of the national labs and the
University of Colorado to establish a task force
to study some of the environmental impacts from
modified in situ operations. We are also work-
ing with the U.S. Bureau of Mines and trying
to determine the explosive nature of oil shale
dust. We are working on a joint review
process. We have a demonstration project that we
are working on, the Mount Emmons project that
Amex has in Colorado, which is an extensive
operation. Amex is really a guinea pig to
assist Colorado to develop a joint review process
involving the three levels of government in-
volved with reviewing large major energy and
mineral resource development for the state.
The government reviews of energy and mineral
resource development projects are increasingly
complex technically, legally, socially, economi-
cally, and politically.
Industry complaints about government
regulation and lack of coordination have become
more and more critical. Local citizen groups
opposing and supporting various projects are
more frequently formed to address specific
projects. General public concern with govern-
ment regulation, spending, and taxation have
become major social and political issues. It
seems that almost every energy and mineral
development project proposed in Colorado is
encumbered with conflict and controversy,
which eventually create delays in decision-
making processes and increased costs.
As Colorado experiences accelerated growth
in energy and mineral development, it is be-
coming increasingly apparent that some
mechanism is needed to better coordinate
governmental reviews to enhance public partici-
pation, to minimize unnecessary conflicts, and
to provide industry with greater opportunities
to become involved with government and the
public as early as possible in project planning.
Our project in Colorado is an attempt to provide
such a mechanism.
A joint review process as we currently
view it, is an interjurisdictional review process
that coordinates decision-making processes be-
tween the three levels of government, provides
the public and special interest groups with
additional opportunities to become involved in
all phases of project planning and review. It
provides informal forums in which government,
industry, the public, and special interest
groups have the opportunity to discuss issues
and concerns. It promotes conflict resolutions
through cooperation and realistic compromise.
Many people have asked, "Why do we need
the review process?" We have identified at
least three broad problem areas that point out
the need. First, the heightened national con-
cern for environmental protection as a result of
proliferation of environmental and land use laws
and regulations at all levels of government.
Most of these laws and regulations were framed
incrementally to respond to specific needs.
Minimal attention was placed on the relationships
of these controls.
To complicate matters, the number of
enforcement agencies has also increased. Many
agencies, although functionally related, are
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organizationally separate. As a consequence of
regulatory proliferation and agency fragmenta-
tion, regulatory requirements within and be-
tween levels of government frequently overlap,
conflict, and duplicate one another. Decision-
making actions of enforcing agencies are often
redundant. The proponent is forced to develop
several different sets of information addressing
the same topic for several different agencies.
Interagency disputes concerning jurisdiction and
authority arise, and they all contribute to
decision-making delays, increased administrative
costs, and inefficient use of time and resources.
Second, operational procedures and habits
of project proponents also contribute to delays
and conflicts in the review process. For numer-
ous reasons, some imagined and some real,
proponents are frequently reluctant to approach
governmental agencies or seek public involve-
ment during early stages of project planning.
Consequently, lines of communication are not
established. Agencies and the public are
uninformed about project proposals. Public
concerns are not heard during project planning
when changes can be made with relative ease.
Project proposals are misinterpreted; agency
requirements are misunderstood. Then, as
frequently happens, a proponent may spend
large sums of money on various studies and
reports, only to find when he seeks a required
permit approval or review that his proposal, his
supporting information, or the procedures
followed are not acceptable to the agency or the
public. Thus, the proponent is faced with the
inevitable choice of litigation, spending addi-
tional monies, and absorbing the accompanying
costs of delay, or abandoning his project.
Third, public interest in the effects of
development on quality of life and the environ-
ment has steadily increased in recent years.
Grass roots citizen organizations, organized to
support or oppose specific projects, are be-
coming a popular and effective tool to influence
public and private decision-making. Citizens
seem to be clamoring for more control over
governmental processes and more influence over
public and private decision-making. However,
ongoing public access to project planning and
review does not improve significantly.
Traditionally, public involvement has been
limited to public comment period, protest filing,
public hearings, and litigation. All of these
techniques usually involve negative actions and
adversary conflicts and generally occur after
project planning is complete or well on its way.
Consequently, many projects move smoothly
forward until they reach the public comment
and public hearing stage. Then, because of
misunderstanding, lack of information, planned
actions, and other reasons, protests about the
project are entered into an agency's record,
often creating delays in the decision-making
process. While many such delays are war-
ranted, some are not necessary.
Most conflicts and delays can be avoided
or minimized by providing the public early in >
the review process with opportunities to express
concerns, discuss issues, provide creative
criticism, influence industry and government
thinking, and generally protect their interests.
Such opportunities could result in greater
public and special interest group understanding
and acceptance of projects, better planned and
more carefully developed projects, increased
protection of the environment, and generally
more beneficial projects.
To insure that our project does not stray
from the original intent and to insure that we
address each problem area, we have defined ten
project goals. They may appear to be somewhat
idealistic, but if one stops to think about them
they are ideals that we should be striving for.
They are needed improvements in our govern-
mental system.
1. To coordinate the environmental and
land use decision-making process
between the three levels of
government
2. To encourage an attitude and create
an atmosphere for cooperation and
greater understanding between indus-
try, government, and the public and
special interest groups
3. To provide a rational, systematic
alternative to the existing fragmented
governmental processes
4. To provide a procedural manual to be
used by the state when conducting a
format review of a major energy and
mineral resource and development
project
5. To formulate a process that is more
understandable, predictable and
internally consistent without dis-
turbing established lines of authority
and power
6. To improve intergovernmental cooper-
ation
7. To enhance and improve participation
in governmental decision-making
8. To minimize conflicts, delays, and
associated costs
9. To demonstrate the viability of a joint
review process
10. To identify problems requiring legisla-
tive or administrative attention
Initial consideration of the major problem
areas and project goals have led us to the
conclusion that a joint review process must be
35
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comprised of at least three major components.
First, the permit, approval, and review require-
ments enforced by all levels of government
should be coordinated. This task involves the
monumental job of reviewing all federal, state,
and local permit, approval, and review require-
ments to determine conflicts, duplications, and
similarities. Fortunately, the Department of
Energy recently completed a study called
Permission I, which includes summaries of most
of the regulatory requirements we will need. A
pert chart will be created that arranges all
permit, approval, and review processes into a
logical sequence, utilizing similarities and dupli-
cations and minimizing conflicts.
Second, informal and formal mechanisms
must be formulated to provide the public with
increased access in the governmental decision-
making processes and greater opportunities to
affect industry planning. Alternative public
participation techniques will be discussed and
preferred techniques identified. Third, joint
review procedures are imperative. They will
provide decision-makers with step-by-step
guidance in implementing the process. These
procedures will integrate into one system, the
public participation process, the federal, state,
and local permit, approval and review processes,
operational guidelines, and other techniques
developed to accomplish project goals.
Numerous specific issues will be analyzed
and evaluated in developing the process.
These issues include the coordination and
consolidation of application forms, the role of
informal public conferences in reviewing the
projects, relationship of the environmental
impact statement process to a coordinated permit
system, conducting a master hearing involving
numerous agencies to establish a factual record,
selection of a hearing site, establishment of time
limits on agency decision-making, and the effect
of such process on decision-making criteria.
We have no preconceived notion about any
of these issues and recognize the potential
importance of each. We will be analyzing and
evaluating each issue to determine which of
them may be addressed in the process and how
they might be addressed. Based on these
analyses and evaluations we will select viable
mechanisms to be included in the process.
What have we accomplished thus far? In
brief, we have hired a staff, developed a work
plan outlining the study components and meth-
odologies, and time lines have been prepared.
We have formed a Technical Resource Committee
of individuals with substantial experience and
expertise in addressing interrelationships in
environmental, industry, governmental, and
public concerns and conflicts associated with
major energy and mineral development projects.
We have and maintain a public interest mailing
list. We are progressing on schedule through
the work plan. Currently we are involved in a
literature review and are conducting interviews
with people on our mailing list.
I would like to note that the time is ripe
for government to begin to develop sophisticated
methods that encourage competing interests to
work together cooperatively for common solutions
to conflict and disagreement. We no longer live
in an age in which the traditional power inter-
ests always get their way. Government should
not be allowed to do its job secluded from the
public. Wasting time, money, and resources is
no longer acceptable or affordable. Coloradoans
seem to demand leadership that will simplify our
lives without sacrificing quality. It is my
opinion that our project is a giant step in the
right direction. We would like to solicit your
comment and help as we go along in preparing
this joint review process for energy and mineral
development in Colorado.
Question: Are you and DOE working on a
project together?
Answer: We are working with DOE to coordi-
nate reviews with local, state, and
federal government.
Question: How long before the joint review
process will be available?
Answer: There will be a manual that will lay
down the guidelines of how a joint
review process should proceed. It
will be available to those projects of
such magnitude as to qualify for it.
At that time industry will have the
option of being a part of the joint
review process.
Question: When will this be completed?
Answer: November, 1979.
ENVIRONMENTAL ADVISORY PANEL,
HENRY O. ASH, EXECUTIVE DIRECTOR
The Environmental Advisory Panel operates
under the Federal Advisory Committee Act,
which provides for a two-year charter period
and review at the end of each two-year period.
It is technically terminated. We went through
about a six-month period awaiting a decision on
its reestablishment. An affirmative decision was
made last August, and we had anticipated that
operations would soon begin, but we are not
operational yet. We are officially reestablished,
and we are awaiting the completion of the roster
of the members. The remaining members to be
named are a couple of federal members and four
public members to be named by the Secretary of
Interior. There has been a change in the
panel's composition of the new charter in that it
now provides for two industry members, where-
as the old charter provided for no industry
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membership on the panel. We expect these
members to be named very shortly, and in the
next few weeks we should be reconstituted and
fully operational. We will plan a meeting within
the next two months. The panel is an inter-
governmental agency. The members are drawn
from bureaus and offices of the Department of
the Interior and other major federal agencies,
state government, and county government and
with a number of public nongovernmental mem-
bers. Total membership under the new charter
will be twenty-six.
Dr. Coffer introduced the next speaker,
Alden Christiansen, director of the EPA labora-
tory in Cincinnati. He presented the following
paper.
EPA OIL SHALE RESEARCH PROGRAM,
ALDEN G. CHRISTIANSON
Introduction
The U.S. Environmental Protection Agency
(EPA) is mandated, under numerous legislative
authorities, to maintain and enhance environ-
mental quality and to protect human health and
welfare. In support of this mission, the
.agency's Office of Research and Development
(ORD) conducts a comprehensive and integrated
research program to provide the following:
1. The scientific technical data base for
reasonable standards and regulations;
2. Standardized methods for measure-
ments and to assure quality control in
programs that assess environmental
quality, implement regulations, and
enforce standards;
3. Cost-effective pollution control tech-
nology and incentives for acceptance
of environmentally sound options; and
4. Scientific, technical, socioeconomic,
and institutional methodologies needed
to judge and balance environmental
management options against competing
needs.
Energy R & D
Emphasis on energy-related research has
increased within EPA over the past four or five
years—basically for a couple of interrelated
reasons: First, our ever-changing energy
dilemma has focused more attention on fuel
supplies and energy conversion and has resulted
in increased efforts to utilize coal and to de-
velop alternate supplies of fuel and energy.
Secondly, federal government emphasis on
energy research and development in 1973-1974
recognized the environmental implications of
accelerated energy development. A coordinated,
Interagency Energy/ Environment R&D Program
was established and funded through special
appropriation to EPA, with EPA's Office of
Energy, Minerals and Industry being charged
with the responsibility for implementing the
Interagency Program.
Two CEQ (Council on Environmental Qual-
ity) task force reports established the basis for
the Interagency R&D Program, covering (1)
Health and Environmental Effects of Energy Use
and (2) Environmental Control Technology for
Energy Systems. These categories are main-
tained and subdivided into various components
so that proper management can be applied in
terms of funding and balance. Areas addressed
on the effects side of the program include:
pollutant characterization, measurement, and
monitoring; pollutant transport, health effects;
ecological effects; and integrated assessment.
Control technology R&D addresses: resource
extraction; coal cleaning; flue gas cleaning;
direct combustion; synthetic fuels (including oil
shale); nuclear fuel cycle; thermal control;
improved efficiency; and advanced systems.
Approximately 60% of the funding autho-
rized for the Interagency Energy/Environment
R&D Program has been apportioned to EPA;
about 40% has been distributed among over a
dozen other federal agencies for relevant envi-
ronmental research.
In terms of fuel types being addressed,
approximately 50 to 60% of funding has been
devoted to coal-related R&D; approximately 25
to 30% to oil, gas, and multi-fuel R&D; and the
remainder divided among the less conventional
fuels or technologies. Oil shale R&D has re-
ceived on the order of 2 to 4% of the program's
funds. In dollar terms, this has amounted to
about $3 to $4 million per year being directed
to oil shale research and development.
For those interested in the Interagency
Energy/Environment Program, there is a "Status
Report" and "Who's Who" directory available.
Oil Shale R&D
Within EPA, research related directly to oil
shale development is conducted through
programs of over one-half of the fifteen mission-
oriented research laboratories. In addition, the
Region VIII Office here in Denver, conducts
some activities that are closely related to
research.
The mission orientation of the EPA Re-
search Laboratories means that various
categories of work related to oil shale develop-
ment are spread throughout different
laboratories and locations. For example,
research on measurement and monitoring, envi-
ronmental transport processes, ecological
effects, health effects, and control technology
is carried out by different laboratories that
37
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focus on those respective missions. To assure
that all oil shale research would be coordinated
within EPA, an Oil Shale Work Group was
formed in 1975 to maintain an integrated overall
program. The Work Group is comprised of
individuals from EPA Laboratories, the Region
VIII Office, and EPA's regulatory offices. All
representatives are personally involved in
research or other EPA Program responsibilities
dealing with oil shale. Many of these individ-
uals are present at this meeting.
Activities in the measurement and moni-
toring program include development of instru-
mentation, methodology, and quality assurance
procedures to monitor conditions or identify
pollutants. In addition, field monitoring pro-
grams are conducted to establish baseline or
other conditions and detect changes.
Air monitoring projects have been con-
ducted primarily by Region VIII. They have
included efforts to correlate National Weather
Station data with that taken at lease tracts.
This was to determine the representativeness of
meteorological data from the standard, long-term
monitoring stations, which might aid in interpre-
tation of weather conditions at lease tracts.
In another effort, upper air data was
collected at tracts C-b and U-a/U-b to generate
stability/wind rise information for use in as-
sessing pollutant dispersal and fate, and the
impact on air quality. Another project has
supported the installation and operation of air
monitoring sites in Western Colorado in order to
collect baseline air quality data prior to major
expansion of energy development activities.
The Environmental Monitoring and Support
Laboratory at Las Vegas is assessing the im-
pacts of oil shale extraction and coal strip
mining on ground water in the Uintah and
Piceance basins through a comprehensive moni-
toring program. The Las Vegas Laboratory also
supports both air and water monitoring networks
throughout the western U.S. to monitor and
assess the impact of energy development.
Outside of the EPA, the USGS is also involved
in conducting water monitoring projects that will
provide information relative to energy develop-
ment. Funding for some of this related work is
provided by pass-through funds from the
Interagency Energy/Environment R&D Program
managed by the EPA.
Development of instruments and methods to
identify components of energy-related wastes
and effluents is pursued by the Environmental
Research Laboratory in Athens, Georgia. This
work is generic in that it will apply to a broad
list of energy sources in enhancing our ability
to accurately describe the chemical characteris-
tics of process streams and residuals. Outside
of the EPA, the National Bureau of Standards is
also conducting supportive work in this area
under the coordinated, Interagency Program.
To better predict environmental transport
processes, the Environmental Research Labora-
tory in Ada, Oklahoma, is attempting to relate
chemical changes in ground water to the charac-
teristics of overburden and the changes that
occur there due to mining, gasification, and
retorting. By understanding the transport
mechanisms more clearly, we hope to be able to
predict environmental impacts more accurately
and avoid damaging consequences.
In terms of effects of research, EPA's
Environmental Research Laboratory in Duluth,
Minnesota, is involved in a study assessing
toxic effects on aquatic ecosystems from coal
and shale oil development. This effect involved
chemical and ecological baseline studies of
waters in the Piceance Creek basin and bioassay
characterization of potential discharges to
receiving waters.
In the category of Health Effects, research
is being conducted by EPA Laboratories as well
as many other agencies concerned with the
impacts of energy development upon human
health. Since most of this work applies broadly
to energy systems, as well as oil shale, exten-
sive interaction is maintained between research
groups.
The Health Effects Research Laboratories
at Research Triangle Park, North Carolina, and
Cincinnati, Ohio, are assessing the health
effects of exposures to air and water pollutants
resulting from energy technologies, including oil
shale processing.
The Environmental Research Laboratory at
Gulf Breeze, Florida, is studying the accumula-
tion of potentially carcinogenic compounds in
the marine food chain consumed by man.
Supportive health effects research, some
funded through the Energy/Environment Pro-
gram is conducted by various Department of
Energy Laboratories (Oak Ridge, Livermore,
Los Alamos, for example) and by NIOSH. The
cooperative efforts cover a range of activities
including maintaining a repository of materials
for testing. However, most effort is devoted to
effects, determinations, and related work,
through whole animal, cellular, and other types
of testing and studies.
The Industrial Environmental Research
Laboratory in Cincinnati, Ohio, conducts control
technology assessment and development for oil
shale processing as well as other industries.
To identify potential control needs, a compre-
hensive environmental assessment of oil shale
development has been conducted. This study
described recovery processes, characterized
residuals, and identified technologies that might
be useable for reducing unacceptable levels of
pollutants.
38
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In order to describe emissions more accu-
rately and thoroughly, a field sampling and
analysis study was conducted at the Paraho
plant during its recent operation. Additional
field studies for pollutant characterization are
planned. When control needs are clearly delin-
eated, field testing of small-scale treatment
processes is planned to evaluate their control
capability.
Fugitive dust studies have also been
conducted at the Paraho operation to describe
the nature, quantities, and specific sources of
such emissions. Determinations were made in
the vicinity of mining operations, haulage
roads, crushing operations, and spent shale
transfer points.
Numerous projects are under way that deal
with safe disposal and control of adverse effects
from spent shale disposal. Spent shales from
Paraho, TOSCO, and USBM have been used in
developing revegetation methods, in evaluating
movement of salts and water on and through
spent shales, and to describe leachate charac-
teristics and control needs.
Additional research efforts are under way
by the Cincinnati Laboratory alone, and with
other agencies, to describe control procedures
and technology for surface and groundwater
impacts from various oil shale extraction, han-
dling, and disposal activities.
The Industrial Environmental Research Lab
in North Carolina is heavily involved in syn-fuel
research and has addressed oil shale in some
assessments. Also, within their programs on
refineries, they have assessed emissions during
refining of shale oil—during the recent Navy
refining of Paraho oil.
A final category of research work by EPA
which, in part, involves oil shale development
is integrated assessment. These studies attempt
to incorporate social, economic, and technical
factors in analysis of likely energy development
scenarios. One such study has addressed
Western Energy Resource Development to identi-
fy major environmental concerns. Another
project, conducted by USDA with pass-through
funds, focuses on coal and oil shale development
with respect to resource competition and use
and the agricultural economic implications of
such development.
Pollution Control Guidance
As mentioned earlier, a primary purpose of
EPA research and pollution control development
is to support the standards-setting function of
the EPA. The research activities described
earlier have been conducted in that vein and
have led to a pretty good technical understand-
ing of the developing oil shale industry and of
the environmental problems that such develop-
ment may pose.
I know you are aware that the environmen-
tal protection legislation applies to oil shale as
well as other industrial operations. In total,
compliance with existing or anticipated air,
water, and solid waste requirements is no small
or easy task.
Developers of new industries face a partic-
ularly difficult task since specific pollution
control requirements are not and cannot be
defined completely. It is a chicken and egg
situation--we need to know what is possible and
reasonable, but real world experience is needed
in many cases to generate that knowledge.
Alan Merson has addressed this very point
earlier this morning—that some answers will not
come until representative, prototype operations
are underway.
Recognizing this situation, EPA is initiating
an effort to provide early environmental guid-
ance for oil shale development. A document
entitled "Pollution Control Guidance for Oil
Shale Development" is being prepared, based on
technical input from researchers, working in
conjunction with representatives of EPA's Pro-
gram Offices and Region VIII. An outline has
been passed out. The document will convey
preliminary regulatory implications and
technology-based environmental goals for the
industry. This will be achieved by identifying
regulatory mechanisms that are most likely to be
applied, and by interpreting what these mech-
anisms may require in terms of identified ranges
of possible discharge and emissions limitations.
We realize this effort is a preliminary step in
describing environmental requirements, but it
should be helpful by providing direction to
industry. In summary, we hope it will be
helpful to be able to address pollution control
requirements in a proper, staged approach,
which will hopefully lead to a reasonable outcome
based on facts—and no surprises.
Industry review and input to this "Guid-
ance Document" will be solicited--in fact, I am
soliciting your cooperation in this effort right
now. A draft of the document will be available
in late summer/early fall, and the EPA would
like your evaluation of it. Where you have
more up-to-date data or additional relevant
data, we would appreciate your pointing this
out and contributing data. By identifying and
resolving environmental control problems early,
we hope that oil shale development can proceed
without delays caused by environmental impedi-
ments or confrontations.
As the status of knowledge and develop-
ment increases, the document may be updated
to reflect more definitive discharge limits and
more demonstrated confidence in available con-
trol technologies. This effort will also be
helpful in identifying research needs to fill
technology gaps.
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Comment: (Harry McCarthy, Science Applica-
tion, Inc.) If anyone is interested
in getting a copy of the Geothermal
document, I will be happy to see to
it that one is sent out.
Question: (H. Pforzheimer, Sohio) After all of
the work you have done, have you
run into any surprises?
Answer: We have not run into any real
surprises.
Question: (Pforzheimer, Sohio) It was men-
tioned what had to be done in order
to get the Alaskan pipeline built. It
took an act of Congress to solve the
environmental problem. Would there
be any consideration to taking a
similar approach with respect to the
modular program for oil shale? The
only way we are really going to get
the data we want is to get in the
field and try to operate these units
with EPA and all other interested
agencies monitoring the results.
Granted we have some legal permit
obligations that we have to satisfy,
but if this is a real serious problem
to the country to satisfy its own
energy needs domestically then why
all the quibble and war? Has any
consideration been given to try to
use that approach? We are getting
pretty close to that point in time.
Answer: I do not believe consideration has
been given to that approach. I do
not know if the status of oil shale
development is comparable to that of
the pipeline.
Comment: Certainly to build modules and to do
all the environmental work on them
is the way to go. There are some
questions that I think we can answer
by doing some field studies in the
absence of any oil shale facilities,
such as more core holes, find out
what water is available, more mete-
orological work, finding out the
dispersion patterns in the Piceance
Basin. Those are things we can do
now. We need to have facilities and
research data is needed from them.
Dr. Chuck Prien with DRI is still on
assignment with EPA and has asked
when you build facilities to have
some joint participation with EPA and
in almost every instance the answer
was yes. Projects coming out of
Cincinnati are waste water treatment
study and air pollution control
study. These will be pilot type
units that will go around and look at
treatability. That sort of thing is
what EPA is prepared to do and
would like to go to the field with.
The problem is we do not have any
facilities to work on.
Comment: We have had access to the Paraho
Development and the whole line that
stems from that 1 think it is very
useful as a model. It covers every-
thing from mining to retorting and
on to refining. It gives us a chance
to look at the whole line of develop-
ment of products—mine dust and so
on. We have retort and effluents.
We have crude, upgraded crude,
seven different products, all of
which will go into Interagency sys-
tems approach, which at this time
the participants are the U.S. Navy,
EPA, DOE, and one or two private
laboratories. That is the approach—
from health aspects to mining
retorting to transportation, occupa-
tional health, product safety, and
product use, including the potential
problems in combustion use. This is
one example where the modular
approach is very useful and should
demonstrate that it can be carried
out. The idea here is not to thwart
the effects of oil shale but to get
information as quickly as possible so
we can proceed more rapidly.
Comment: It might be possible to assist in
making progress in oil shale develop-
ment to encourage more interagency
communication. We are talking now
about how beneficial it would be to
have some modules to monitor and to
get some of the real big answers
from them. Yet, from the
Department of the Interior, it was
suggested that modules were pre-
mature at this point. I think we are
not getting communication between
the agencies that are making deci-
sions which would permit modular
development to go forward.
Comment: (Alden Christiansen, EPA) I am sure
that is true. There is never enough
communication and especially with
respect to oil shale development. We
should really look at what kinds of
mechanism for communication are
there. The mechanism is more
difficult to identify.
The "Guidance Document" will be one
way, and we solicit your evaluation
of it and input to it—there is prob-
ably a need for more communication
than that.
Comment: (Pelofsky, SAI) One of the things
that I have run into for a number of
years, and this refers to the
40
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"Guidance Document" as well as
communications, is that everybody is
talking, using different assumptions,
and different bases. Perhaps indus-
try could be helpful to you while
this document is being prepared if
you were to enumerate the assump-
tions. The same thing goes for
interagency communication and
industry communication. We saw an
example of that today on the $3.00
tax credit.
Comment: (Christiansen, EPA) We have decided
with respect to the document, to put
together the status and knowledge as
we, within EPA, see it,, (technical
data and so forth), and incorporate
it in the EPA rough draft and then
ask industry for its comments.
Comment: (Pelofsky, SAI) But you see, by the
time the document is ready to be
published, if the basis and assump-
tions are not clear, it would be too
late to review.
Comment: (Christianson, EPA) No, it will not
be too late to review. It is basically
to provide early guidance. It is
going to be based on technical data
and EPA's perspective of regulations,
for example, how the Clean Air Act
and Solid Waste Acts are going to be
translated for the oil shale industry.
It depends on what technology is
available and the limits that need to
be set for health and welfare protec-
tion. We do need to have access to
facilities that are operating. We
want to work cooperatively with you
to assess control technology capabil-
ities. If you have facilities available
for that kind of thing, or the time is
right for that kind of interaction, we
would welcome your expression of
that by contacting either me, or
Terry Thoem, so that it could be
evaluated. We would like to be
aware of any opportunities for us to
do some onsite work or cooperative
work.
Terry Thoem from the EPA Region VIII
Office was introduced, and he presented the
following paper on the EPA regulatory program.
EPA-REGION VIII, DENVER, TERRY L. THOEM
Introduction
Enabling legislation during the 1970s in the
environmental medium of air, water, solid waste,
noise, and toxic substances has expanded the
EPA regulatory jurisdiction and has created an
increased need for research programs. EPA is
often asked the question, "How large an oil
shale industry can Colorado, Utah,, and Wyoming
support?" Is air quality a limiting constraint?
Is it water quality or water availability? Is it
socioeconomic considerations? Is it economics?
Or is it technology? If you think I am going to
answer those questions in this paper I am
afraid I will have to disappoint you. Rather, I
will describe to you the EPA regulatory activ-
ities and philosophy that bear upon the
question. The topic could perhaps be labeled
as describing everything about EPA that you
never wanted to know but that you are forced
to live with. I will discuss this topic of regula-
tions in the framework, the approach toward
regulations, and finally the suggested permit
limits.
Framework
The general process of legislation/regula-
tions is that the U.S. Congress establishes
environmental legislation that provides a frame-
work for state legislation and implementing
federal and state regulations. In many
instances EPA is faced with the task of inter-
preting that legislation. State legislation and
regulations can be more stringent, but not less
stringent, than federal requirements if a state
is delegated responsibility for administering the
program in a given media. The federal govern-
ment retains an oversight reviewing role for
those programs that are delegated to the states.
State legislation, in general, parallels federal
legislation in form and substance.
A comprehensive research program must
provide a data base upon which EPA may fulfill
its regulatory responsibilities. These regula-
tory activities serve to protect the environment
while allowing the development and reasonable
growth of an oil shale industry. Enabling
legislation and implementing regulations in the
form of the Clean Air Act Amendments of 1977
(P.L. 95-95), the Clean Water Amendments of
1977 (P.L. 95-217), the Safe Drinking Water
Act of 1974 (P.L. 93-523), the Resource Con-
servation and Recovery Act of 1976 (P.L.
94-580), the Toxic Substances Control Act of
1976 (P.L. 94-469), and to a lesser extent the
Noise Control Act of 1972 (P.L. 92-574) estab-
lish the regulatory framework through which
EPA operates. Of course the National Environ-
mental Policy Act of 1969 (P.L. 91-190) is also
a significant piece of environmental legislation.
Since other entities such as the respective state
agencies and the Area Oil Shale Office also have
regulatory jurisdiction in similar media,
EPA-Region VIII has established a close working
relationship with these organizations.
Under the Clean Air Act oil shale devel-
opers must 1) employ Best Available Control
Technology (BACT), 2) insure that National
Ambient Air Quality Standards (NAAQS) are not
violated, 3) not cause Prevention of Significant
Deterioration (PSD) ambient air quality
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increments to be violated, 4) not significantly
degrade visibility in mandatory Class I areas,
and 5) perhaps obtain one year of baseline data
prior to applying for a PSD permit to construct
and operate. BACT has been defined in the
form of allowable emissions limits for sulfur
dioxide and particulate matter for two permitted
facilities. Effective on March 1, 1978, BACT
limits for nitrogen oxides, carbon monoxide,
and hydrocarbons must also be specified in all
permits. Source monitoring, ambient monitor-
ing, recordkeeping, and reporting requirements
are also part of the PSD permit.
The Clean Water Act contains requirements
in sections 301 and 404 for potential permits for
an oil shale developer. A National Pollutant
Discharge Elimination System (NPDES) permit
must be obtained under requirements of section
402 if water is discharged to a navigable stream.
Specific effluent guidelines have not been
promulgated for oil shale facilities. A Section
404 permit must be issued by the Army Corps
of Engineers and concurred upon by EPA if any
dredge and fill operations take place in a navi-
gable stream. Section 303 of the act provides
the mechanism for establishing water quality
stream standards. Plans developed by various
state water pollution control agencies must
define water courses within the state as either
effluent-limited or water quality-limited.
Underground injection control (UIC) regu-
lations to be promulgated under the Safe
Drinking Water Act will govern the injection or
reinjection of any fluids. Permits will probably
be required for in situ operations and for mine
dewatering reinjection. The State of Colorado
requires reinjection permits under existing
regulations. Monitoring and mitigation measures
to prevent the endangerment of the ground-
water system will be requirements under these
UIC regulations.
The Resource Conservation and Recovery
Act (RCRA) governs the disposal of solid and
hazardous wastes generated by an oil shale
facility. Included in this category will be
processed shale, spent catalysts, process
sludge, and sewage wastes. Criteria for the
identification of hazardous wastes were proposed
by EPA in December 1978. Performance stan-
dards defining safe disposal practices for
hazardous wastes were also the subject of a
special mining waste study, which will be com-
pleted in February 1979. Permits requiring
safe disposal of hazardous wastes will have to
be obtained from EPA or a state by an oil shale
developer.
Testing of effects, record keeping, re-
porting, and conditions for the manufacture and
handling of toxic substances are being defined
under the auspices of the Toxic Substances
Control Act of 1976. An inventory of all com-
mercially produced chemical compounds is now
being compiled and will be published soon. If a
substance is placed on the inventory it is
"grandfathered" from the TSCA requirements.
Shale oil and/or its refined products are slated
to be on the inventory.
Manufacturers of new chemical substances
must notify EPA ninety days prior to their
manufacture and must also describe the pro-
posed use, the amount produced, and
by-products, disposal practices, and any test
data related to the health and environmental
effects potentially caused by the chemical's use.
The manufacturer may be required by EPA to
perform testing of a chemical's effects such as
epidemiological, carcinogenic, mutagenic,
environmental, etc. The EPA control of a
chemical's use may take one of three forms--
manufacture with no restrictions; a ban;
manufacture with conditions placed on the
handling and use of a chemical. EPA has
promulgated regulations regarding one
substance--PCBs. Production of PCBs is pro-
hibited after January 1979. Noise and radiation
legislation have little impact upon an oil shale
industry.
The final piece of environmental legislation
in which EPA participates is NEPA. EPA re-
views Environmental Impact Statements (EIS)
and in limited cases will write the EIS when a
project involves a major federal action. EPA's
roles as a reviewer is to comment on the envi-
ronmental aspects of the project.
EPA's legislation as described above nor-
mally provides a permit process mechanism.
Companies wishing to construct and operate an
oil shale facility must receive a permit from EPA
or the state permitting authority in order for
the facility to be operated. A compilation of
the permits required for an oil shale facility will
be provided in the Pollution Control Guidance
Document.
Precommercial Approach to Regulations
The approach toward regulating pilot-
module oil shale facilities must insure compliance
with existing standards, but more importantly,
should emphasize characterization of residuals
from an oil shale facility. Comprehensive
emissions effluent and waste material monitoring
should be performed by the company. Research
programs designed to define the optimum control
technology for a given pollutant for an oil shale
industry should be conducted. Trade-offs
among air pollution/water pollution/solid waste
must be considered. The energy penalty,
water consumption, and control must be defined.
The comprehensive monitoring efforts should not
be limited to only the "designated" pollutants,
but should characterize all "suspect" pollutants.
Another concept for consideration in the
regulatory approach is source characterization.
A moderate degree of ambient impact monitoring
should be performed in order to validate
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predicted impacts and to document trends and
changes from baseline. Programs to evaluate
effects upon "receptors" should be performed in
order to provide feedback on the source and
ambient monitoring programs.
A final concept in the approach to regula-
tions involves the concern over nonregulated
pollutants such as trace elements. Although
not regulated, some trace elements may not be
released in a significant enough quantity to
present environmental harm. Threshold Limit
Values (TLVs) have been defined by OSHA for
many inorganic and organic elements/compounds.
A screening analysis could be performed on the
potential amount of a "nonregulated" pollutant
that might be released from an oil shale facility.
If a significant--i.e., much higher than the
TLV—concentration were predicted, source
characterization, ambient monitoring, and effects
programs could be implemented as applicable.
BACT for criteria air pollutants must be
implemented for any proposed oil shale facility
with the potential to emit 100 tons or more per
year of any criteria pollutant. Those facilities
that have potential emissions less than 100 tons
do not need BACT but should be required to
perform comprehensive monitoring. Two primary
mechanisms exist to define BACT. First,
several oil shale facilities have received PSD
permits. BACT has been defined on a
case-by-case basis for these facilities. Second,
air pollution control technology, which has been
defined as BACT for "oil shale related
facilities," may be considered as transferable to
the oil shale industry.
A no-discharge of pollutant concept is
being considered by most oil shale developers
as means of handling their waste water streams.
A no-discharge of process water concept has
been written into NPDES permits. If any water
is discharged to a surface stream or reinjected
into the groundwater system, it would consist
of mine inflow (but not retort or backflood
water) uncontaminated surface runoff. Treat-
ment may or may not be necessary. BPT and
BACT should be defined for certain pollutants
for certain oil shale process streams. A few
major factors to be addressed by regulatory
agencies and the oil shale developer are sum-
marized in the following sentences. First,
because of the semiarid water-short condition of
oil shale country, it may be "environmentally
best" to encourage treatment and discharge to a
surface stream of nonprocess water. Second,
because of salinity considerations treatment of
certain nonprocess streams and/or minimization
of water consumption may be a desirable policy.
Third, disposal of process water onto processed
shale piles without treatment may not be desir-
able. The high organic and salt concentration
of the process water may represent too great of
a risk to groundwater/surface water quality
because of potential catastrophic events or
unexpected permeabilities/leaching. Fourth,
maximum recycle/reuse of process and nonpro-
cess water will be encouraged. Finally, land
application of untreated nonprocess water may
be desirable only for a short period of time due
to the potential nonpoint source runoff
problems.
Solid and hazardous waste should be
disposed of in a manner that prevents its
contact with water, which would result in toxic
concentrations. Disposal practices should be
designed that preclude (or at least minimize)
the potential for the solid material from be-
coming airborne as a fugitive dust. Safe
disposal practices as defined at 40 CFR 250
(pursuant to Sections 3002 and 3004 of RCRA)
apply to oil shale facility hazardous wastes such
as spent catalyst, API separator sludge, tank
bottoms, cooling tower sludge, water treatment
plant sludge, and perhaps processed shale.
The principal solid waste from an oil shale
industry is of course processed shale or raw
shale. Surface disposal at a minimum should
conform to those practices proposed at 40 CFR
257 pursuant to 4004 of RCRA. Special disposal
practices for high-volume semihazardous waste
materials, such as processed shale, may need to
be defined under a special category under the
RCRA regulations.
Suggestions for Interim EPA Emissions,
Effluent and Solid Waste Disposal Standards
Standards Criteria and Environmental Goals
Section II of this paper describes existing
legislative and regulatory constraints and
Section III describes a regulatory approach to
defining environmental standards that should be
met by any oil shale facility and by an oil shale
industry. The environmental goal applicable to
an oil shale industry should be the "minimiza-
tion" of environmental impacts. Minimization
must be defined in terms of potential environ-
mental harm, economics, energy penalty, and
intermedia tradeoffs. A no significant degrada-
tion policy has been quantified for a few air
pollutants (SO« and particulate) and has been
qualitatively srated for water quality. Protec-
tion of minimum stream flows for aquatic life,
provision of adequate water quality for appli-
cable water use, protection of health and
welfare related air quality aspects, minimization
of detrimental land disturbance in order to pre-
serve adequate wildlife habitat, and protection
of valuable socioeconomic, cultural, historical,
and aesthetic values are environmental criteria
that constitute the basis for defining specific
environmental standards.
Suggestions for Interim Regulatory
Guidelines and Standards
The source standards and ambient stan-
dards discussed below could apply to individual
oil shale facilities and to an oil shale industry.
The ambient standards have the most direct
impact on the industry (rather than any indi-
vidual facility) in that the Piceance Basin and
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the Uintah Basin (and Colorado River Basin)
have a finite "carrying capacity" for air pol-
lutants/water use. Although attempts have
been made to define the size of an oil shale
industry that could fit into this "carrying
capacity," a paucity of data and comprehensive
predictive efforts have limited the successful
accomplishment of this task. Facility siting is
an obvious major factor in determining the
ultimate size of an oil shale industry.
In an attempt to both build upon previous
details and to provide summary guidance on
environmental requirements to be met by an oil
shale facility and by an oil shale industry,
suggested interim guidelines are provided
below.
1. Air
Source guidelines (daily averages)
99.5% total sulfur recovery from retort
off-gas streams or less than 50 ppm S at 0%
O2 stack gas concentration (dry basis)
0.8 pounds of SO2 per million Btu for
liquid fuel combustion sources
0.10 grains H2S/dscf and/or 250 ppm SO2
at 0% O2 dry) for process fuel gas
0.3 pounds of SO2 per million Btu for
gaseous fuel combustion sources
0.5 pounds of NOX per million Btu for
liquid fuel combustion sources
0.2 pounds of NOX per million Btu for
gaseous fuel combustion sources
75 ppm NOX at 15% O2 for gas turbine
combustion
0.03 pounds of particulate per million Btu
for any fuel combustion source
99.8% particulate collection for any materials
handling source
0.022 grains/dscf on all process streams
10% opacity for any particulate source
30 inchAp wet scrubbers for particulate
Fugitive dust control measures such as
those described in the EPA Region VIII
Interim Policy Paper on Air Quality/Mining
A maximum concentration of 100 ppmw of
uncombusted hydrocarbons from fuel
combustion sources
Ambient Standards
NAAQS
PSD increments
State ambient SO2 standards
5 ng/ro3 (24-hour average) SC>4 concen-
tration in Class I areas
5 ug/m3 (24-hour average) NO3 concen-
tration in Class I areas
No significant degradation of visibility in
Class I areas
Hg, As, Se, Cd, Be and Ba TLVs
37 pg/m3 (24-hour average) fine particulate
(2.5 micron) concentration in Class II areas
and 10 |jg/m3 (24-hour average) in Class I
areas
2. Water
Source Guidelines
No discharge of process water
Treatment or dilution of discharges to the
following:
TDS 723 mg/JZ (weekly maximum) and
1 ton per day of salt
F 3.0 mg/SL (daily maximum)
B 5.0 mg/S. (daily maximum)
TSS 30 mg/S. (30 day average)
45 mg/H (7 day average)
NH4 1.3 mg/Z (daily maximum)
Phenol 0.2 mg/A "
Al 1.1 mg/i "
Fe 7.0 mg/i "
Other metals limits compatible with
designated stream use
Removal of organics and 804 from prior to
disposal on solid waste pile
Diversion of runoff from process areas
Collection and containment in lined evapor-
ation sedimentation ponds of all process
area and disturbed area runoff
Maximum recycle and reuse of water
Collection and containment (no discharge to
surface water or ground water) of process
shale pile and/or runoff
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Ambient Standards
State water quality standards
Colorado 208 standards
- 723 mg/H TDS in the Colorado River Basin
Prevention of groundwater contact with
spent in situ retorts unless retorted shale
is impermeable
Up-drainage and down-drainage from pro-
cessed shale pile collection/ evaporation
ponds
3. Solid and Hazardous Wastes
Source Guidelines
Isolation and containment of hazardous
wastes such as spent catalysts and process
sludges
Compaction of bottom, top and edges of
processed shale pile into an impermeable
mass
Disposal of processed shale in areas other
than the 100 year flood plain, wetlands,
critical wildlife habitat, and recharge areas
to sole source aquifers
Ambient Standards
Prevention of contact of solid and hazardous
wastes with water (which leachate would
subsequently be discharged) whose concen-
tration would exceed 10 times the drinking
water standards
Prevention of (or minimization of) solid
waste/hazardous waste materials becoming
airborne as fugitive dust emissions
Contouring solid waste materials to provide
harmony with the surrounding landscape.
Issues
I would next like to address several issues
that have either been consistently discussed or
have been raised in the past by the oil shale
industry.
First, the number of permits required for
a facility is consistently raised as a constraint.
EPA is investigating opportunities for permit
consolidation, but I must ask the obvious
question—How many of these permits are
environmentally related? Second, the high
background air quality levels of articulate,
hydrocarbon, and ozone have been considered
and discussed at length. EPA has responded in
the form of development of a rural fugitive dust
policy, consideration of revocation of the
hydrocarbon standard, the drafting of a pro-
posed rural ozone policy and proposed revision
of the ozone standard. Third, it has been
argued that the inclusion of fugitive dust from
oil shale activities is not consistent with the
intent of PSD. The promulgated PSD regula-
tions will not require consideration of fugitive
dust (i.e. non-oil shale material) emissions in
evaluating compliance with PSD increments.
Fourth, concern has been raised over the level
of soon-to-be proposed NSPS for electric utility
facilities combusting oil shale derived products.
It must be made perfectly clear that these
standards will apply only to those facilities that
sell more than one-third of their produced
electricity and have a unit capacity of greater
than 250 million BTU per hour. The proposed
standards limit SO2 emissions to 0.2 to 1.2
pounds per million BTU coupled with an 85%
reduction. An 80% reduction was proposed for
use of synthetic fuels. The particulate limit is
set at 0.03 pounds per million BTU coupled with
a 99% reduction. However, the percent reduc-
tion does not apply to liquid or gaseous fuels.
The NOX limit for synthetic oils or gas is pro-
posed at 0.5 pounds per million BTU.
Conventional oil and gas limits are 0.3 and 0.2
respectively. Emission rates may be averaged
over a twenty-four hour period.
A fifth issue involved RCRA. As pre-
viously mentioned, critieria defining hazardous
wastes and performance standards establishing
safe disposal practices were proposed in
December 1978. As proposed, processed shale,
if considered hazardous via the toxicity test,
will be subject to the full range of proposed
standards. A sixth issue involves the PSD
Class I/Class II designations. The development
of a well controlled, environmentally sound
facility should be able to exist within the con-
straints of a Class II designation. If Class III
is needed it should not be needed until the oil
shale industry becomes very mature.
Finally, uncertainties in the regulatory
framework have been discussed. I would ac-
knowledge that there are instances to support
these statements. However, I must also
acknowledge that there have been several
instances of uncertainties on the part of the
industry. Instances including uncertain emis-
sions data, control devices, control device
efficiency, water discharge rates, water effluent
composition coupled with changing plans and
missed reporting dates have not left the indus-
try with a clean slate. It behooves industry,
government, and the public to avoid surprises.
Communicating the best information available can
serve to minimize the number of surprises.
Conclusion
Some oil shale developers have tended to
become frustrated by the lack of definition of
clear, concise environmental requirements that
they must meet. This situation has arisen in
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part because of relatively recent environmental
legislation passed by Congress and because of
the cyclic go/no posture of the oil shale indus-
try. In order to provide regulatory guidance
to the industry, EPA is working on a "Position
Paper" that will provide guidance on the
long-term requirements that the industry must
meet. This document should be ready for
review by May 1979.
Because of the nation's need for domestic
petroleum sources and because of the environ-
mental and technological answers to be obtained
regarding oil shale development, EPA supports
the limited development of oil shale. Judgments
may then be made on the size of an oil shale
industry that may be developed. Regarding
prototype development, EPA's philosophy is do
it but do it environmentally right.
Question: Regarding ozone standards, do you
have an idea of whether the secon-
dary level will be retained?
Answer: Most likely not. It may go to .1 or
.12, not any higher.
Question: How does the developer get a certain
amount of certainty that once he
gets a permit for that facility, some
years down the line he is not going
to be subjected to some new and
more stringent requirements?
Answer: There is not a lot of flexibility. I
do not think we can guarantee that
certainty. A few instances we
can—the air quality permit, a PSD
permit is issued for the life of that
project. Where we cannot give
certainty is in solid and hazardous
wastes and water discharge permits.
Water discharge permits mandated in
the Clean Water Act states it has to
be reviewed every five years.
Question: How do you change regulations?
Answer: When EPA issues, for example, an
air quality permit we establish the
best available control technology--
what the limits are--we have to
consider the costs and arrive at
what is an economically and environ-
mentally reasonable standard. If
because of the uncertainty of the
emissions data, and obviously there
is a lot of uncertainty in that area,
we do not know exactly what the
emissions are going to be, if you get
the plant up and running and you
find out that the emissions that are
going into that control device are
much different than those you had
told us in your PSD application, and
if you are meeting the control ef-
ficiency that we also established--it
is a simple matter of adjustment of
the permit condition. I do not see
that as any major problem. If we
project down the road that the oil
shale industry, after you get a lot
of facilities, that the ambient concen-
trations are higher than once was
expected, the state has a responsi-
bility to go back and change the
emissions standards.
Question: (Frank Berryman, Chevron) Can you
comment on whether there will be a
need to maintain visibility from Class
I areas, that is outside of the area
but can be seen from the area as
opposed in inside it.
Answer: We do not know yet.
Question: (Berryman, Chevron) In regard to
the Fire Service published findings,
have you had an opportunity to
determine if the act creates any new
wilderness areas near to shale coun-
try in the Piceance Basin, the
problem being they could become
Class I areas in the future.
Answer: I have not specifically looked at
that. I heard that some of the areas
being considered were near oil shale
country. One of the proposals was
more of the White River National
Forest which would in effect move
the Flat Tops Wilderness are closer
to oil shale country. But if they
are classified as a wilderness area,
there is a process that a land-
manager can recommend to Congress
and/or the state to then designate it
as a Class I area.
Question: (Rees Madsen, White River) Will
individual process shale be con-
sidered or will process shale as a
category be lumped in as a hazar-
dous waste?
Answer: They will be looked at on a process
by process basis. There was a list
of compounds that were automatically
designated as hazardous. Processed
shale was not on that list. Rather
the toxicity test will be applied to
each process. This will lead to a
situation whereby one type of pro-
cessed shale may be indicated as
hazardous waste and another type
nonhazardous.
Comment: (Mark Mercer, EPA) If you look at
individual waste streams within a
facility may all of them be then
categorized as hazardous or non-
hazardous?
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Comment: One of the key things is that we
need to look at some data from
processed shale under those disposal
type conditions. This data is not
available at the present time, to my
knowledge.
Question: (Madsen, White River) Does this
mean that, for example, Colorado
processed shale disposal system
might be considered hazardous
whereas if data was different in
Utah, that processed shale system
would be classified as nonhazardous?
Answer: Yes, that situation could exist.
Processed shale, regardless of the
type of process used, may have
different characteristics and dif-
ferent things may be done in the
disposal scheme. For instance,
someone may be putting a certain
type of waste with that processed
shale, so the final waste product
depends on the inherent character-
istics of the processed shale as well
as the disposal techniques.
Harry McCarthy of SAI was introduced and
asked to comment on their DOE-sponsored
project on analyzing the permitting process.
SCIENCE APPLICATION, INC.,
HARRY MCCARTHY, VICE PRESIDENT
About seven months ago, at a meeting held
in Denver, the permitting maze was pictured as
a real problem in oil shale development.
Jackson Gouraud indicated that maybe this
would be something that DOE could help solve.
If a permitting road map were built, one which
could be updated as necessary, both the regula-
tory agencies and the oil shale developers would
benefit. In order to make this road map useful,
it must be current—which leads to the problem
of changing regulations. Therefore, we have a
two-phase program. Phase I was designed to
find out whether there was a definable system
suitable for automation. We examined the
enabling legislation, went into the field to
collect existing permits, and made cross checks
between enabling legislation and the existing
permit system. We made correlations from top
to bottom to try and make sure that we had a
comprehensive set. We looked at federal, state,
and county regulations and permits. We did
include the municipal level with its emphasis on
zoning. We found that a trackable system
exists, but it is a constantly changing system.
We have finished the first part, which
defines, as of June 1978, a manual flow system.
Given a technology and county location, the
manual system enables us to draw a flow sheet
of what the permitting process looks like. We
were not able to do that very easily. We had a
lot of help from the oil companies, particularly
C-a and Colony Development. They showed us
what they had been required to do, and this
gave us a good basis. We went through some
of the EPA's offices and were able to compile a
lot of data. With help from many agencies, we
came up with something comprehensive. Those
of you who want a copy of the first phase
report can request one through Andy Decora's
office at LETC.
We have now started on Phase II, which is
to automate and validate the system. We have
an interim funding arrangement now with DOE
to fund us for a couple of months. We are
looking forward within about twelve to fifteen
months to having a computerized road map that
will be updated. We have had great cooperation
with all three states. These permits are only
for oil shale and only for Colorado, Wyoming,
and Utah. Colorado is interested in pursuing
this in their joint review process to try and
streamline their permitting process. I think the
biggest output one can get, once we have this
system, is an indication of how the system can
be streamlined to eliminate redundancies and get
to the most stringent requirements. I believe
the states and EPA want to eliminate this over-
lapping and understand the overall process.
The system being developed will help us all by
providing them a tool to help streamline the
process—that is our goal.
Question: (Ron Bissinger, Union Oil) If we are
going to do this for oil shale, will
the permits be any different for
coal, coal gasification, and so on--
should it include all of those?
Answer: Yes. Some permits apply to most
energy sources. We are not sure of
the interactions as a proposed on-
going program. DOE's feeling is
that it is a good idea and should be
done, but they want to do it for oil
shale and make sure that it is func-
tioning before we spend money on all
the other energy resources.
Question: How long does it take to complete
the permitting cycle?
Comment: The time is dependent upon a number
of things. The location and the
type of process all vary. What we
are doing in this program is to give
estimated time; we have not included
the time that you might have to
recycle.
Question: It is in the form of a critical path?
Answer: (Harry McCarthy, Science Applica-
tion, Inc.) Yes, for each type and
location of development we present a
path with the critical factors noted.
It is not the only path that you
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could go through. There are alter- Answer: Yes, we do. We point out where it
nate paths, but you do have certain is known. In the ones where there
criteria that you have to meet at is no legislated time frame, we try to
certain places. We have picked what rely on an experience factor, which
we consider a logical path. is often lacking in the case of oil
shale. If other estimating factors
Question: (Ken Olson, Gulf Mineral Resources) are lacking, we solicit estimates from
There are permits that are given the cognizant agencies.
that have time frames as part of the
requirements, there are others which
do not. Do we point that out?
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GENERAL DISCUSSION
HANK COFFER, PROGRAM COORDINATOR,
C.K. GEOENERGY CORP-
I would like to review a report we made
for EPA late last year when we contacted all the
major companies involved in oil shale to see just
what you thought about the critical constraints.
We went through air, water, waste disposal,
and we found that when we asked you to list
high priority and low priority items, we found
that by and large the majority thought .that the
sulfur oxides, the nitrous oxides, the hydro-
carbons, and the groundwater control were
major priority problems, and that the disposal
and process water and surface water releases
were minor problems. We talked to the six
companies that we felt at that time were most
active in oil shale. They felt that the problems
that the majority said were critical were not
really critical. But when you got down to the
bottom line, it turned out that there were very
few, if any, problems that those who were
working close to oil shale felt were critical. I
think we find ourselves in a situation where the
environmental issue has become a whipping boy
that industry and government can hide
behind—we cannot move fast because of envi-
ronmental issues. But when you look at it, it
looks as if environmental issues can be handled.
Environment may not be the major issue at all.
It may be economics.
Dr. Coffer asked the various company
representatives for any comments on these
issues.
Comment: (Harry Pforzheimer, Sohio) If in fact
we do not see any big serious acci-
dents down the road in the module
program, and we know that we have
to have the module program going to
get the kind of data we need to
actually implement the regulations,
then my proposal was why do we not
just go forward with some sort of
exemption of the type that was
granted for the Alaskan pipeline so
that people can do their thing and
can be monitored by all government
agencies to get the necessary infor-
mation and then determine what the
problems are with respect to going
commerical. I did not want to leave
the impression that there was no red
tape problem. We have not actually
gotten into it, but a lot of other
people have gotten into it.
Comment: (Hank Coffer, C.K. GeoEnergy) I
did not mean there were no prob-
lems, but they seem to be solvable
problems.
Comment: (Pforzheimer, Sohio) One way to
solve them is to grant an exemption
to start out with—get the data and
see what problems we have got to
solve. I am not saying that this can
be done, but think about it.
Comment: (Elaine Miller, C-a) Obviously there
are some problems that I believe I
agree with you are solvable. One
thing I do question is that I think
some of these problems develop at
different times with different pro-
jects, and that it may be very
difficult to have an industry/EPA
solution to these things. Our com-
munication with EPA has been excel-
lent, and I hope that it will remain
that way in the future.
Comment: (Coffer, C.K. GeoEnergy) Someone
from EPA has stated that after
getting acquainted with some of you
they would like to open the lines of
communications with you on a
one-to-one basis.
Comment: (Alden Christiansen, EPA) We would
like to try to work on a one-on-one
and not with EPA with a collective
industry single voice. There are
problems with each company, they
have specific problems all are inter-
ested in approaching, studying,
trying to resolve these problems.
If individual companies have situa-
tions to address to EPA we could
probably coordinate and cooperate
with them. We would like to have
those kinds to situations brought to
our attentions so we could try talk-
ing in a one-to-one manner. It is
impossible to work one to twenty-five
all the time. Please contact one of
the following:
Alden Christiansen, Terry Thoem, or
Gene Harris, chairman of Oil Shale
Work Group.
Comment: (Bob Thomason, C-b) I think that a
certain amount of one-on-one effort
is indeed necessary and should
continue. With all of us together
with such a broad collection of
disciplines and interagency commu-
nication opportunity it should be
carried one step farther. There is
no one in this room who does not
think that an oil shale industry is a
49
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desirable thing. We also agree, I
believe, that an effort towards
development of the sizable shale oil
producing industry is of benefit to
our national needs. I think a com-
mon sense of urgency and a
commitment to meet this objective on
industry interagency basis and
industry effort is something that is
really needed. With regard to
constraints, we find that working on
an individual project basis there is
some lack of communication between
the EPA and the state agencies. I
do not think it is the EPA's fault,
but there is a huge gray area in the
interpretative part of these regula-
tions. When it gets filtered down to
the technical people who actually set
the criteria, the permit criteria often
becomes very restrictive. We abso-
lutely have to get started in this
particular train of events of how we
get from here to there. We want to
commence the commercial-sized de-
monstration and confirmation of
actual operating conditions to
develop the data that is necessary to
serve as a basis for reasonable
regulations. This really is not
happening right now. It has to
happen before we can get to that
sizable industry that is going to
make an impact on our country's
energy needs. Initially the projects
have to have a policy or the permits
that effect those projects from a
starting point have to have a policy
of flexibility. The needs of an
initially commencing project are
different than the needs and require-
ments for a project at its production
rate. We must have some sort of a
timely process to get at the issuance
of these permits that takes into
consideration the flexibility that is
necessary.
We do not have a timely process.
There is an inconsistency in the way
the different regulating agencies do
their thing. We have one agency
that does have time limits on the
issuance of permits. They have got
to act in a timely fashion. We have
another agency who apparently has
no time limits on the way they re-
spond to permit applications. As an
example, we have had an application
for a National Pollution Discharge
Elimination permit for tract C-b for
now eighteen months now. The
criteria for that particular permit
has changed numerous times during
its development. The longer it
takes, the more changes are involved
in it. We cannot live with that kind
of due process. We have to have
some elements of flexibility and
timely operating conditions in the
issuance of permits. Some of the
other areas that interagency effort
could be of benefit, and they have
economic impact, is in the modeling.
Air quality, we think, is a manage-
able thing. We have the experience
and capability of controlling pollution
from emitting sources, yet there is a
lack of the appropriate realistic
models for predicting the impacts
from those emissions in the basin.
We need a very good rough terrain
model. It is critical to the develop-
ment of the industry. The location
of the emitting sources can have a
huge economic impact and on the
quality of air. There needs to be
some sort of an integrated approach
in this direction. Similarly in the
area of water, and there is a basin-
wide profit for modeling the effects
on the groundwater and surface
water from the standpoint of comple-
tions. I think that is a beneficial
effort and should continue on an
industry interagency basis. That
model, once refined, will probably
serve as a tool to define just what is
going on.
In the area of water quality, again
the classification of the streams in
the state is a critical issue.
Something is lost in the way of
communication between EPA and state
agencies. The permits are being
formed on the basis of the stream
being classified as a fishing stream
or they are not. This criteria
should be developed on the basis of
historic and practical use. A con-
certed effort needs to be brought to
bear to the proper classification of
the Piceance Creek. It is critical to
this developing industry.
Certainly we perceive our individual
efforts on a one-on-one basis with
the various regulating agencies, but
why not have an interagency indus-
try task force to consider these main
issues and something we can develop
clout with? We get together and talk
about all these things—but we do
not develop anything that has clout.
We have to do that in order to be a
successful industry.
Comment: (Rees Madsen, White River) In
regard to solving problems, we all
realize that as we get closer to
processes we find problems and of
course our job is to solve those
problems. We have to recognize that
50
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if the regulations and legislation that
are passed contain these kinds of
fatal flaws that we are able as indus-
try and regulatory people to recog-
nize those as things that could be
stumbling blocks. One of the things
we need is additional data and one of
the ways to do that is to build a
facility that is going to operate
under normal conditions. In that
regard, when we go in for permits
and so on we are using condition
factors that have been borrowed, a
lot of times from other industries,
which may or may not be applicable.
We are using emission factors that
have been developed from data that
may not be true operating data but
is more test data developed as a spin
off of some other work and this is
another reason that has been men-
tioned for full-sized demonstration.
Full-scale modeling work is critical.
Models are going to be the thing
that will decide whether you will
need to get a permit. Models are
something that industry is not com-
pletely equipped to do work on. It
is going to require the input and
expertise of EPA, DOE, and others.
In regard to new regulations, I am
always interested in talking to people
who have researched the program to
come up with the numbers that are
submitted to the regulatory people to
decide on the regulation number,
like 160 micrograms per cubic meter.
Often times the research individuals
do not have a lot of input into the
final number that is developed for
the regulation. We find ourselves
inclined to detect a ceiling with
instrumentation that might only be
able to measure plus or minus 20%.
In the case of hydrocarbons it might
be able to read plus or minus the
standard value. It is of concern to
industry and myself in particular
that maybe this kind of evaluation of
research results is not being com-
pletely incorporated into the numbers
that are developed in regulations.
We deal with legislations and regula-
tions, but we also deal with
interpretation and administrative
decisions. This latter group is a
little bit risky, in my opinion, to be
basing a 1.5 million or $1 billion
facility on, and some of these things
should be put into a firm regulation.
They should not be administrative
type regulations but should be made
more formal so that the risk of
lawsuits are at least somewhat more
minimized than they are at the
present time.
Comment: (Coffer, C.K. GeoEnergy Corp.) I
do not think EPA has any intent to
proceed on their own at all. They
want to continue cooperating with
industry, and they really like the
interchange of information. Their
timing is such that they feel the
guideline document can be presented
in rough draft to each participant
before the next meeting. You can
set up separate task groups to look
at different parts of it, and then get
the committee back as a whole and
talk about it.
Comment: (Charlie Sullivan, Superior) I would
like to group the problems we see
into three categories: 1) Timing—
time to industry is money, and
anything that can shorten up the
timing would be greatly helpful; 2)
Ways to reduce the risks on the
changing baselines on the permits,
and 3) The suggestion that if we
are interested in regulating the oil
shale industry, we at least ought to
know what that industry is. The
programs under way now are strictly
limited to the Mahogany Zone and in
situ leasing processes. The whole
spectrum of processes should be
looked at so that we know what is
the best process for the country for
the production, not just how well
one process will work.
Comment: (Paul Dougan, Equity Oil) Environ-
mental problems are minimal with the
fully in situ process.
Comment: (John Maziuk, Mobil) We have not
been very active in a project but
have been interested in the progress
of them. One thing I have seen
here is the intent of EPA to work
closely with industry in setting up
these standards and the one-on-one
approach. This should be imple-
mented, and I am sure anything we
can do to help, we would be happy
to do so. But we still have not had
that direct interest that is shown by
the other participants.
EUGENE HARRIS, EPA,
CHIEF, EXTRACTION TECHNOLOGY BRANCH,
GUIDANCE DOCUMENT COMMENT
This is a document to set up some kind of
goals for the EPA. What we are putting to-
gether now is what EPA has learned from you
from the many times you have told us what
your intentions are and the people that have
been kind enough to have our group on their
sites to show us what is happening. In this
document is what we understand is happening.
51
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It is written by EPA people mostly. We have
had some contractor help on things that we did
not know about. By February we should have
the first write up. And it is very preliminary.
There will be people in my group reviewing it
and getting other opinions on it. As soon as
we get the document in one piece, we will send
it to the program offices.
We do have on our committee representa-
tives of the program office who are involved in
many things and cannot make the meetings too
often so their contact with the industry is
limited. Usually the people who come to our
meetings are coming to keep their groups in-
formed on what is happening. They are not
making policy at the meetings, just keeping
informed. When we get a document together we
send it to the program offices, so they can look
at what the individual researchers understand
the situation to be and what his projections are
as to needs. If they have problems with it,
(and the problems they may have are what we
have projected as research needs or timing will
not fit the requirements that have to be met by
law) they may come back and ask to have it
revised. We do not anticipate any regulations
for the oil shale industry until into the 1980s.
The people I am talking to who write regula-
tions are just beginning to learn the word oil
shale.
This document will help see how our re-
search will fit into their plans. The role of our
group is to furnish data so that when a regula-
tion comes out it is something that is reason-
able, something that the regulatory people can
really enforce. We would like to reiterate to
the program officers on what we think is a
meaningful regulation and give them the data to
back it up. When we get their response back
and their comments we will incorporate that into
the draft.
That is the version that we would like to
give to you. We thought that would be the
document that you would prefer to see. That
has the program offices and the regulatory
people's viewpoint incorporated into it, which
means something to you. We need to give the
regulatory people good sound information as
much as we can. This document is to put
together all our guesses, and we want you to
look at it before we publish it. We want you to
tell us whether we are missing it a mile,
whether we are close enough that it will not
hurt anyone, or whether it is going to be
useful. If you can tell us how to make it
useful, we would be tickled to death. We would
like to have at least a place to start and are
hoping that you will help us. If you do, I
think it will mean something; if you do not, it
will be another federal document that you can
throw on your shelf.
If there is some opinion that it is the
wrong time to give it to you, there are other
reasons for holding it up. First, if we gave it
to you now, we would be violating rules. When
one individual has written a document, he is
not allowed to release it until it is reviewed by
at least his supervisor and in some cases even
higher than that. The office involved is to
have some say as to when this is released. We
just could not give it to you until at least one
review. Beyond that point, we would be happy
to entertain changes.
Comment: (Hank Coffer, C.K. GeoEnergy
Corp.) Probably we are using the
environment as a whipping boy. We
do need clout so that we can stand
up and say we dp not really have to
wait for the environmental issues to
get out of our way—they can
probably be handled. The other
thing that has not been spoken to is
the research program that EPA is
conducting. They would like to
make that as joint as possible. So if
you have any ideas that you would
like to see tried, they have funds
and they would like to do things in
conjunction with you. Secondly, as
we look at the guideline document,
we will probably set up the typical
task force to look at various parts of
the document and then after these
groups have looked at it, come back
at a general meeting and discuss the
whole document. It will probably
split out by air, water, and solids
basically. A meeting will most likely
be held in July. If anyone feels
that this task force should start any
earlier than that, then we would
entertain looking at an earlier
meeting. We will not have the
document to work with until about
July. Our current plans are to get
them to you individually. The task
force will probably be voluntary with
companies who would like to serve on
the various portions, air, water, or
solid. We will also make efforts to
integrate into these the BLM and the
state people so that we have full
coverage.
Question: If there will be no document till July
are you not going to miss an oppor-
tunity to get some input into the
March hearings aimed at regulatory
revisions? I understand that their
hearings are in March. Is this
group going to have some sort of
joint effort addressing itself to the
problems of solid disposal—should it
not occur a little sooner and perhaps
get that input into the record?
Comment: (Terry Thoem, EPA) The meetings
will be held March 7, 8 and 9 in
Denver. The critical document is
52
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Comment:
the December 18, 1978, Federal
Register. Those of you who have
not seen that, look at it. We have
solicited your opinions and thoughts
on it. We need to get the companies
to look at the impact of those regu-
lations and get your input and
comments on that. How we collec-
tively can influence that I am not
sure. One way is for the EPA oil
shale work group to make sure that
they look at comments that come in
regarding those regulations.
(Coffer, C.K. GeoEnergy Corp.)
With those coming up in March, it is
Hank
11:30 a.m.
probably pretty tough to get a
group together. The best inter-
action forum is the direct approach
of each company that is going to be
impacted by the regulations to get
with EPA.
We will be meeting with EPA on how
to implement these task forces in the
three areas and will be back in
contact with you. Those meetings
probably will be held just before the
general meeting, to discuss the
guidance document.
Coffer adjourned the meeting at
53
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ATTENDEES OF THE FIRST MEETING OF JOINT EPA/INDUSTRY
OIL SHALE WORKING GROUP
Denver Stouffer Inn, Denver, Colorado
January 23-24, 1979
Dean Allred
Research Associate
Marathon Oil Company
Box 269
Littleton, CO 80120
(303) 794-2601
Henry O. Ash
Executive Director
DOI Oil Shale
Environmental Advisory Panel
Denver Federal Center
Denver, CO 80225
(303) 234-3275
F.M. Barnett
Staff Vice President
Arthur G. McKee & Co.
6200 Oaktree Blvd.
Cleveland, OH
(216) 524-9300
Edward R. Bates
Physical Scientist
EPA
Extraction Technology Branch
5555 Ridge Ave.
Cincinnati, OH 45268
(513) 684-4417
Jim Beissel
Engineering Advisor
Carter Oil Co.
P.O. Box 2180
Houston, TX 77001
(713) 656-2065
Frank Berryman
Manager, Environmental Sciences
Chevron U.S.A.
555 Market St.
San Francisco, CA 94105
(415) 894-2242
Ken Biesinger
Director of Extramural Programs
EPA-ERL
6201 Congdon Blvd.
Duluth, MN 55804
(218) 727-6692
A.C. Bishard
Chief, Stationary Sources Section
Colorado Dept. of Health
4210 East llth Ave.
Denver, CO 80220
(303) 320-4180
Ron Bissinger
Environmental Engineer
Union Oil Co.
461 S. Bylston
Los Angeles, CA 90017
(213) 486-7760
Alden Christianson
Director, Program Operations Office
EPA-IERL
5555 Ridge Ave.
Cincinnati, OH 45268
(513) 684-4207
J.S. Cloninger
Manager, Oil Shale Geology
Union Oil of California
Valley Federal Plaza 505
Grand Junction, CO 81501
(303) 243-0112
Henry F. Coffer
President
C.K. GeoEnergy Corp.
5030 Paradise Rd., Suite A103
Las Vegas, NV 89119
(702) 739-9630
Dave Coffin
Senior Science Advisor
EPA-HERL
Research Triangle Park, NC 27711
(919) 541-2585
A.S. Couper
Project Manager
Amoco Oil
Box 400
Naperville, IL 60540
(312) 420-4843
W.K. Daniel
Staff Planning Analyst
Tenneco Oil
Box 2511
Houston, TX 77001
(713) 757-3185
Andrew W. Decora
Director
U.S. DOE
Laramie Energy Technology Center
P.O. Box 3385
Laramie, WY 82071
(307) 721-2211
55
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Paul M. Dougan
Cooperative Secretary
Equity Oil Co.
806 Ten West 3rd So.
Salt Lake City, UT 84101
(801) 521-3515
M.G. Fryback
Mgr. of Synfuels
Sunoco Energy Development Co.
12700 Park Central Place
Suite 1500, Box 9
Dallas, TX 75251
(214) 233-2600
Cindi Gorshow
Associate Director, Colo. Petroleum
Assn. and Committee on Oil Shale
Rocky Mtn. Oil & Gas Assn.
Denver, CO 80204
(303) 534-8261
Jackson Gouraud
Deputy-Undersecretary for
Commercialization, DOE
20 Massachusetts Ave. N.W.
Washington, DC 20545
(202) 376-4000
A.A. Gregoli
Projects Coordinator
Alternate Fuels Div.
Cities Service Co.
201 Building Box 300
Tulsa, OK 74102
(918) 586-4105
Robert Hiestand
Manager of Research and Engineering
Paraho
Box A Anvil Points
Rifle, CO 81650
(303) 625-2100
C. Hall
Senior Science Advisor
U.S. EPA-HERL
Research Triangle Park, NC 27711
(919) 549-2586
Larry Harrington
Engineer
Department of Energy
P.O. Box 3395
Laramie, WY 82071
(307) 721-2251
Eugene F. Harris
Chief, Extraction Technology Branch
Environmental Protection Agency
5555 Ridge Ave.
Cincinnati, OH 45268
(513) 684-4417
Don Hessling
Economics Analyst
Cities Service Co.
201 Building Box 300
Tulsa, OK 74102
(918) 586-2159
A.T. Ireson
Manager, Mining Venture
Shell Oil Co.
1700 Broadway
Denver, CO 80202
(303) 861-4408
Joseph M. Jackson
Executive Vice President
Multi Mineral Corp.
330 North Belt East
Houston, TX 77060
(713) 931-0330
Kurt Jakobson
Senior Staff Engineer
EPA (RD-681)
401 M Street S.W.
Washington, DC 20460
(202) 755-2737
Wesley L. Kinney
Aquatic Biologist
EPA
P.O. Box 15027
Las Vegas, NV 89114
(702) 736-2969
John H. Knight
Asst. Division Mgr.
Superior Oil Co.
2750 So. Shoshone
Englewood, CO 80110
(303) 761-5853
Lawrence Kronenberger
Environmental Coordinator
Carter Oil Co.
P.O. Box 2180
Houston, TX 77001
(713) 656-6352
Carroll F. Knutson
Executive Vice President
C.K. GeoEnergy Corp.
5030 Paradise Rd., Suite A103
Las Vegas, NV 89119
(702) 739-9630
Miles LaHue
Environmental Specialist, Air Quality
Area Oil Shale Office
131 N. 6th Street Suite 300
Grand Junction, CO 81501
(303) 245-6700
56
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J.A. Lamping
Director, Ecology
Standard Oil Company (Indiana)
200 E. Randolph Dr.
Chicago, IL 60601
(312) 856-7198
Max Legatski
Coordinator, Permits and Water Contracts
Colony/Atlantic Richfield
555-17th St.
Denver, CO 80217
(303) 575-7609
Richard Lieber
Vice President
Rio Blanco Oil Shale
9725 E. Hampton
Denver, CO 80217
(303) 751-2030
Les Ludlam
Manager, Colony Development Operations
Atlantic Richfield Co.
555-16th St. Box 5300
Denver, CO 80217
(303) 575-7607
Harry McCarthy
Vice President
Science Applications Inc.
15990 W. 74th
Golden, CO 80401
(303) 232-7900
William McCarthy
Chemical Engineer
U.S. EPA
OEMI, Rm. 645 (RD681)
401 M Street
Washington, DC 20460
(202) 755-0205
W.F. McDermott
Executive Vice President
Occidental Oil Shale, Inc.
P.O. Box 2687
Grand Junction, CO 81501
(303) 242-8463
Sam McFarlane
Manager, Denver Project Office
Department of Energy
P.O. Box 26500
Lakewood, CO 80226
(303) 234-5791
Les G. McMillion
Hydrologist
U.S. EPA
P.O. Box 15027
Las Vegas, NV 89114
(702) 736-2969 ext. 241
Rees Madsen
Environmental- Coordinator
White River Oil Shale
1315 W. Highway 40
Vernal, UT 84078
(801) 789-0571
Steve Mankowski
Staff Engineer
Geokinetics Inc.
P.O. Box 887
Vernal, UT 84078
(801) 789-0806
George K. Massad
Executive Vice President
Western Oil Shale Corp.
Oil Center West
2601 New Expressway
Oklahoma City, OK 73112
(405) 840-3531
John Maziuk
Chief Engineer, Synthetic Fuels Group
Mobil Research & Development
P.O. Box 1026
Princeton, NJ 08540
(609) 737-3000 ext. 2505
Mark Mercer
Environmental Scientist
U.S. EPA
401 M Street S.W.
Washington, DC 20460
(202) 755-9167
Alan Merson
Regional Administrator
U.S. EPA Region VIII
1860 Lincoln Street, Suite 900
Denver, CO 80203
(303) 837-3895
Glen A. Miller
Supervisory Hydrologist
USGS-AOSO
131 N. 6th Street
Grand Junction, CO 81501
(303) 245-6700
J.B. Miller
President
Rio Blanco Oil Shale
9725 E. Hampton
Denver, CO 80231
(303) 751-2030
Paul Mills
Quality Assurance Officer
EPA-IERL
5555 Ridge Ave.
Cincinnati, OH 45268
(513) 684-4216
57
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Charles Murphy
Planning Manager
Mobil Research & Development
150 E. 42nd Street
New York, NY 10017
(212) 883-6752
Bob D. Newport
Environmental Protection Specialist
R.S. Kerr
Environmental Research Lab.
P.O. Box 1198
Ada, OK 74820
(405) 332-8800
Jack O'Brien
Regional Coordinator for Environment & Safety
Department of Energy
P.O. Box 26500
Lakewood, CO 80226
(303) 234-5791
Kent R. Olson
Staff Attorney
Gulf Mineral Resources Co.
1720 S. Bellaire St.
Denver, CO 80222
(303) 758-1700 ext. 213
Arnold H. Pelofsky
Director of Alternate Fuels R & D
Science Applications Inc.
E. Brunswick, NJ 08816
(201) 238-2200
Harry Pforzheimer
Program Director
Sohio Natural Resources
300 Enterprise Bldg.
3rd & Main Sts.
Grand Junction, CO 81501
(303) 243-9550
J.H. Phillips
Manager of Process Development
Texaco, Inc.
P.O. Box 2100
Denver, CO 80201
(303) 861-4220
Allen Randle
Manager of Retort Operations
Union Oil Co.
Valley Federal Plaza #505
Grand Junction, CO 81501
(303) 243-0112
W.L. Rogers
Manager, Environmental Affairs
Gulf Oil Co.
1780 So. Bellaire Street
Denver, CO 80222
(303) 758-1700
J.F. Rollin
Geologist
Chevron Shale Oil Co.
P.O. Box 599
Denver, CO 80201
(303) 759-7042
Peter A. Rutledge
Area Oil Shale Supervisor
USGS
131 N. 6th St.
Grand Junction, CO 81501
(303) 245-6700
R.F. Schlecht
President
Chevron Shale Oil Co.
225 Bush Street
San Francisco, CA 94104
(415) 894-4081
Robert Siek
Deputy Director
Colorado Dept. of Natural Resources
1313 Sherman
Denver, CO 80203
(303) 839-3311
H. Michael Spence
Attorney at Law
Mosley, Wells & Spence
1600 Broadway
Denver, CO 80202
(303) 861-8136 (Representing TOSCO)
Hilding Spradlin
Environmental Research Assistant
Geokinetics Inc.
582 N. Vernal Ave.
Vernal, UT 84078
(801) 789-0806
Winnie Stoberski
Senior Secretary
C.K. GeoEnergy Corp.
5030 Paradise Rd., Suite A103
Las Vegas, NV 89119
(702) 739-9630
C.W. Sullivan
Environmental Coordinator
Superior Oil Co.
2750 So. Shoshone
Englewood, CO 80110
(303) 761-5853
Bill Tarleton
District Supervisor
Chevron Shale Oil Co.
P.O. Box 599
Denver, CO 80201
(303) 759-7042
58
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Terry Thoem
Director
U.S. EPA Region VIII
1860 Lincoln Street, Suite 900
Denver, CO 80203
(303) 837-5914
R. Thomason
Manager, Environmental Services
Occidental Oil Shale, Inc.
P.O. Box 2687
Grand Junction, CO
(303) 242-8463
Robert Thurnau
Physical Scientist
U.S. EPA
5555 Ridge Ave.
Cincinnati, OH 45268
(513) 684-4363
Bruce Tichenor
Project Officer
EPA-IERL
Research Triangle Park, NC 22771
(919) 629-2547
Ben Weichman
President
Multi Mineral Corp.
330 North Belt East
Suite 200
Houston, TX 77060
(713) 931-0330
59
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing;
REPORT NO.
EPA-600/9-79-025
TITLE ANDSUBTITLE
EPA PROGRAM CONFERENCE REPORT:
Oil Shale- Proceedings of the First EPA/
Industry Forum, January 23-24, 1979
6. PERTdRM7NG~"ORGANIZATION CODE
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
1Q7Q
AUTHOR(S)
Christiansen, A., Pforzheimer, H.,
Thoem, T.L., et. al.
8. PERFORMING ORGANIZATION REPORT NO.
PERFORMING ORGANIZATION NAME AND ADDRESS
C.K. GeoEnergy Corporation
5030 Paradise Road
Las Vegas, NV 89119
10. PROGRAM ELEMENT NO.
1NE825
11. CONTRACT/GRANT NO.
68-01-5029
12. SPONSORING AGENCY NAME AND ADDRESS
Office of Energy, Minerals and Industry
Environmental Protection Agency
Washington, DC 20460
13. TYPE OF REPORT AND PERIOD COVERED
Conference - jarmary 1P7P/
14. SPONSORING AGENCY CODE
EPA/600/17
15. SUPPLEMENTARY NOTES
C.K. GeoEnergy conuct:
Hank Coffer
Airport Center. Suite A103
S030 Paradise Road
Las Vegaa. NV B9119
<702) 739-9630
EPA conucta:
William N. McCarthy. Jr.
U.S. EPA (RD-661)
401 M Street s.w.
Washington. DC Z04GO
(202) 7SS-2737
Alden Chrlstlanaon
U.S. EPA-IERL
2G West St. clalr
Cincinnati, OH 4S268
(513) 664-4207
16. ABSTRACT
This publication reports the proceedings of the first meeting of the joint EPA/
Industry Forum to Research Technical and Regulatory Problems relating to Oil Shale.
The purpose of the meeting was to establish a closer working relationship between
EPA and industry and to develop better channels of communication.
Attending the meeting were federal representatives from EPA and DOE, state
representatives from Colorado and personnel from all of the companies active in oil
shale development and research programs. Highlights of the meeting included
presentations by the EPA Region VIII Administrator, the DOE Deputy-Undersecretary
for Commercialization, and reviews of eleven (11) active oil shale development projects
by representatives of the operating companies. The meeting took place in Denver,
January 23-24, 1979.
17.
KEY WORDS AND DOCUMENT ANALYSIS
a.
DESCRIPTORS
b. IDENTIFIERS/OPEN ENDED TERMS
COS AT I l;icld/Group
Commercialization
Development
Lease Tracts
Monitoring
Nahcolite
Oil Shale
Permits
Proceedings
Processes
Regulations
Research
Retorts
Synthetic Fuels
C-a
C-b
Equity Oil
Geokinetics
Multi Minerals
Occidental
Piceance Basin
Rio Blanco
Sohio
Superior Oil
Talley
TOSCO
U-a/U-b
Uintah Basin
Union Oil
White River
48B
680
97F
97K
970
18. DISTRIBUTION STATEMENT
RELEASE UNLIMITED
19. SECURITY CLASS (This Report)
UNCLASSIFIED
20 SECURITY CLASS (This page)
UNCLASSIFIED
21. NO. OF PA
£8_
22. PRICE
EPA Form 2220-1 (9-73)
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INSTRUCTIONS
1. REPORT NUMBER
Insert the EPA report number as it appears on the cover of the publication.
2. LEAVE BLANK
3. RECIPIENTS ACCESSION NUMBER
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approval, date of preparation, etc.).
6. PERFORMING ORGANIZATION CODE
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zation.
8. PERFORMING ORGANIZATION REPORT NUMBER
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14. SPONSORING AGENCY CODE
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16. ABSTRACT
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significant bibliography or literature survey, mention it here.
17. KEY WORDS AND DOCUMENT ANALYSIS
(a) DESCRIPTORS - Select from the Thesaurus of Engineering and Scientific Terms the proper authorized terms that identify the major
concept of the research and are sufficiently specific and precise to be used as index entries for cataloging.
(b) IDENTIFIERS AND OPEN-ENDED TERMS - Use identifiers for project names, code names, equipment designators, etc. Use open-
ended terms written in descriptor form for those subjects for which no descriptor exists.
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jority of documents are multidisciplinary in nature, the Primary Field/Group assignment(s) will be specific discipline, area of human
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EPA Form 2220-1 (9-73) (Ravarte)
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