&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
                                                12

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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
                                                13

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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.
                                                 14

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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
                                                15

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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.
                                                16

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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
                                                 17

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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

-------
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

-------
             THE SUPERIOR OIL COMPANY
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             THE SUPERIOR OIL COMPANY
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                                      SHOWING

                                 PILOT ADIT AND PILOT MINE
.
STEP 1 !VU
SPENT SHALE '
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-------
CT)
                              THE SUPERIOR OIL COMPANY



                              PHOTOSORTING SYSTEM
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           THE SUPERIOR OIL COMPANY

          CONCEPTUAL DESIGN

            SODA ASH PLANT
                             ' MULTIPLE EFFECT

                               CRVSTALLIZERS
                                                         CONDENSED

                                                         WATER
             PERIODIC PURGE
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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

-------
     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
                                                34

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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
                                                 36

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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.
                                                 39

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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
                                                41

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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
                                                 42

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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
                                                 43

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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
                                                44

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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
                                                 45

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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?
                                                46

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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
                                                47

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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?
                                                48

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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)

-------
                                                         INSTRUCTIONS

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        Include ZIP code.

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        Leave blank.

    15. SUPPLEMENTARY NOTES
        Enter information not included elsewhere but useful, such as:  Prepared in cooperation with, Translation of, Presented at conference of,
        To be published in, Supersedes, Supplements, etc.

    16. ABSTRACT
        Include a brief (200 words or less) factual summary of the most significant information contained in the report.  If the report contains a
        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.

        (c) COSATI FIELD GROUP - Field and group assignments are to be taken from the 1965 COSATI Subject Category List. Since the ma-
        jority of documents are multidisciplinary in nature, the Primary Field/Group assignment(s) will be specific discipline, area of human
        endeavor, or type of physical object. The application(s) will be cross-referenced with secondary Field/Group assignments that will follow
        the primary posting(s).

    18. DISTRIBUTION STATEMENT
        Denote reusability to the public or limitation for reasons other than security for example "Release Unlimited."  Cite any availability to
        the public, with address and price.

    19. & 20.  SECURITY CLASSIFICATION
        DO NOT submit classified reports to the National Technical Information service.

    21. NUMBER OF PAGES
        Insert the total number of pages, including this one and unnumbered pages, but exclude distribution list, if any.

    22. PRICE
        Insert the price set by the National Technical Information Service or the Government Printing Office, if known.
EPA Form 2220-1 (9-73) (Ravarte)

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