UNITED ST A TBS
ENVIRONMENTAL PROTECTION
AGENCY
OIL SHALE
BRIEFING BOOK
REGION VI11
DENVER COLORADO
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& sr%
"52.1
Oil Shale Research Workgroup
Tour
October 21-23, 1980
Itinerary
October 20 Arrive in Grand Junction, Colorado
Evening meeting (informal, optional, about 7:00pm) with
Area Oil Shale Supervisor's Office.
Stay at American Family Lodge (303/243-6050)
October 21
7:zo Sos oV £ttv*Ay
7:30am Depart for Union ***
9:00 - 10:00 Briefing of Union's activities
Field visit view of construction
10:00 Depart for Colony
10:30 - 11:30 Briefing of Colony's activities
Field visit view of construction
11:30, Lunch
Noon Depart for Paraho
1:00 - 2:30pm Briefing and tour of Paraho facilities
Split into three groups -
mine, retort, revegetation
2:30 Depart for Visibility/Air Quality site
3:00-4:30 View EPA Region VIII Monitoring s
4:30 Depart for Meeker
5:30 Arrive at Sleepy Cat Lodge (303/878-4413)
d I IC
ite (\i)e
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October 22
y-.DO ^J+rtKr
11:30
11:30 - 1:00
1:00
1:30 - 3:30
3:30
5:30
October 23
8:30am
9:00 - 10:30
10:30
11:30
12:30 - 2:00pm
4:30
^iC-b Cc^ctWA
5iiu\o:r of C-b
Depart for USBM shaft, Horse Draw
\)\QMJ c£ C.-b ovs 4-Ve Way
Lunch
Briefing and Tour (underground)
Depart for Tract C-a
Briefing and Tour of C-a
Depart Tract C-a for Vernal, Utah
Drive by briefing of Superior
Arrive at Vernal
Stay at Dinosaur Motel (801/789-2660) and
Motel Utah (801/789-1131 )
Depart for DOE Tar Sands Project
Tour of Asphalt Ridge
Depart for lease tracts UaUb
Lunch
Depart for Grand Junction
Arrive in Grand Junction
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OIL SHALE INDUSTRY PROFILE
The development of oil shale has been "just around the corner"
for at least 60 years. The heart of the problem facing a viable
oil shale industry has been economics. While some companies talk
about overly restrictive environmental requirements and of regulatory
uncertainty as factors in the non-development of oil shale, close
scrutiny of the situation brings one back to economics as the principal
constraint. Other factors besides economics (environmental requirements
and regulatory uncertainty to a much lesser degree) which have postponed
the development of an oil shale industry include technical and legal
uncertainties. Considerable work has been done over a number of years
to remove many of the technical uncertainties surrounding oil shale
processing. However, uncertainties regarding scale-up of technologies
remain. The largest demonstration of retorting has been at a capacity of
1200 tons per day. Commercial size modules will be about six times
larger. Two major legal constraints face a potential oil shale-industry.
The first consists of the contested ownership of 43,GOO acres of un-
patented mining claims filed on oil shale land under the mining law of
1872. The Mineral Leasing Act of 1920 made oil shale a leasable
mineral. Recent court decisions have unheld the validity of the pre
1920 claims. The second legal uncertainty involves Federal vs State
ownership of certain lands. Both Utah and Colorado have claimed
Federal lands bearing oil shale under provisions of the Statehood Enab-
ling Act of 1894.
Produced shale oil is entitled to the world free market price as
a result ofactions by the President and DOE. Most companies were
projecting a required price of about $25 per barrel in the 1978-79 time
frame. Therefore, even with inflation, shale oil is becoming attractive
at the present world market price of about $30 per barrel. Further
adding to the attractiveness of shale oil is the certainty of a supply
of oil, given recent events in the Middle East.
Shale oil is being produced in the USSR and in China. Commercial
size projects are under construction in Brazil and Australia. The
Federal Prototype Oil Shale Leasing Program v/as launched in the United
States late in 1973 in order to demonstrate the viability of the
technology and to define the environmental impacts of shale oil production.
Operations via the modified in-site technique are proceeding on the two
Colorado lease tracts. The two Utah lease tracts are involved in the
land ownership legal battle. The two Wyoming tracts attracted no bidders.
Development on private lands'in C-.lf.rado appears to be destined to under-
ground mining and surface retorting.
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The President established a goal of production of 400,000 bpd
of shale oil by 1990. Congress appears to be arriving at a similar
production goal but to be accomplished by 1992. Due to the recent
renewed interest in oil shale development D0I Secretary Andrus is
evaluating the need for resumption of an oil shale leasing program
prior to fulfillment of the Prototype Program objectives. A recent
survey of oil shale company production goals by 1990 resulted in a
total figure -f almost 700,000 bpd (see attached table). It should
be strongly emphasized that these must be considered as posturing
or planning figures and in no way represent firm commitments to
proceed.
In conclusion, oil shale has had a great potential for years;
it now appears that the 1980's will bring some development into being.
The role, location, and mode of development will all bear upon the
environmental acceptability of the industry.
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Status of Oil Shale Projects
COMMERCIAL PROJECTS
1. CATHEDRAL BLUFFS SHALE OIL CO. - Occidental & Tenneco(T3S,R96W,6PM
Bonus bid of $117.8 million paid to acquire rights to Tract C-b in
1974. Original partners, ARCO and TOSCO, withdrew in 1975. A third
original partner, Shell, withdrew 11/76. Occidental joined(with
Ashland as remaining partner)ll/76. Ashland withdrew 2/14/79. On
9/4/79, Tenneco acquired half interest for $110 million. Modified
DDP for 57,000 BPD modified in situ plant submitted March 1, 1977.
DDP approved 8/30/77. EPA issued conditional PSD permit for first
phase of development 12/16/77. Primary contractor is Ralph M. Parsons
Company. Three headframes, two of concrete and one of steel, have
been erected. As of mid-Octobe^the shaft depths were: Ventilation/
Escape - 910', Service - 725', Production - 726'.
Project cost: $1 billion
2. COLONY DEVELOPMENT OPERATION - (60%) and TOSCO (40%)(T5S,R95W,6PM)
Proposed 46,000 BPD project on Colony Dow West property near
Grand Valley, Colorado. Underground room-and-pillar mining and
TOSCO II retorting planned. Production would be 66,000 TPD of
35 GPT shale from a 60-ft. horizon in the Mahogany zone. Development
suspended 10/4/74. Draft EIS covering plant, 196-mile pipeline
to Lisbon, Utah, and minor land exchanges released 12/17/75. Final
EIS has been approved. World .price for shale oil and inclusion of
shale oil in entitlements program increases likelihood that project
will be reactivated. EPA issued conditional PSD permit 7/11/79. If
a proposed $3/bbl tax credit indexed for inflation or equivalent
incentive becomes law, Colony hopes the climate will improve to
attract enough investment for reactivation of the project.
Project cost: Estimated at $1,132 billion(1977 collars) including
$20 million for community development.
3. UNION LONG RIDGE PROJECT - Union Oil Company of California (T5S,R95W,6PM)
In 1974, Union announced plans for a commercial project ranging in
size from 50,000 BPD to as much as 150,000 BPD on some 22,000 acres
of fee land near Grand Valley, Colorado. Land, shale and water
resources are adequate. Underground room-and-pillar mining and
Union "B" retorting would be employed. Union's "B" retort is a
modification of their direct-heated,rock pump retort first tested
in the late 1950's. Current plans are to proceed with a 9,000 BPD
(10,000 TPD) prototype facility before expanding to commercial
production. Environmental and engineering studies are substantially
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2.
COMMERCIAL PROJECTS (Contd.)
completed for prototype facility. Union has announced that it
will proceed if a $3/bb1 tax credit is enacted. EPA issued
conditional PSD permit 7/31/79. Colorado Mined Land Reclamation
Board issued permit 8/2/79.
Project cost: Approximately $100 million for 9,000 BPD module.
4. RIO BLANCO OIL SHALE COMPANY - Gulf & Standard(Indiana)(T2S,R99W,6PM)
Proposed project on federal Tract C-a in Piceance Creek basin,
Colorado. Bonus bid of $210.3 million to acquire rights to tract;
lease issued 3/1/74. Revised DDP calling for use of LLL Rubbilized
In Situ Extraction(RISE) of shale oil submitted to Interior 5/77.
Combination of modified in situ retorts and surface retorts(TOSCO II)
will be used to produce 76,000 BPD. Five-year process development
project will be conducted to prove in situ technology. Commercial
facility scheduled to get underway in 1987. DDP approved 9/22/77.
American Mine Services Inc. of Denver was awarded a $4 million contract
11/21/77 to sink a 15-foot wide, 971-foot deep shaft. EPA awarded
PSD permit on 12/16/77. Primary contractor is Morrison-Knudsen
Company with a $38.8 million contract. Tests are underway to
determine underground water quantities. Agreement($6 million) reached
3/79 with Oxy for exchange of modified in situ technical data. On
8/31/79 approval was granted to modify in situ retorts using RBOSC
design. On 7/16/79 announced 1-year design and cost study($4 million)
that could lead to $100 million construction and operation of Lurgi-
Ruhrgas surface retort demonstration plant. Shaft completed at
979' in 10/79, and outfitting is progressing. Surface processing
facilities scheduled for completion 1st quarter of 1980. First burn
is scheduled for Jiprfl 1980.
OetafoQ?
Project cost: Four-year process development phase budgeted at
$93 million. No cost estimate available for
commercial facility.
5. WHITE RIVER SHALE PROJECT - Phillips, Sohio & Sunedco(T10,R94E,SLM)
Proposed joint development of federal lease Tracts U-a and U-b in
the Uinta Basin near Bonanza, Utah. Bonus bid for Tract U-a was
$76.6 million by Sun(now Sunedco) and Phillips. Bonus bid for
Tract U-b was $45.1 million by White River Shale Oil Corporation
(jointly owned by Phillips, Sohio and Sunedco). Rights to Tract
U-b subsequently assigned to Sohio. Both leases issued 6/1/74.
Detailed Development Plan filed with Interior 6/76 proposes modular
development with ultimate expansion to 100,000 BPD. Application
for one-year suspension of lease terms granted 10/76 based on
environmental considerations. This suspension was superseded by a
court injunction suspending the lease terms based on property title
questions. WRSP's leases U-a and U-b are in jeopardy due to the
existence of unpatented pre-1920 oil shale placer mining claims and
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3.
COMMERCIAL PROJECTS (Contd.)
by an, as yet unresolved,application for a state lease to the same
property by Peninsula Mining associated with Utah's in-lieu land
selection procedure. The injunction order suspending the U-a and
U-b federal lease terms is uncontested and is in full force and
effect. The final Environmental Baseline Study report was issued
on 11/15/77 by WRSP. Utah approved White River Dam and Reservoir
funding 2/78. EIS for the Dam is proceeding.
Project cost: Estimated at $1.61 billion for 100,000 BPD
project (1975 dollars)
6. NAVY OIL SHALE RESERVE DEVELOPMENT - TRW Inc.
Navy issued RFP 6/77, calling for preparation of Master Develop-
ment Plan for Naval Oil Shale Reserves 1,2, and 3. Objective is
to put N0SR in position for large scale development of resources
within five years. Contract awarded 6/22/78 to team composed of
TRW, CF Braun & Company, Gulf Research & Development Company,
Williams Bros. Engineering Company, and Tosco Corporation.
Comparative analysis of N0SR 1 and eight other Piceance Creek basin
properties has been completed. A production range of 50,000 to
200,000 BPD is being evaluated. Baseline environmental data are
being obtained.
Project cost: $2.16 million through 10/1/79
$60 million in 4 annual options
7. CHEVRON RESOURCES CO.
Project feasibility study is ongoing. Project would consist of
open pit mining and surface retorting. Feasibility plans are
directed toward a 100,000 BPD operation by 1990. Baseline environ-
mental data are being collected. Although on private land an
EIS would be prepared because of offsite right-of-way approvals.
8. EXXON COAL USA, INC.
A request for land exchange was sent to BLM on December 28, 1979.
Project feasibility study is ongoing.
9. SUPERIOR OIL CO. (TIN,R97W,6PM)
Proposed project involving production of shale oil, nahcolite,
alumina and soda ash from a 6,500-acre privately owned tract in
Piceance Creek basin near Meeker, Colorado. Underground mining and
aboveground processing to yield shale oil, nahcolite, aluminum
trihydrate, and soda ash. Facilities proposed to be constructed
in modules of 11,586 B0PD from 26,176 TPD shale feed. Co-products
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A.
COMMERCIAL PROJECTS (Contd.)
would be 4,878 TPD of 80 percent nahcolite, 580 TPD alumina,and
1,005 soda ash. Land exchange request to block up economically
viable property filed with Interior 12/73. Draft EIS issued by
BLM 7/17/79.
Project cost: $300 million for one multi-mineral module
$473,459 for EIS
10. TOSCO SAND WASH PROJECT - Tosco Corp.(T9S,R21E,SLM)
Proposed 50,000 BPD project on 14,688 acres of state leases in
Sand Wash area of Uinta basin near Vernal, Utah. State-approved
unitization of 29 non-contiguous leases requires $8 million tract
evaluation by 1985. Minimum royalty of $5 per acre begins in 1984
and increases to $50 per acre in 1993. Preliminary feasibility
study completed for TOSCO II surface retorting. Process and
engineering work underway. Environmental assessment underway on
site, but no other field work being conducted. Tosco has drilled
a core hole on the Sand Wash site as a preliminary step to shaft
sinking and establishment of a test mine. The test mine would
confirm economics and mining feasibility plans for the commercial
project. Permits for this new work have been received from the
state.
Project cost: Approximately $1 billion
11. OCCIDENTAL OIL SHALE, INC.,LOGAN WASH(T75,R97W,6PM)
Oxy is developing its modified in situ retorting technology on its
Logan Wash site near De Beque, Colorado. Field tests have been
underway since 1972. Initial tests were conducted on three small
retorts measuring 30 feet square by 70 feet high. Tests are now
being conducted on commercial scale retorts measuring 120 feet by
280 feet high. Thirty thousand barrels of oil were produced from
first commercial retort between December 75 and June 76. A $60.5
million cost-sharing contract was signed 9/30/77 with DOE.
Production from retort 5 was 11,287 barrels. Retort number 6 was
rubblized 3/25/78. In mid-September, two weeks after ignition, a
sill pillar collapsed within Retort 6, but there was no interruption
in operation. As of 10/15/79 gross oil production from Retort #6
was 47,733 barrels. PSD permit for Retorts 7 & 8 awarded 11/1/79.
Project cost: To date at least $45 million spent
$60.5 million DOE cost-sharing contract
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5.
COMMERCIAL PROJECTS(Cont.)
12. PETROSIX - Petrobras (Petroleo Brasileiro, S.A.)
A 2,200 TPD Petrosix demonstration retort located near Sao
Mateus do Sul, Parana, Brazil. The plant has been operated
successfully near design capacity in a series of tests since
1972. A U.S. patent has been obtained on the process. A 50,000
BPD plant is now being designed. Preliminary indications favor a
scaled-up facility about five miles from existing site. A 36-ft.
inside diameter vertical retort is being designed for construction
at the San Mateus plant site for cold-testing of shale feed and
discharge devices. This is a scale-up factor of four over the
existing 18-foot inside diameter retort. Part of commercialization
project is underway, viz. mine expansion, engineering of the retort,
and equipment procurement. Partial operation will begin in 1984,
and full capacity will be reached in 1987.
Project cost: Total expenditures in excess of $35 million
Projected cost of 50,000 BPD plant is $1.3 billion
13. RUNDLE PROJECT - Central Pacific Minerals & Southern Pacific Petroleum
Development of the Rundle deposit in Queensland, Australia.
Construction will begin in 1980 on two commercial demonstration
modules using Superior and Lurgi-Ruhrgas processes. Production
projected to be 20,000 BPD by 1982. By 1986, production would
grow to 250,000 BPD from 40 retorts.
Project cost: $316 million (US) for 20,000 BPD
$2.16 billion (US) for 250,000 BPD
R&D PROJECTS
14. DOW CHEMICAL CO.
DOW was awarded a four-year contract by ERDA in March 1977, for
production of fuels from Antrim oil shale formation. Project
includes characterization and mapping of Antrim shale resources
in Michigan Basin, evaluation of three in situ fracturing techniques
on an 80-acre site belonging to DOW, and two in situ production
tests. Explosive fracturing activities for the hydraulic fracturing
subtask were completed in the 100 series wells. Well cleanout was
almost completed and permeability studies and fracture evaluation
will proceed as soon as it is complete. Evidence that there is
communication between these wells continues to accumulate. The
third and fourth shots in the explosive underreaming series were
detonated in well #301. The well cavity was increased by a factor
of 2.4 compared to the original borehole volume for a 62-foot section
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6.
R&D PROJECTS(Contd.)
after the third shot. The fourth shot produced more damage to
the bottom section of well casing. For the chemical underreaming
subtask, well #201 was notched in a limestone stringer below the
Antrim formation. The well was hydrofractured with water but no
communication with nearby wells was observed. Further evaluation
of this subtask is underway. The data from extraction trials on
the front site have been collected and processed. Analysis of
product gases from the final trial showed that they had a total
energy content 4.9 times the total solid fuel and gaseous fuel
put into the well for ignition, thus establishing that significant
quantities of Antrim shale had been affected by the operation.
Ignition in well #305 in 10/79 gave indicati
combustion occurred.
Project cost: $14 million
15. EQUITY OIL COMPANY
Equity received a $5.5 million contract from ERDA in June 1977,
for development of in situ technology using superheated steam.
The work is being conducted on a one-acre site in the Piceance
Creek basin of Colorado. The first phase of the contract has
been completed which involved drilling two core holes near a
previous steam injection site. Site evaluation has been completed.
Start-up of field project occurred 6/79. As of mid-October 1979,
steam was being injected at 950°F and 1,450 psi at a rate of
20,000 to 25,000 lb/hr(about 50% design rate). No shale oil had
been produced.
Project cost: DOE cost-sharing contract for $6.5 million.
16. GE0KINETICS,INC.
Geokinetics has been conducting field tests to develop horizontal
in situ retorting technology since 1973. Obtained ERDA contract
7/77 to develop technology in thin horizontal beds of oil shale in
Uintah County, Utah. Porosity is established in formation by
raising the shallow overburden during explosive fracturing of the
shale formation. Total production to end of 1978 was 5,437 barrels.
Project cost: DOE cost-sharing contract valued at $9.2 million
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7.
R&D PROJECTS(Contd.)
17. LARAMIE ENERGY TECHNOLOGY CENTER
Laramie and Rocky Mountain Energy Co. have been conducting
in situ shale oil production tests for several years near
Rock Springs, Wyoming. Partial dismantling of Site 12 began
5/79, and post-operation water monitoring phase began 7/79.
Project cost: Undetermined
18. PARAHO OIL SHALE FULL SIZE MODULE PROGRAM - Paraho Development Corporation
Paraho is seeking six sponsors, each contributing $500,000, for
Phase I of a 3-phase module program. Phase I consists of engineering
and planning; Phase II is detailed design, procurement, and
construction; and Phase III is operation. Paraho initiated Phase I
at its own expense on 12/1/77.
Project cost: $4 million for 16-month Phase I
$75 million for 21-month Phase II
$14 million for 24-month Phase III
19. U.S. BUREAU OF MINES - Multi Minerals Corp.
USBM began drilling 10-foot diameter, 2,400-foot deep shaft 3/77.
Objective is to mine samples of oil shale, nahcolite, and dawsonite
from shale formation. Shaft may be used for ventilation in future
experimental mine. Drilling operations were completed 10/2/77 at
2,371 feet. Shaft classified as gassy mine. Multi Mineral Corp.
is performing experimental mining. EIS in preparation for
"Integrated In Situ Process" testing.
Project cost: Over $8 million for shaft sinking.
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PREDICTED SHALE OIL PRODUCTION LEVELS FROM
WESTERN OIL SHALE RESOURCES
1980 —1996
NOV 1979
OIL SHALE PROJECTS
I960
1981
1962
1963
1984
1965
1966
1987
1966
1989
1990
1991
1992
1993
1994
1995
1996
OCCIDENTAL OIL SHALE «
LEASE TRACT C-b
PILOT OPERATION,ENGR.
6,250
30/000
30,000
50,000
87,500
140000
aoopoc
COMMERCIAL OPERATION
PERMITTING, CONSTRUCTION
PROJECT RIO 8LANC0 b
LEASE TRACT C-a
PILOT OPERATION.ENGR.
19000
45,600
76000
COMMERCIAL OPERATION
90000
1 II.60O
135000
COMMERCIAL
PERMITTING, CONSTRUCTION
ENGR, PERMITTING, CONSTRUCTION
OPERATION
GEOKINETICS, INC e
UINTA BASIN
SAME AS
o
! o
i
3,000
10,000
15,000
25000
40000
I
O
ABOVE
EOUITY OIL *
PICEANCE BASIN
PILOT OPERATION
PLANS DEPEND UPON OUTCOME 0^ PILOT OPERATIONS -
1 '
NAVAL OIL SHALE RESERVE •
PICEANCE BASIN
FEASIBILITY STUDY
DESIGN
CONSTRUCTION
280OO
41,500
50,000
COMMERCIAL OPERATION
PERMITTING
DEMONSTRATION OF ABOVE f
GROUND RETORTING I DOE-PON)
MODULE MODULAR PLA
NT
8,000
4,000
END
PROJECT
DESIGN| CONSTRUCTION
DEMONSTRATION OF ADVANCED g
RETORT TECHNOLOGY IDOE-PON)
• RESEARCH >
PILOT TESTS. ENGINEERING,PERMITTING
8,000
8,000
ENO
PROJECT
MODULE CONSTRUCTION
UNION OIL h
LONG RIDGE, PICEANCE BASIN
CONSTRUCTION
9,500
MOOULE OPER.
3Q00G
COMMERCIAL OPERATION
O
!
IOO0OO
CONSTRUCTION
sO/JW
SCALE UP
COLONY/TOSCO i
PARACHUTE CREEK,PICEANCE BASIN
DESIGN, CONSTRUCTION
25,900
38,400
46,200
COMMERCIAL OPERATION
TOSCO SANO WASH i
UINTA BASIN
PERMITTING.
23,100
46,200
CONSTRUCTION
WHITE RIVER PROJECT k
LEASE TRACTS Uo.Ub, UINTA BASIN
EXACT SCHEDULE WILL DEPEND UPON OUTCOME OF LIT) GAT (ON
45,000
9O0OO
CHEVRON OIL •
PICEANCE BASIN
engr,permitting, pilot
7,000
I5.60C
|24,200
32,800
41,400
50,000
66,600 j63,200
module construction
IOO0OC
SUPERIOR OIL n»
PICEANCE BASIN
PERMITTING, CONSTRUCTION
6.70O
lO.OOO
12000
COMMERCIAL OPERATION T
-
MOBIL OIL «
PICEANCE BASIN
ENGINEERING. PERMITTING,CONSTRUCTION
6,000
60OO
3Q60O
42,500
50000
COMM. OPERATION
780OO
91,500
00,000
SCALE UP
CARTER OIL • 0
ENGINEERING. PERMITTING. CONSTRUCTION,
16,600
24,900
3O0OO
45000
6Q 000
COMMERCIAL OPERATION
CITIES SERVICES
NO DEFINITE PLANS AT THIS TIME
TOTAL PROJECTS
0
0
14,900
22,500
81,650
181,300
9
3
337?00(446^00
M73O0
e930OG
723JOO
73^200
821000
942.40C
98CC90C
989^400
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"Tosco
OIL SHALE; READY, COMMERCIALLY COMPETITIVE, ENVIRONMENTALLY
SOUND
The Resource
Mineral deposits called "oil shale" appear in many
parts of the world, and have been produced on a commercial
scale for over 150 years. Scottish shale oil was produced
through the late 19th century into the 1920's; Sweden's
deposits were worked to economic exhaustion in the period
after World War II; Chinese and Estonian oil shale is now
in production. A fledgling industry exists in Brazil, and
studies are under way in Israel, Morocco and Australia.
Although all these deposits and the Devonian shales
of the Eastern United States are all called "oil shale,"
they vary in their composition, richness, and mineability.
Present United States oil shale plans focus on the oil
shale of the Green River formation of Colprado, Utah and
Wyoming. This deposit, the remains of an ancient, stagnant
freshwater lake which gradually filled with organic matter
and dust, is especially rich in an area in Northwest Colorado
called the Piceance Basin and an area of Utah immediately
to the West called the Uinta Basin.
Oil shale is a hard, sedimentary rock, characterized
by thin layers resulting from annual patterns of deposition
in the prehistoric lake. It does not contain liquid oil,
but an organic matter called kerogen. When the oil shale
is heated to about 900°F in a process known as pyrolysis,
the organic kerogen vaporizes and the vapors may then be
condensed into shale oil, except for a non-condensible gas
fraction.
-17-
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The gas fraction, which is small in the Tosco II
retorting process, may be used as plant fuel. The re-
mainder of the oil shale is the dust which was deposited
in the lake and a small amount of residual carbon. In
the Tosco II retorting process the dust is recovered
in the form of a fine, black silt-like material called
spent shale.
The composition and usability of shale oil is within
the range of properties of conventional crude oils, its
only unusual properties being a high "pour point" (which
is not a problem) and a high nitrogen content. The nitrogen,
which would interfere with conventional refinery processes,
can be removed by standard hydrogenation processes.
The hydrogenation process produces a synthetic crude
oil of premium quality which can be readily converted into
transportation fuels in a typical Rocky Mountain refinery.
Table I compares the yield from shale oil with that from
a premium quality sweet Wyoming crude currently selling for
$28.50 a barrel.
Shale oil is a source of transportation fuels comparable
to premium quality domestic crudes. Since it fits easily
and readily into the existing complex refining, distribution
and consumption system for oil, it is the most straight-
forward substitute for imported oil.
The available quanitites of oil from shale are very
large. The entire Green River formation contains an
estimated 600 billion recoverable barrels of shale oil
in deposits of a richness of 25 gallons per ton of shale
-18-
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Table I
Percentages of Products from a Typical Rocky Mountain Refinery^"
From From
Wyoming Sweet Hydrotreated Shale Oil
Gasoline
52.4%
55.3%
Diesel/Jet
33.5
39.1
High Sulfur Fuel Oil
3.8
-
Low Sulfur Fuel Oil
8.7
3.5
LPG
1.7
2.5
Processing (Loss) Gain
(0.1)
(0.4)
100.0%
100.0%
iBased on Tosco in-house analysis.
-19-
-------
or higher. While recovery of all of this oil will re-
quire further refinement of the technology, 130 billion
barrels in deposits averaging at least 30 gallons per ton
in mining horizons of 30 feet or more can be recovered
using existing technology.1 The currently recoverable oil
from shale exceeds by more than four times the current
United States proven reserves of crude oil.
Clearly, limits exist on the rate at which these
very large reserves may be produced. Using present tech-
nology within the bounds of sound environmental practices
and water availability without reduction in use by other
water users, the maximum production rate is generally
thought to be in the neighborhood of one million B/D.
While some industry sources think twice that level of pro-
duction is feasible, most agree that technological advances
in the course of a decade following initial commercial
production are likely to permit substantially greater
future production rates than those now projected.
While one million B/D or even two will not replace
all imported oil, currently between eight and nine million
B/D, it can make a major difference as part of an effective
program of conservation, solar, and increased traditional
and new fossil energy production. Oil shale production
at the level of one million B/D would represent a new domestic
source of premium quality oil equivalent to half of that
from Alaska on a continuing basis well into the next
century.
^National Petroleum Council estimate.
-20-
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Proposed Oil Shale Projects
C-a — Gulf and Standard of Indiana
C-b — Occidental and Tenneco
U-a U-b — Sohio, Phillips and Sun
-------
U.S. Oil reserves and potentially recoverable shale oil
compared with Saudi Arabian reserves
(In billions of barrels)
600
165.7
28.5
Saudi Arabia
Proven oil
reserves
United States
proven oil
reserves
long-range
recoverable
130
recoverable
by present
technology
United States
oil shale reserves
Source: Energy Information Administration, Cameron Engineers
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STATE HIGHWAY
Location of Proposed Oil Shale
Projects in Northwestern Colorado
Approximate distances indicated between towns and protects
Colony: Tosco and ARCO
C-a —¦ Gulf and Standard of Indiana
C-b — Occidental and Tenneco
U-a U-b — Sohio, Phillips and Sun
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Shale oil would directly replace declining domestic
production of crude oil, or if that decline is slowed
enough, displace imports. In addition, it would provide
a national security "credibility" factor far in excess of
actual production rates, because of its stable production
cost and very large production potential. Saudi Arabia
now exercises an influence in OPEC pricing disproportionate
to its production rate because it alone has large unused
marginal production capacity. Oil shale can play a similar
role for the United States.
Status of the Technology
Unlike any other source of unconventional liquid fuels,
shale oil production by the TOSCO II process is economically
competitive today, field-ready now, and able to move into
viable commercial production with no further research and
development.
The TOSCO II retorting process entered the pilot stage
more than twenty years ago and was scaled up to "semi-works"
(semi-commercial) scale nearly fifteen years ago. The
TOSCO II process will be used in the commercial development
of the Colony Project, a joint venture between Atlantic
Richfield (60%) and Tosco (40%).
The Colony Project has its own privately owned shale
reserve, detailed engineering plans, and a definitive cost
estimate based on these plans, an approved Environmental
Impact Statement, and all but one remaining significant
permit granted for a commercial scale (47,000 B/D) shale
oil project.
-24-
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Commercial development of oil shale is being pursued
by a number of companies. The major technologies for
retorting shale oil fall into two categories; surface
retorting and modified in situ. The surface retorting
process involves three major steps: first, conventional
underground mining; second, crushing of the shale rock after
it has been mined and brought to the surface; and third,
heating of the crushed rock to 900° F. in surface retorts
to vaporize and release the hydrocarbons. The vaporized
hydrocarbons are then upgraded at the site and, upon com-
pletion of the process, are ready for the conventional
refining process.
There are several different surface retorting technolo-
gies in active development. These differ primarily in terms
of the method of feeding the crushed rock into the retort-
ing chamber, the type of retorting chamber used, and the
mechanisms for achieving even, rapid distribution of the
heat to maximize the efficiency of recovery. The major
surface retorting technologies are the TOSCO II process,
the Union B process, the Paraho process, and the Superior
multi-mineral recovery technology. (see diagrams 1-2 and
the diagram in the back pocket).
The pure in situ method, which involves no mining, has
been extensively studied and is considered impractical. In
the modified in situ process, a working space is mined out
in the shale bearing formation and large columns of the
rock are rubblized in place by explosion. The rubblized
zones are then ignited and the burning shale operates as an
underground retort, vaporizing the trapped hydrocarbons.
The shale oil vapors are then gathered at the surface where
they are further retorted and upgraded. Occidental's process
is the best known modified in situ process and the one
being most actively developed (see diagram 3).
-25-
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There are presently a number of oil shale projects in
various stages of development in Colorado and Utah using
either surface retorting technology, in situ, or a combi-
nation of the two, depending on the nature of the resource.
The in situ technology is regarded as a promising secondary
recovery technique in combination with surface retorting
technology.
Roughly 90% of the resource is owned by the federal
government. Two federal tracts in Colorado and two in Utah
were put up for bid and leased for development under the
Federal Prototype Oil Shale Leasing Program. Although
two tracts were also offered for bid in Wyoming, due to the
leanness of the oil shale there, there were no bidders. In
addition to the two federal test lease tracts in Colorado
and Utah, there are also a number of developments in progress
on privately owned land or state leases.
In Colorado, test lease Tract Cb is being developed by
Occidental Petroleum and Tenneco. The lease was by a direct
venture of Ashland, Arco, Shell, and Tosco for a bonus bid
of $117.8 million. The original participants withdrew for
a variety of reasons after considerable resource analysis
and environmental monitoring work. Occidental is now at
work on a pilot project on tract Cb using its own proprie-
tary modified in situ technology. Tract Cb is located north-
west of Rifle toward the center of the Piceance Basin. The
closest town is Meeker (see map). Occidental is also develop-
ing a second project on its own privately owned land south
of tract Cb.
Tract Ca is being developed by Rio Blanco Oil Shale
Company, a joint venture of Gulf Oil and Standard Oil of
Indiana. Rio Blanco plans to use both a surface retorting
and an in situ recovery technology in combination. Rio
-26-
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Blanco is under license to use the TOSCO II surface retort-
ing process and is working on the development of its own
version of modified in situ technology. Rio Blanco acquired
the lease in 1974 for a bonus bid of $210.3 million. The
project is in the resource analysis, environmental monitor-
ing and analysis, and development planning phase. Tract Ca
is located northwest of Tract Cb, near the town of Rangeley
(see map).
The Colony Project, a joint venture of ARCO and Tosco,
is located on a privately owned tract north of Grand Valley
and south of both federal test lease tracts (see map). The
Colony Project has completed its pilot operation and plans to
proceed to a commercial scale 47,000 B/D facility using the
TOSCO II process, if effective legislation is enacted by
the Congress. The TOSCO II process utilizes hot ceramic
balls to heat the crushed shale in a rotating kiln (see
diagram in pocket of back cover).
Union Oil Company, which has been involved in the oil
shale industry for more than 50 years, is developing its own
privately owned tract adjacent to the Colony Project (see map).
The Union "B" surface retort uses externally heated gas to
heat the shale. A reciprocating rock pump forces crushed
shale in from the bottom. Gas and oil leave the bottom of
the retort; retorted shale overflows the top. The Union pro-
cess is widely regarded as practical and commercially ready
(see diagram 1).
Paraho Development Corporation is a joint venture par-
ticipated in by seventeen oil companies for the purpose of
further developing a surface retorting technology originally
pioneered by the School of Mines. Paraho has operated three
retorts on lands leased from the U.S. Naval Oil Shale Reserves
-27-
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near Rifle, Colorado (see map). The Paraho retort is a
continuous vertical kiln. It can be operated by direct
combustion within the retort (direct mode) or by external
heating of the recycled gases (indirect mode) (see diagram 2).
The Superior Oil Company owns 6,500 acres of oil shale
land located on the northern edge of Colorado's Piceance
Creek basin (see map). Superior's technology, an indirect
hot gas process, is designed for multiple recovery of shale
oil, nahcolite, and dawsonite, two minerals which are unusually
plentiful on the Superior reserves. Superior believes that
its process, which produces four products, is practical and
financially flexible.
In Utah, Federal Lease Tracts Ua and Ub are being jointly
developed by the White River Shale Project. The lease to
Tract ua was originally awarded to Phillips Petroleum Com-
pany and Sun Oil Company (now Sunoco Energy Development Com-
pany) in 1974 for a bonus bid of $76.6 million. The White
River Shale Corporation was formed when Sohio Petroleum
Company joined the venture and the group was awarded the
lease as Tract Ub in 1974 for a bonus bid of $45.1 million.
White River's two-year Environmental Baseline Monitoring
Program included monitoring and analysis of surface water,
groundwater, geology and soils, air guality, biological
resources, and other studies.
After completing extensive conceptual engineering studies
White River filed a Detailed Development Plan with the federal
government in 1976 outlining plans for development of the
tracts; The lease is currently in suspension at the request
of White River pending resolution of problems related to the
-28-
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Union B Retort
j^Raw Shale Feed
Retorted Shale to Disposal
Retort Make Gas To Gas Treating
Rundown Oil Product
Rock Pump
QQQQQQQQQQ
Diagram 1
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Paraho Reactor
Raw Shale
I
Shale Distribution
Preheating & Mist Formation
Pyrolysis
Stripping & Water Gas Shift
Partial Combustion
Combustion
Cooling
Moving Grate
4^
Retorted Shale to Disposal
Product Gas & Vapors
Gas/Air
Gas/Air
Gas/Air
Shale Moved through Grate
Diagram 2
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Occidental Modified In Situ Process
Q, a/yfi%
0jjo&i
bOi°
mmm
Drill/Air Distribution
Sill Pillar
Decarbonized Zone
Combustion Zone
1400°-1600°
Retort Zone
900°
Broken Oil Shale
To Stack
Oil to Storage
Diagram 3
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ultimate disposition of the title to the tracts and other
complications. ^
A state lease, the Sand Wash Project, in northeastern
Utah, is being developed by Tosco Corporation. The Sand
Wash project is currently completing the resource analysis
and environmental monitoring phase and will begin prepara-
tion of the EIS and permit applications in 1980. The project
will use the TOSCO II technology and much of the plant
design, environmental and socioeconomic work carried out
for the Colony project.
The first step in the development of an oil shale pro-
ject is the analysis of the resource to determine the thick-
ness of the shale, the depth and location of the deposit,
the extent and location of underground water and other
factors. The choice of a technology is based in large part
on the characteristics of the reserve. Extensive environ-
mental monitoring is often carried out. After detailed
plant design and cost projections for a commercial plant
have been carried out, the environmental impact statement
(EIS) can be prepared. During the preparation and approval
of the EIS, the dozens of other state and federal permit
applications can be made for a commercial plant.
All the projects in Colorado and Utah are in various
stages of this development process. The test lease tracts
are generally in the resource analysis and environmental
monitoring phase. Tract Cb is in the pilot plant phase as
are several other projects. No projects is in .commercial
production.
^"Cameron Enginners, Inc. Oil Shale Status Report, August, 1979.
-32-
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The Colony Project is the only project which has com-
pleted its pilot plant operation and testing, and has a
completed and approved EIS, all but one of its major per-
mits in hand, and its community development and socioeco-
nomic impact mitigation planning completed for a commercial
plant. If effective legislation were to pass, the project
could move forward to commercial production immediately.
Roughly four years would be required for construction of a
commercial plant.
The length of time required to prepare for commercial
development including resource analysis, environmental mon-
itoring, design work, pilot operations, commercial plant
design, permit applications, EIS preparation and approval,
and development of the financing package is sufficiently
extensive, and the program sufficiently complex and costly
that only a few projects are ready for commercialization.
A so-called "crash program" would not occur regardless
of the magnitude of the federal incentives enacted. Under
a practical and effective incentive program, it is likely
that several of the most advanced projects would be able to
move forward to commercial production. To the extent that
i.t did not occur naturally, construction of these could be
phased to minimize the peaks and valleys of population influx
and other impacts.
Cost
The detailed plans and definitive estimates for the
Colony Project are not rough preliminary estimates, but
careful and thorough engineering estimates performed at
a cost of $12 million by two world-scale contractors.
-33-
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This estimate is used in the recent Rand Corporation study
of cost estimate escalation in "synfuel" projects as an
example of a mature and reliable estimate, in contrast
with less reliable and probably understated numbers for
untried and less developed processes. The estimate was
completed in 1974 and is now in the process of being up-
dated to take normal inflation into account.
Using the currently projected, updated costs, the
investment cost for the Colony Project is about $25,000
per "daily barrel" of shale oil production capacity. Based
on published oil industry statistics, the 1978 cost of
finding and developing conventional oil and gas was about
$27,000 per daily barrel, significantly more than the
current estimated cost of oil shale production from the
Colony Project.^"
Subject to the updating now in progress, it appears
that upgraded shale oil from this proposed plant can sell
at around $25/B, returning all capital, operating and
financial costs, and yielding.about a 15% discounted cash
flow rate of return on an all equity basis. This is well
within current prices, since comparable quality Wyoming
sweet crudes are now selling at $28.50/B.
While conventional oil and gas exploration should con-
tinue to be affected by general inflation, it is likely that
such inflation will be offset or more than offset in second-
generation shale oil plants by efficiencies resulting from
technological advance. Thus shale oil can play a stabilizing
role in energy pricing.
•'•Tosco in-house analysis based on industry and Department of
Energy data published in Oil Daily, June 11, 1979.
-34-
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Other sources of liquid fuels, such as coal liquefaction,
should also be pursued. Gasoline and other fuels from coal
are now being produced in South Africa's SASOL plant. Ex-
panded production levels are projected both from SASOL II,
now under construction, and the proposed SASOL III. While
there is no doubt of the workability of the process, costs
are high. The U.S. contractor now building SASOL II esti-
mates that gasoline from a comparable plant in the U.S. West
would require a price of over $60/B. Nevertheless, even
this cost may well seem cheap by the time such a plant is
built. Other coal liquefaction processes are in pilot or
pre-prototype stages, and work on these should be pursued.
These facts demonstrate that we cannot afford not to
pursue commercial-scale development of shale oil. It is
commercially ready and competitive with conventional sources,
and highly competitive with other unconventional sources.
It is a secure domestic supply. It is a source of urgently
needed transportation fuels which are the least amenable
to conservation or replacement by solar, and it is the most
direct replacement for imported foreign oil.
-3 5-
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Estimated cost of shale oil compared with estimated
cost of coal liquefaction arid coal gasification.
SHALE OIL1
$25 per barrel
COAL LIQUIDS (DIRECT)2
$36 per barrel
COAL LIQUIDS (INDIRECT)2
$37 per barrel
OIL SANDS2
$31 per barrel
COAL GAS2
$40 per barrel
1 TOSCO estimate.
2 Cameron Engineers, Testimony to the Senate Budget Committee Task Force on
Synthetic Fuels, September 5,1979.
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VJcS^NUTV NA0N\T*atH£
TV
Ho^xqwaI • -';/, ~~
-------
Figure 1, Locations of Potential Oil Shale Developments -
Piceance Basin, Colorado
-------
MB
-------
** FACT SHEET **
C-b History and Today's Project
• April 1, 1974 Colorado B Tract (C-b) was leased for
$117,778,000.36
t original participating companies were Atlantic Richfield,
Ashland Oil, Shell Oil and The Oil Shale Corporation
• November 2, 1976 Shell Oil Company, following Atlantic
Richfield and the Oil Shale Corporation, withdrew from
the C-b lease, ARCO and TOSCO having withdrawn in 1975
• November 3, 1976 Ashland Colorado, Inc., lessee, and
Occidental Oil Shale, Inc., operator, entered into an
agreement using Oxy's Modified In Situ process
• Occidental acquired a 100% interest when Ashland with-
drew effective February 14, 1979
o the Green River formation of Northern Colorado, North-
western Utah and Southwest Wyoming are estimated to
contain close to 2 trillion barrels of oil
• the C-b Tract contains approximately 5,100 acres
• an estimated 3.7 billion barrels of oil are contained
in this Tract
• Occidental Oil Shale, Inc. plans a recovery of about
1.2 billion barrels of oil from the shale to be
initially mined
e over 50 years production life expected
» current C-b project schedule is estimated to be:
Sept. 1977 - mobilization and start of site preparation
Jan. 1979 - began shaft sinking
Mar. 1983 - began construction of initial retorts
May 1984 - ignition of initial retorts
-------
** FACT SHEET **
Description of Modified In Situ (In Place) Retorting
t modified in situ method of retorting is completely
underground
• retorts are created by initially mining out enough
shale to provide a suitable void into which the
remaining rock is blasted
• remaining shale is rubblized by blasting
• provides permeability for gas flow during operation
• in situ retorts consist of groups or "clusters"
• eight 155' x 310' x 390' retorts make one cluster
(subject to design change)
e processing of a cluster of retorts consists of several
steps
- a retort within a cluster is ignited from the top
by externally fueled burners
- when the temperature at the top of the retort is
sufficient to sustain combustion, burners are shut
off
- a regulated mixture of air and steam is drawn into
the top and then down through the retort
- hot combustion gases flow down through the retort
- these supply heat to the unretorted shale below
- at 900°F organic material or kerogen decomposes into
oil vapor and gas
- other gases are carried along with the combustion gases
- steam in the air fed to the retort acts as a dilutant
to the oxygen in the air to control the reaction tem-
perature
-------
Description of Modified In Situ (In Place) Retorting (cont)
- in the combustion process, steam reacts to form
carbon monoxide and hydrogen to improve the heat-
ing value of the product gas
- some mineral carbonates in the shale are also
decomposed to carbon dioxide gas and mineral
oxides
- the hot gas mixture flowing down through the
retort preheats the raw shale
- at the same time, the oil and some of the water
vapor are condensed
- product liquids and gases are collected in the
bottom of the retort
- pumped to surface for separation and storage
- becoming product oil, produced fuel gas and
water
Oxy's Modified In Situ experience began at the
Logan Hash operation in 1972
- some 50,000 barrels of oil have been produced at
Logan Wash
- private investment of 50 million dollars has been
made in Logan Wash Operation
-------
RETORT 6
SIMPLE RETORTING PRINCIPLES
-------
ep* fc.sznt
ENVIRONMENTAL CONCERNS REGARDING OIL SHALE DEVELOPMENT
Mining and conversion of oil shale will degrade air quality,
will consume precious water resources, may degrade surface and/or
groundwater quality, will create solid and hazardous wastes to
be disposed of properly, and will create significant population
growth in a predominantly rural setting which translates into
potential social and economic problems. That these things will
occur is a given...the question is the magnitude and the signifi-
cance of the occurrence. Key questions such as the following
exist:
1. How much groundwater will be intercepted during mining?
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?
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 (nearest Class I area)?
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 as effective?
10. What is the expected population growth associated with the
development of an oil shale industry?
Answers to the above questions (and perhaps other questions not
yet posed) will in part determine the ability of individual plants
and of an oil shale industry to be compatible with the desired
environment for oil shale country.
Answers to some of the above questions may be partially answered
by theoretical research work and limited-scope field investigations
in the absence of any oil shale facilities. Answers to the
remaining questions will necessarily be developed through rigorous
testing programs and data analyses performed on facilities represen-
tative of commercial size.
Much has been said and written about the environmental advan-
tages and disadvantages of in-situ development vs. surface
retorting technology. Without hard data from operating facilities
it is difficult to reach firm conclusions. However, surface retorting
appears to have slightly greater air emissions and has more of a
solid waste-processed shale disposal problem compared to in-situ.
On the other hand in-situ development poses greater risks to ground-
water movement and quality than does surface retorting. Firm data
are desirable prior to the launching of a large industry.
-------
T
EPA Regulatory Actions Affecting Oil Shale
Environmental regulatory actions which we have taken include -
EIS Reviews
o Prototype Oil Shale Leasing Program (D and F)
o Colony (D and F)
o Superior (D)
PSD Permits Issued
o C-a 1000
o C-b 5000
o Colony 50,000
o Union 9000
o Occidental 1000
BPD 12-15-77
BPD 12-15-77
BPD 7-11-78
BPD 7-31-79
BPD 11-1-79
NPDES Permits Issued
o C-a dewatering phase
o C-b dewatering phase
o Occidental experimental facility
Future regulatory involvement will include -
RCRA Permits
Final regulations scheduled for April 1980 may impose requirements
applicable to processed shale.
UIC Permits
Reinjection of produced water will be subject to the requirements
as a Class III well. Final regulations are scheduled for April 1980.
In the absence of air NSPS, water effluent guidelines, and solid waste
disposal performance standards the Region has been using test engineering
judgment. The Agency through the lead of ORD is preparing a series-of oil
shale documents which will provide "early guidance" on control technology
expectations, monitoring methodologies, and impact assessment. The EMB
Task Force - Alternative Fuels Group is responsible for the development
and implementation of a regulatory and research strategy.
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HIGHLIGHTS OF THE REGION VIII ENERGY POLICY
STATEMENT AFFECTING OIL SHALE DEVELOPMENT
The Region VIII Draft Energy Policy Statement was developed in
response to the President's Energy Message. The statement conveys
the Region's intent to practice responsive government by providing
priority expedited reviews of energy facilities. The statement also
reiterates the region's commitment to the protection of its exceeding
high quality environment. We believe that energy resource development
and environmental protection can be compatible in most situations.
The Energy Policy Statement affects the development of oil shale
in the following ways . . .
1. Expedited permit processing
The Region has committed to the processing of oil shale permit
applications within six months of receipt of a completed
application.
2. Grandfathering
The Region hopes that it will not be necessary to grandfather
oil shale facilities from future substantive requirements.
However, it is recognized that the EMB will probably have
authority on a case-by-case basis to waive future requirements
for existing facilities. EPA is pledging its full support to
work with EMB on these case-by-base determinations.
3. Role of Development
The Region favors "orderly phased development" rather than
"crash commercialization of an industry". Some technologies may
be in a position to be scaled to commercial size; others must be
further developed at the modular scale. Minimization of tech-
nological failures, economic white elephants, environmental
disastors, and socio-economic disruptions are benefits of this
approach. Mostjof the industry plan to proceed in this manner.
RMOGA endorses this approach. The chances of meeting the
President's shale oil production goal improve with this approach.
4. Better than BACT
Since it appears that the PSD air quality increments may serve as
the limiting constraint to the size of an oil shale industry,
we encourage initial oil shale developers to go beyond BACT in
their air pollution controls. It may be worth the incremental
cost to individual developers for the nation to realize the maximum
amount of oil production from the Piceance Basin given Class I
and Class II increments.
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5. Federal Government Coordination
EPA is pledged to work with DOE on oil shale research efforts
and with DOI on future leasing needs. EPA also actively
participates on the Oil Shale Environmental Advisory Panel.
6. Information/Communication
. Through the FRC, we are assisting potential oil shale
"impact" communities with planning and financial (through
sewage treatment plant funding) support.
. Through the Energy Office, we are routinely communicating
and interpreting EPA policies, regulations and research
results to the oil shale industry.
. The Region will conduct an Energy Industry Seminar to help
explain EPA's permit policies, procedures and requirements.
Items 2, 3, and 4 have received considerable attention from
the oil shale industry, Congressman Dingell and 0MB via comments on
the Energy Policy Statement. The proposed Dingell and Cutler
responses are attached.
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SotVxxtft SVjva
Press Conference
Anticipated Questions and Answers
1. What is EPA1s viewpoint on oil shale development?
We recognize that a tremendous energy resource potential exists
in shale. The oil shale areas of Colorado, Utah, and Wyoming contain
an estimated 700 billion barrels of oil - more than proven Middle
East reserves. With the escalation world price ofoil and the
growing uncertainty of a reliable supply of oil it appears that oil
shale companies are about ready to proceed with development. The
President has established a production goal for shale oil of 400,000
BPD by 1990. EPA has fully supported the goals of the Federal Prototype
Program. It now appears that development on private lands may occur
in parallel with the Federal program. Our hope is that development
will proceed at such a pace to allow knowledgeable decisions to be made
regarding future leasing for "second generation" facilities.
2. Does EPA endorse additional Federal leasing?
The Prototype Program administered by D0I envisioned fulfillment
of the objectives of the Program prior to any additional leasing.
There appears to be mounting pressure to deviate from that stance.
We no not believe that additional leasing is required to meet the
President's 400,000 BPD goal. Therefore, any additional leasing in
the near future should be aimed toward specific mining or processing
technology development which is not being developed privately,
through DOE, or through D0I. Knowledgeable decisions on the "best"
ways to maximize resource recovery and to minimize environmental
degradation from future projects could then be made.
3. What are EPA's primary environmental concerns regarding oil shale development;
o Surface retorting of oil shale produces vast amounts—up to 20
million tons per year for a 50,000 BPD facility—of processed shale.
This material must be disposed of in a manner which will not allow
migration of water through the pile, leaching various inorganics
and organics, and subsequent entry into the ground water system.
Processed shale must also be covered with soil like material and
successfully revegetated in order to prevent surface runoff containing
high concentrations of total dissolved solids.
o In situ retorting poses some questions yet unanswered about the
ability to prevent groundwater quality degradation.
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2.
3. (continued)
o Air emissions from any oil shale facility will contribute toward
consumption of the PSD increments. It appears that the Class I
increments at Flat Tops Wilderness Area may prove to be the limiting
constraint to the size of an oil shale industry. Class II increments
will govern how closely facilities may be spaced but do not appear
to be a constraint for any individual facility. EPA issued a PSD
permit to Colony for its 50,000 BPD operation.
4. The oil shale industry is concerned with the accuracy of air quality
models applied to the complex terrain of oil shale country. What is
EPA doing to refine existing models?
We recognize the need for an accurate regional complex terrain
model which can assess the impacts of several oil shale facilities in
combination with impacts from the associated population growth. EPA
plans an initial modest field effort in 1980 and hopes to conduct an
intensive effort in 1981. Data obtained from these efforts will serve
to refine(if necessary) and validate models which can accurately assess
impacts on Flat Tops Wilderness Area. This effort should be a joint
effort among the industry, DOE, D0I, and the States of Colorado and
Utah. Preliminary planning is underway. Additional funding will be
necessary.
5. Is there enough water available for oil shale development?
A recent intensive study performed by the Colorado Department of
Natural Resources for the U.S. Water Resources Council concluded that
there were sufficient surface water resources available to support the
consumptive demands of a 1.3 million BPD oil shale industry and its
associated growth. Several assumptions and conditions affect this
conclusion. First, while water may be physically available, reservoirs
and conveyance facilities would have to be built in order to provide year
round needs. Second, instream needs for recreational and aquatic uses
may be compromised. Additional study on this issue is necessary.
Finally, additional consumption in the Upper Colorado Basin while legal
will impact on downstream - Lower Basin - present users who may have
very junior water rights.
6. What impact will the UIC program have on the development of in situ oil
shale projects?
In situ oil shale retorts are classified as special process wells
(Class III). There is concern about the potential for movement of
contaminants out of the burned retorts as mining is completed and water
is allowed to return to the site. There is, also, concern about potential
quality modifications in the aquifer outside of the mined area from
reinjection of water removed from the mine area. The main thrust of the
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6. (continued)
UIC permit program is for monitoring and reporting to insure that toxic
materials do not migrate off site via the ground water.
The Agency feels that the UIC regulations will be flexible
enough to allow development of in situ oil shale while providing
adequate protection of the ground water.
7. What is the status of the proposed UIC regulations?
The Agency anticipates finalizing both the consolidated permit
regulations (which contain UIC permit regulations) and the technical
UIC program requirements (CFR 146) this coming spring.
8. Will EPA be issuing UIC permits for in situ oil shale projects in Colorado?
The UIC program is intended to be a State run program. The State
must establish a program for control of all underground injection activities
which meet the minimum requirements established by the UIC regulations.
The States of Colorado and Utah have already indicated their intention
to assume primacy for the UIC program and have accepted EPA grants to
enable them to develop their programs. It is anticipated that both
states will be in a position to achieve primacy within the required time
frame. EPA will only be involved in an oversight and assistance role.
A point of fact is that the State of Colorado Health Department Water
Quality Control Commission is presently issuing permits for in situ oil
shale projects under their existing Subsurface Disposal Regulations.
9. What is the potential impact of the proposed UIC regulations on the
existing production of oil and gas in this area?
There may be limited impact depending on the age of existing fields
and the extent of the state regulations at the time many of the wells
were drilled. Reworking of some wells may be required before they could
be repermitted.
10. Will the UIC program slow down development of new oil and gas fields?
It is not anticipated that new oil and gas field development will
be slowed by the need for a permit to inject produced water. The
necessary information and resulting permits could be developed concurrent
with development of the fields. In addition, the existing drilling and
completion technology are such that the permitting agency will not have
to require additional data collection.
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11. Will EPA1s sole source aquifer program impact the program for
syn fuel development?
There is a potential for impact on the syn fuel program if there
is federal financial assistance to a particular project. At this time
there have been no designations of sole source aquifers in Region VIII.
The Region does designate such aquifers. A memorandum of understanding
would be developed with DOE outlining the procedure for review of
assisted energy projects. If a project was reviewed and was found to
pose a threat, mitigation measures would be required before federal
assistance would be approved.
12. What is EPA's view of the adequacy of the Prototype Program?
The Program has established a sound mechanism which may provide
answers to (1) the technological and economic feasibility of extraction
and conversion of the oil shale resource, and (2) the environmental
impacts from a commercial operation. The program needs to be carried
out as outlined in the EIS and as further described in the DDPs.
13. Are local communities ready for oil shale development?
The potentially impacted communities have voiced support of the
C-a and C-b development at the public hearingg held in Rangely and Meeker.
The feeling is that the companies have worked closely with town and
county officials to insure that adequate schools, medical facilities,
recreational facilities, etc., are provided in a timely fashion.
14. What are the EPA responsibilities in water?, in air? , and other?
Water: EPA administers the NPDES program. Colorado issues permits;
EPA issues permits in Utah. EPA also issues effluent guidelines and NSPS
for effluents from processing and mining activities.
Air: EPA grants permits to construct and operate under the prevention
of significant deterioration regulations. EPA promulgates NSPS and NESHAPS.
15. What ancillary facilities are required for oil shale development?
Power Plants: Power generating capacity is needed for the TOSCO
type plants. 150 to 200 MW are needed for 50,000
BPD.
Water: If ground water is not used, a dam and reservoir may
be the source for storage water.
Loading: By-products distribution via rail or pipeline will
require terminals. Products pipelines will be necessary.
Other Off-site: Transmission lines and roads.
Communities: Services for an expanded community must be provided.
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16. Is technology adequate to develop the oil shale resource?
This is what the Prototype Program is all about. Only pilot scale
operations have been conducted in the U.S. Larger applications are
existent in other countries but different shales exist.
17. Is reclamation of spent shale possible?
Again, the Prototype Program is designed to provide the answers.
However, even with that Program the success of processed shale
revegetation will not be proven for many years. Key concerns are
amount of soil cover, species variety, and prevention of upward salt
migration.
18. What impact will regulations under RCRA have on the oil shale
industry especially regarding the disposal of processed shale?
Final regulations will be out this Spring. EPA has not yet made
a final determination on how to categorize processed shale. It may be
similar to some other high volume special wastes. Data on representative
processed shale for all processes are necessary to determine the "degree
of hazard" of the waste.
19. What is the total cost of environmental controls as applied to an oil
shale facility?
Since there is limited environmental data available upon which
to prescribe applicable control technology standards this cost estimate
is difficult to make. This is one of the objectives of EPA in our
Oil Shale Guidance Document to be released in 1981. An estimate of
environmental control costs made by Denver Research Institute for DOE
concluded that capital costs for control equipment sould be 5 to 10
percent of the total plant cost. Annualized per barrel costs would
range from 1 to 2 dollars per barrel depending upon the process.
At a $30 per barrel world market price the environmental control cost
appears to be minimal.
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