&EPA
United States
Environmental Protection
Agency
Industrial Environmental Research EPA-600/7-79-075
Laboratory March 1979
Cincinnati OH 45268
Research and Development
Technological
Overview
Reports for Eight
Shale Oil Recovery
Processes
Interagency
Energy/Environment
R&D Program
Report
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-79-075
March 1979
TECHNOLOGICAL OVERVIEW REPORTS
FOR EIGHT SHALE OIL RECOVERY PROCESSES
by
C. C. Shih and J. E. Cotter
TRW Environmental Engineering Division
Redondo Beach, California 90278
and
C. H. Prien and T. D. Nevens
Denver Research Institute
Denver, Colorado 80210
Contract No. 68-02-1881
Project Officer
Thomas 0. Powers III
Energy Systems Environmental Control Division
Industrial Environmental Research Laboratory
Cincinnati, Ohio 45268
INDUSTRIAL ENVIRONMENTAL RESEARCH LABORATORY
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
CINCINNATI, OHIO 45268
-------
DISCLAIMER
This report has been reviewed by the Industrial Environmental Research
Laboratory, U.S. Environmental Protection Agency, Cincinnati, Ohio, and ap-
proved for publication. Approval does not signify that the contents neces-
sarily reflect the views and policies of the U.S. Environmental Protection
Agency, nor does mention of trade names or commercial products constitute
endorsement or recommendations for use.
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FOREWORD
When energy and material resources are extracted, processed, converted,
and used, the related pollutional impacts on our environment and even on our
health often require that new and increasingly more efficient pollution con-
trol methods be used. The Industrial Environmental Research Laboratory - Cin-
cinnati (lERL-Ci) assists in developing and demonstrating new and improved
methodologies that will meet these needs both efficiently and economically.
An analysis of environmental impacts begins with describing potential
pollutant sources for a variety of physical settings. For shale oil develop-
ment, this effort has resulted in up-to-date descriptions of the leading shale
processing technologies, which are compiled and presented in this document.
It is anticipated that some of these processes will be used to provide shale
oil for energy or petrochemical needs in the not-too-distant future. The over-
views can serve users as a solid basis for additional studies or as information
sources leading to an awareness of what is involved in shale oil processing.
Further information on the environmental aspects of shale oil processing can
be obtained from the lERL-Cincinnati Fuels Technology Branch.
David G. Stephan
Director
Industrial Environmental Research Laboratory
Cincinnati
iii
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ABSTRACT
This report, "Technological Overview Reports for Eight Oil Shale Recovery
Processes," has been prepared to assist research workers by providing up-to-
date descriptions of processes at the forefront of shale oil development. The
purpose of the document is to supply background information to aid in the
evaluation of environmental impacts and pollution control technologies in con-
nection with oil shale development. In order to be included in the report,
processes for shale oil production had to be able to meet certain criteria
indicating commercial promise. All of the reported processes have been tested
on a sufficient pilot scale (0.1-0.5 m3/day oil production) to permit an eval-
uation of their operating characteristics and yields. Six surface retorting
processes were selected for characterization: (1) Union Oil Retort B, (2)
Paraho, (3) TOSCO II, (4) Lurgi Ruhrgas, (5) Superior Oil, and (6) USBM Gas
Combustion. In addition, two in-situ retorting processes were selected: the
Occidental modified in-situ retort, and the true in-situ development programs
of Laramie Energy Technology Center (Department of Energy, DOE).
Each of the overview reports contains information on general process des-
cription, shale preparation requirements, equipment types, operating conditions
(e.g., temperature, feed rate), physical and chemical characteristics of pro-
cess products and by-products, energy and water requirements, process stream
characteristics, retorted shale disposal requirements, and site-specific
aspects.
This report was submitted in partial fulfillment of Contract 68-02-1881
by TRW Environmental Engineering Division under the sponsorship of the U.S.
Environmental Protection Agency. Work was subcontracted to Denver Research
Institute.
IV
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CONTENTS
FOREWORD 111
ABSTRACT iv
FIGURES vi
TABLES viii
INTRODUCTION 1
UNION OIL SHALE RETORTING PROCESS 5
PARAHO OIL SHALE PROCESS 17
TOSCO II OIL SHALE PROCESS 37
THE LURGI-RUHRGAS PROCESS FOR OIL SHALE RETORTING 55
SUPERIOR OIL SHALE PROCESS 63
USBM GAS COMBUSTION PROCESS 75
OCCIDENTAL MODIFIED IN-SITU PROCESS 87
,LETC/DOE IN-SITU OIL SHALE RESEARCH PROGRAM 99
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FIGURES
1 Union Oil Shale Fee Property in Piceance Creek Basin, Colorado . . 6
2 Union Retort B 10
3 Union Retort B Flow Diagram 11
4 Block Flow Diagram for Union Oil Retort B Prototype Plant .... 12
5A Flow Diagram for Retort System in Union Oil Retort B Prototype
Plant 13
5B Flow Diagram for Shale Oil Processing in Union Oil Retort B
Prototype Plant 14
5C Flow Diagram for Fuel Gas Process and Water Treatment in Union Oil
Retort B Prototype Plant 15
6 The Paraho Retort 19
7 Paraho Direct Mode Flow Diagram 20
8 Temperature Profile in Paraho Direct Mode Retort 21
9 Paraho Indirect Mode Flow Diagram 23
10 Proposed Site Additions to Anvil Points Facilities 29
11 Block Flow Diagram of Proposed Paraho Modular Plant 30
12 Proposed Plan for Mine Extension 31
13 Area Setting of Proposed Action 38
*
14 Shale Oil Complex - Composite Aerial View 39
15 Room-and-Pillar Mining Concept 41
16 • Block Flow Diagram Retorting and Upgrading Units 43
17 Pyrolysis and Oil Recovery Unit TOSCO II Process 44
18 Gas Recovery and Treating Unit 46
vi
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19 Hydrogen Unit, Steam Reforming Process 47
20 Gas Oil Hydrogenation Unit 48
21 Naphtha Hydrogenation Unit 50
22 Delayed Coking Process 51
23 Ammonia Separation Unit 53
24 The Lurgi-Ruhrgas Process for the Retorting of Oil Shale 57
25 Structure Contour Map 64
26 Schematic Cross Section of the Parachute Creek Member Showing Three
Zones in Oil Shale 65
27 Typical Mine Panel Showing Spent Shale Return 66
28 Artist's Concept of Circular Grate Retort 68
29 Cross Section of Circular Grate Retort 69
30 Plan View of Circular Grate Retort Showing Movement of Charge thru
Various Zones 70
31 Conceptual Design Soda Ash Plant 73
32 Conceptual Process Flow Diagram 77
33 Gas Combustion Retort 78
34 USBM 150 ton/day Gas Combustion Retort 79
35 Flow Diagram of 150 TPD Modified Gas Combustion Retort and
Auxiliaries 81
36 Occidental Oil Shale Lease Property in Piceance Creek Basin,
Colorado 88
37 Retorting Operation of the Occidental Modified In-Situ Process . . 89
38 Occidental's Proposed Commercial Scale In-Situ Mining Scheme ... 91
39 Two Level Mining for Commercial Size Retort 92
40 Flame Front Movement in the Occidental Modified In-Situ Process. . 94
41 LERC In-Situ Sites, Sect. 15, T 18 N, R 106 W, Rock Springs, Wyo.. 102
42 Well Pattern for In-Situ Site 9 104
43 Location of LERC Field Studies, Sweetwater County, Wyo 106
vi 1
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TABLES
1 Paraho Shale Oil Properties 25
2 Paraho Retort Gas Properties 26
3 Physical Properties of Paraho Direct Mode Processed Shale 27
4 Paraho Retort Water Analysis 34
5 Water Requirements for a .59,000 m3/Day (100,000 BPD) Paraho Shale
Oil Plant 36
6 Properties of Oil Shale Retorting Products 59
7 Selected Demonstration Run Results Modified Gas Combustion Process. 82
8 Analysis of Gas Combustion Retort Water 84
9 Properties of Shale Oil from Modified Gas Combustion Retort .... 85
10 Commercial Production of Shale Oil Based on Occidental Modified
In-Situ Process 93
11 Types of Research at LERC Rock Springs, Wyoming Sites 101
viii
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INTRODUCTION
The work plan for the EPA project "Assessment of Environmental Impacts
from Oil Shale Developments" identifies characterization of leading recovery
processes as a key element. An analysis of effluent and emission impacts
necessarily begins with the pollutant sources, as well as the variety of phy-
sical settings where shale oil recovery plants might be constructed. Accord-
ingly, a number of technology overview reports have been prepared by the staff
of TRW and Denver Research Institute, in order to assist in the evaluation of
environmental impacts and pollution, control technologies.
Since these overviews provide basic and up-to-date descriptions of pro-
cesses at the forefront of shale oil development, this information is compiled
and presented in this publication. This document will serve as input to the
final assessment report and, hopefully, will prove to be useful as an indivi-
dual reference.
Although several hundred different processes for retorting oil shale have
been proposed over the past 75 years, only a few have been sufficiently inves-
tigated to be considered viable for commercial development. In order to be
included in the current EPA evaluation it was felt that any present-day process
for shale oil production should be able to meet a majority of the following
criteria:
(a) The process has been tested on a sufficient pilot scale
(0.1-0.5 m3/day or 0.6-3 bbls/day oil production) to permit
an evaluation of its operating characteristics and yields.
(b) The data obtained to date have indicated that the process is
technically sound and is amenable to further scale-up to a
large pilot plant, semi»works plant, or single commercial
module.
(c) Process operation up to the present time has not indicated
any inherent adverse environmental emissions or effluents
which are considered to be incapable of eventual control.
(d) The process has operated successfully on United States oil
shales, particularly those of the Western Green River Forma-
tion.
(e) The preliminary economics of the process are sufficiently
promising for the future to warrant continued process develop-
ment.
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(f) There are some indications that construction of a commer-
cial module (1000 m3/stream day or 6000 bbls/day) will be
in progress before 1985.
(g) Some reasonable measure of cooperation could be secured
from a process developer in obtaining unpublished infor-
mation, descriptions of new process changes, etc.
Six surface retorting processes were selected for characterization on the
basis of the above criteria: (1) Union Oil Retort B, (2) Paraho, (3) TOSCO II,
(4) Lurgi-Ruhrgas, (5) Superior Oil, and (6) USBM Gas Combustion. In addition,
two in-situ retorting processes were selected: (1) the Occidental modified
in-situ retort, and (2) true in-situ development programs of Laramie Energy
Technology Center (DOE).
In, true in-situ processes, the oil shale zone is prepared by various
fracturing techniques to create permeability, and no mining is involved. This
is in contrast to the modified in-situ process, which involves underground
mining of 20 to 25% of the shale deposit (or barren rock above and/or below
the shale deposit), followed by explosive fracturing of the shale into the
void volume to create a chimney of rubblized shale. Retorting of the shale
can be carried out in either the vertical or horizontal direction, depending
on the thickness of the shale zone. The heat for retorting can be supplied by
combustion of the shale in place or by the injection of externally heated gases.
There is published information on each of the eight selected processes.
The available technical details vary considerably and it was determined that
individual contacts would be made with each of the developers to obtain the
latest information whenever possible. These contacts were in the form of con-
ferences with technical and management personnel at corporate offices, together
with laboratory and plant visits wherever permission could be secured. Finally,
unpublished report sources were consulted, to the extent available, as an in-
formation cross-check on the above, providing that the proprietary nature of
any data obtained was properly treated.
The process overview reports are not intended to provide in-depth analy-
sis, but to supply useful and accurate background information on recovery tech-
nologies. The reports attempt to include:
t general process description
• shale preparation requirements
• equipment types
• operating conditions (e.g., temperature, feed rate)
• Physical and chemical characteristics of process products
and by-products
• energy and water requirements
• process stream characteristics
-------
t retorted shale disposal requirements
0 site-specific aspects, wherever applicable
Each of the reports was submitted to the respective process developers
for review relative to accuracy and conformance to current planning. TRW and
the Denver Research Institute appreciate the helpful comments provided by many
developers.
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UNION OIL SHALE RETORTING PROCESS
C. C. Shih
The Union Oil Company of California (Union) has been involved in oil
shale activities for more than fifty years. During that time it has acquired
121 Mm2 (30,000 acres) of property located on the Parachute Creek, north of
Grand Valley, Colorado (Figure I)."1" The development of Union's oil shale re-
torting technology was initiated in the early 1940's, and several variations
of a vertical kiln retorting process, with upward flow of shale and counter-
current downward flow of gases and liquids, have been developed. Two varia-
tions are known as the Retort A and the Retort B. The first concept, the Re-
tort A process, has been carried through 1.81 tonnestt (2 tons) per day and
45.4 tonnes (50 tons) per day pilot plants. This was followed by the construc-
tion and operation of a large demonstration plant in the late 1950's. The
demonstration plant was designed for 317.5 tonnes (350 tons) per day capacity,
but long-term operability was demonstrated at rates of 635 to 907 tonnes (700
to 1,000 tons) per day, with a peak rate of 1,089 tonnes (1,200 tons) per day.
However, although the demonstration of the Retort A process was extensive and
successful, the Union Oil work, except for a continuing low activity research
effort, was suspended due to the plentiful supply of low-cost Middle East oil
and natural gas at the time. An improved version of the Union Oil process,
the Retort B process, was developed in subsequent work in response to the in-
creasing energy demands and shortage of fuel supplies, and has been carried
through pilot plant stage. It is the Retort B process that Union Oil now pro-
poses to construct and demonstrate at the 9,072 tonnes (10,000 tons) per day
rate along with all necessary auxiliary facilities.
UNDERGROUND MINING AND CRUSHING
Union Oil proposes to utilize the conventional room-and-pillar method for
production mining, with the mine portal designed to open on to a bench at the
2,100 m (7,000 ft) elevation. The rooms will be 18.3 m (60 ft) high by 18.3 m
(60 ft) wide and the pillars will have an 18.3 m (60 ft) square horizontal
section. The initial production mining will be at a rate of approximately
9,900 tonnes (10,900 tons) per stream day.
Both primary and secondary crushing of the shale ore will be done under-
ground. Primary crushing will reduce the size of the run-of-mine shale to
minus 20 cm (8 in), and secondary crushing will further reduce the shale size
A second fee property owned by Union Oil, also shown in Figure 1, consists
of 5,200 acres. This property is probably of minor importance in Union's
plans for commercial development.
tonne = 1,000 kg
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I R99W
—' ro ^,
9 s §
Rio B1anco\Count
GarfieTd~CoVnty
OCCIDENTAL
Garfleld County
Mesa County
95T
T PARAHO
7 (ANVIL
S POINTS)
Figure 1. Union Oil Shale Fee Property in Piceance Creek Basin, Colorado
-------
to minus 5 cm (2 in). The crusher product is divided into two fractions by
screening. Shale particle size in the 0.32 to 5.08 cm (1/8 to 2 in) range is
used for the retort feed. The less than 0.32 cm (1.8 in) fraction is rejected
and stockpiled in the mine. Dusts from the shale preparation plant will be
controlled by the use of'dust suppression systems and dust removal systems
such as bag filters.
RETORTING AND UPGRADING
In the Retort B process, shown in Figure 2, crushed oil shale in the 0.32
to 5.08 cm (1/8 to 2 in) size range flows through two feed chutes to the solids
pump. The solids pump consists of two piston and cylinder assemblies which
alternately feed shale to the retort, and is mounted on a movable carriage and
completely enclosed within the feeder housing and immersed in oil. As shale
is moved upward through the retort by the upstroke of the piston, it is met by
a stream of 510 to 538<>C (950 to 1000°F) recycle gas from the recycle gas
heater flowing downward. The rising oil shale bed is heated to retorting tem-
perature by countercurrent contact with the hot recycle gas, resulting in the
evolution of shale oil vapor and make gas. This mixture of shale oil vapor
and make gas is forced downward by the recycle gas, and cooled by contact with
the cold incoming shale in the lower section of the retort cone. In the dis-
engaging section surrounding the lower cone, the liquid level is controlled by
withdrawing the oil product, and the recycle and make gas are removed from the
space above the liquid level.
The flow diagrams for the Retort B process and for the Retort B prototype
plant are presented in Figures 3, 4, 5A, 5B, and 5C. As shown in Figures 3
and 5A, the make gas is first sent to a Venturi scrubber for cooling and heavy
ends removal by oil scrubbing. That portion of the 31.5 MJ/m3 (800 Btu/SCF)
make gas not recycled is then processed by compression and oil scrubbing to
remove additional naj^hajyadJigivy ends, followed by a Stretford unit to re.-
move^hydrogen j»uTfTde[Figure 5C). Th~e sweetened make gas is used "as" plant
fuel. The remaining gas, taken off after the venturi scrubber, is recycled
to the retort through the recycle gas heater to provide the heat for oil shale
retorting (Figure 5A).
The rundown oil from the retort is treated sequentially for solids,
arsenic, and light ends removal (Figure 5B). The solids removal is accomplish-
ed by two stages of water washing. The shale fines are collected in the water
phase which is recycled to the water seal. The water seal is a Union Oil con-
cept, shown in Figure 3, in which a water level is maintained in the conveyer
for retorted shale removal to seal the retort pressure from atmosphere. For
arsenic (As) removal, a proprietary Union Oil process employing an adsorbent
is utilized to reduce the arsenic content of the raw shale oil from 50 ppm to
2 ppm. Arsenic removafMs necessary because the presence of the relatively
high concentration of ai&gnic j'jT_ihfi_jcrud£_sbale-oil (50 ppm As in crude shale
oil vs less than. 0.03 ppm As in conventional crudes) would lead to catalyst
deactivation in both hydrotreating and in subsequent catalytic reforming. The
dearsenated shale oil is sent to a stripping column for stabilization and
stripping prior to shipment. This partially upgraded shale oil can now be
marketed as a low sulfur burner fuel in various locations in the United States,
and is also a suitable feedstock for refineries that have adequate hydrotreating
-------
capacity. It may be noted that rather severe hydro treating conditions are
required to reduce the high level of nitrogen in the crude shale oil to the
low levels acceptable for reforming. At the present time, however, Union Oil
does not envision additional upgrading of the crude shale oil on-site.
For the Retort B prototype plant, the principal pollution control devices
in the Union Oil design include the Stretford process for hydrogen sulfide re-
moval from the retort make gas and oil/water separation and sour water strip-
ping for wastewater treatment. The treated wastewater is used in the cooling
and moistening of the retorted shale to provide for dust control and proper
compaction. Dust control is also provided throughout the plant wherever emis-
sion might be encountered.
The crude shaLe oil fromjthe Retort.. B jjcocess -has a .speci fie gravity of
0.918 T^2^7?AP_lL_i,PQlir poirdLOf. 15.^60£_XfiDP_E)., and aJdnematic viscosity of
TlTcen ti stokes (98. 2SUS) at 37.80C (lOOOj)^ Jjbtypically contains 1.74
0.81 Wei^liL4ierce5£!?uTTur . Its Conradsbn carbon
-
residue (1.75%Tis lower, than that of the Paraho or TOSCO shale oils (5%).
Union Oil indicates that a better quality crude shale oil is obtained in the
Retort B process because oil vapor evolved in the retort is quickly forced
downward by the gas toward the cooler shale, thus quenching the polymerization
reactions which form heavy oil that is difficult to refine. In addition, the
use of an indirectly heated recycle gas in the Retort B process appears to
result in a crude shale oil of lower oxygen content. This is desirable be-
cause the presence of oxygen compounds has been known to contribute to gum
formation and enhance corrosion rates in certain situations.
The Retort A process uses similar equipment required in the Retort B pro-
cess. The main difference between the Retort A and Retort B processes is that
hot gases, generated by burning the carbonaceous deposit on the retorted shale
in the upper part of the retort, is used to cause oil shale pyrolysis in the
Retort A process. The Retort B process is selected over the Retort A process
because higher yields of a better quality shale oil and a high Btu gas product
are obtained with the Retort B process.
RETORTED SHALE DISPOSAL
The retorted shale from the Retort B process is similar to that produced
by the Bureau of Mines and Paraho retorting processes. It is a coarse gravel -
sized material with some black carbonaceous residue remaining on the shale.
The retorted shale will be cooled and moistened by the treated waste water
prior to disposal. The retorted shale slurry has a pH of 8.7 and very little
tendency for cementation. For the prototype plant, 7,620 tonnes (8,397 tons)
per day (dry basis) of retorted shale containing approximately 20 percent
water will be transported to a disposal area in the East Parachute Creek
Canyon, where it will be laid down and compacted in windrows proceeding up the
south embankment. The embankment will be provided with a leachate collection
ditch, so that any leachates resulting from rain and snow melt runoff will be
gathered and discharged into the plant water supply pond. In addition, a cut-
off trench will be constructed immediately downstream of the plant water
supply pond to bed rock so as to help collect subsurface flow of any leachates
Thus, all process wastewater, as well as any retorted shale embankment runoff,
-------
will be collected in the plant water pond.
Union Oil is currently investigating revegetation on retorted shale plots.
The results, based upon initial germination, appear to be favorable.* For the
prototype plant, Union Oil plans a revegetation program which includes mulch-
ing, seeding, irrigation, and fertilization.
OIL SHALE RETORTING PRODUCTS AND UTILITIES REQUIREMENTS
For a commercial size plant processing 57,620 tonnes (63,500 tons) of 34
gpt oil shale per stream day, the Union Retort B process will generate the
following products:
Crude shale oil: 7,950 m3 (50,000 bbl) per stream day
Sulfur: 51 tonnes (56 tons) per stream day"1"1"
Retorted shale (dry basis): 47,800 tonnes (52,680 tons) per stream day
Wastewater (contained in the retorted shale): 498 m3/hr (2,190 gpm)
The total water consumption rate is estimated by Union Oil to be 585 m3/
hr (2,580 gpm) and the power requirement to be 70,000 kw. The fuel require-
ments for the plant will be met by the retort make gas produced.
ilipman, S. C., "Union Oil Revegetation Studies," paper presented at the
Environmental Oil Shale Symposium, Colorado School of Mines, October 9-10,
1975.
''"''This sulfur production rate, supplied by Union Oil, appears to be low. TRW
estimates a sulfur production rate of 120 tonnes (132 tons) per stream day
based on TOSCO II retorting process gas product composition.
8
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Note: Figures 2 and 3 are from the paper
"Development of Union Oil Company
Upflow Retorting Technology" by
J. M. Hopkins, H. C. Huffman, A.
Kelley and J. R. Pownall, presented
at the 81st AIChE National Meeting,
April 11-14, 1976, Kansas City,
Missouri
SHALE FEED
CHUTE
OIL LEVEL
\\muui
\\ttltlir
MMUIII
\\M1I
RETORTED SHALE
DISCHARGE
TO WATER SEAL
Figure 2. Union Retort B
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A
RECYCLE GAS
HEATER
OIL-WATER
SEPARATOR
RETORT HAKE GAS TO
GAS TREATING
C.W.
RETORTED SHALE TO
DISPOSAL
RUNDOWN OIL PRODUCT
Figure 3. Union Retort B Flow Diagram.
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lTtM
sirrir
I««T
CM
SUPflT
CMLIM
w«n«
11»HT
f LMT 1
IMTUMXT
Alt
>«(TU
ITMMT
KM II
Jimt
rvii
sum*
WLICF
M»
KCIMMTOI
i»in«
CHEKICAI.
iTDwa
MO
mniiM
ritt
WATtft
STOW 1
AMA V»n«
MAIMU
(ucnicAi
Jisitn
• UU
HMOIIIIC
*»
STOMCI
Ofnei
MO
uuawuit
•UILONCS
COlTMt
MB
UTILITY
WIlDIIGl
CLMI
IM1UT10I
UTILITIIl
or r si TI s
Note: Figures 4 and 5 are supplied by the Union Oil Company.
Figure 4. Block Flow Diagram for Union Oil Retort B Prototype Plant.
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ro
SHALE FEED
FROM FEED
PREPARATION d} . RETORT
hF^-
W-
Lt_
(
RECYCLE GAS f
DISENGAGED GAS
RETORTED SHALE //
COOLING VESSEL //
f *V
SHALE LEVEL X^ RECOVERED
WATER LEVEL QUENCH WATER
I^S^ c — 3-*— •
pV
0
RETORTED SHALE
TO RETORTED
SHALE DISPOSAL
MAKEUP WATER d^-—
RECYCLED PLANT WATERED
VAPOR QUENCHING
AND SCRUBBING
^
Q>
QUENCH PUMP
DISENGAGED
OIL
SCRUBBER
CIRCULATION(
PUMP
COOLING ^
WATER
^
S. RECYCLE GAS
HEATER
7
^_ WATER STRIPPER
"-j 1 NONCONDENSIBLE
A GASES FIG. C
[ PLANT
L— CI3 FUEL GAS
1
V. VENTURI
fN SCRUBBER
fr
OIL-WATE
J SEPARATO
-Ai* ^(\
^\y* ^vj
SCRUBBER
CIRCULATION
RECYCLE GAS
COMPRESSOR
r~* —
•^Lf
MAKE GAS
1 *— >TO TREATING
FIG. C
R
R
1) 1 LIGHT ENDS OIL
'STRIPPER FIG. C
LIQUID PRODUCT
1
KNOCK OUT
DRUM
FIG. B
Figure 5A. Flow Diagram for Retort System 1n Union 01, Retort B Prototype P,ant.
-------
LEAN OIL TO
ABSORBER £
FIG. C
RICH OIL
FROM
ABSORBER
Fir.. C
LIQUID PRODUCT
FROM RETORT
FIG. A
RECOVERED OIL FROM
WATER STRIPPER
FIG. C
2-STAGE
MASHER
WATER
FIRED
HEATER
7\
T_
Fl RST STAGE WATER
WATER STRIPPER
FIG. C
STRIPPER OVERHEAD
GAS TO HAKE GAS
COMPRESSOR
FIG. C
WATER TO WATER
STRIPPER FIG. C
GAS TO STRETFORD
ABSORBER FIG. C
PLANT FUEL GAS
SECOND STAGE WATER
>TO RETORTED SHALE COOLING
FIG. A
LIQUID PRODUCT
TO STORAGE
POUR POINT
DEPRESSANT
Figure 5B. flow Diagram for Shale Oil Processing in Union Oil Retort B Prototype Plant.
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RETORT HAKE
GAS FIG. A
OIL STRIPPER
OVERHEAD CAS
FIG. B
WATER FROM
OIL-WATER
SEPARATOR
FIG. A
WATER FROM
FIRST STAGE
OE-ASHER
FIG. B
WATER FROM
OIL STRIPPER
CONOENSATE DRUH
FIG. B
COOLERS
ABSORBER
MAKE GAS
COMPRESSOR
L KNOCK OUT
DRUM
r
{*,/
OIL TO WASHER
FIG. B
OIL SEPARATOR
STEAM
WATER
STRIPPER
/
AMMO
^*\
WATER
OEBUTANIZER
GAS FIG. B
AMMONIA LIQUOR TO
WATER STRIPPER
LEAN OIL
(STRIPPER BOTTOMS)
FIG. B
RICH OIL TO STRIPPER
FIG. B
NON CONDEHSIBLE GASES
TO INCINERATION
FIG. A
PLANT FUEL GAS
5 SULFUR
TO RETORTED SHALE COOLING
FIG. A
Figure 5C. Flow Diagram for Fuel Gas Process and Water Treatment in Union Oil Retort B Prototype Plant.
-------
PARAHO OIL SHALE PROCESS
T. D. Nevens, C. H. Prien
The Paraho Oil Shale Process is based on a series of patents and inven-
tions by John B. Jones, Development Engineering, Inc. (DEI). The retorting
technology is the outgrowth of research extending over many years on (a) the
pyrolysis of both Colorado and Brazilian oil shales, and (b) the calcination
of both high calcium and dolomitic limestones.
BACKGROUND
In 1972, Development Engineering, Inc. obtained a long-term lease on the
U.S. Department of Interior/Navy oil shale plant and mining facilities at
Anvil Points in order to prove the DEI technology. The Paraho Development
Corporation was formed with DEI as a subsidiary, and the Paraho Oil Shale Pro-
ject was launched in late 1973 with funds provided by 17 participating com-
panies ,1" including many with long experience in oil shale research. DEI con-
tinued as the operating company, and Arthur G. McKee and Co. was selected as
engineering contractors.
Two newly designed Paraho oil shale retorts were constructed at Anvil
Points, and placed in operation in 1974. These included a 1.4 meter (4.5 ft)
O.D. pilot plant used for rapid investigation of operating parameters, and
a 3.2 meter (10.5 ft) O.D. semi-works unit with a nominal throughput capacity
of 408 tonnes (450 tons) per day for large-scale testing under production con-
ditions. The oil shale retorts were based on a DEI design used successfully
for lime burning, where throughput rates of up to 635 tonnes (700 tons) per
day have been attained.
The two retorts have been operated on an intermittent basis from mid-1974
to mid-1976 as part of a continuing $9 million Paraho project to determine de-
sign parameters for scale-up to a commercial plant. During one 56-day semi-
continuous run of the semi-works plant in 1975, using a direct-heating modett
some 1600 cubic meters (10,000 barrels) of shale oil were produced. The Navy
had the oil refined into seven different fuels by the Gary Western Refinery
near Grand Junction, Colorado.
fThe seventeen Paraho participants are Atlantic Richfield, Carter Oil (Exxon),
Chevron Research (Std. of California), Cleveland-Cliffs Iron Co., Gulf Oil,
Kerr-McGee, Marathon Oil, Arthur G. McKee, Mobil Research, Phillips Petrol-
eum, Shell Development, Sohio Petroleum, Southern California Edison, Stan-
dard Oil Co., (Indiana), Sun Oil, Texaco, Webb-Chambers-Gary-McLoraine Group.
description of direct and indirect heating modes is given in the subse-
quent section on retorting.
15
-------
The program on the semi-works retort direct-heated mode of operation was
completed in November 1975. Oil yields varied from 94% to 97% of Fischer
assay. The pilot plant retort has continued operation in the direct mode pri-
marily to provide a source of low-Btu gas for subsequent indirect-mode opera-
tion of the semi-works retort.
The semi-works retort was converted to indirect-mode heating in December
1975, and a 30-day run completed in February 1976. Yields of up to 97%
Fischer assay were obtained during a 12-day "confirmation run."
It was planned to carry out further development of the Paraho process in
1977 under a proposed $12-$15 million ERDA/Navy appropriation. An Environ-
mental Impact Statement was completed for the construction of a full-
scale 11,800 tonnes (13,000 tons) per day modular Paraho retort and support-
ing facilities.
PARAHO DEMONSTRATION PROJECT
The present Paraho oil shale demonstration project utilizes some of the
facilities originally developed by the U.S. Bureau of Mines at Anvil Points,
including an underground room and pillar mine, crushing plant, retort struc-
ture, various storage tanks, shale disposal area, and associated laboratories,
maintenance shops, and water supplies.
Underground Mining, Crushing
The mine at Anvil Points is a room and pillar operation encompassing the
Mahogany Ledge of the Green River Formation at an altitude of approximately
2440 meters (8000 ft). Mined shale is trucked approximately 8.8 kilometers
(5.5 miles) to the processing area, at an elevation of about 6000 feet. Through
1976 over 75,000 tons of oil shale had been mined by Paraho, of which more
than 80% had been sent through the Paraho retorts.
At the plant site the mined shale is processed through the primary and
secondary circuits of the USBM crushing and screening plant to produce a feed
of approximately minus 7.6 cm (3 in) plus 6 mm (% in) size, which is sent to
storage bins. The 10-15% fines from the screening plant are stockpiled.
Retorting Plant. Auxiliary Facilities
Two Paraho-type retorts (Figure 6) have been erected in a steel structure
adjacent to the old USBM gas combustion unit. These include a 1.4 meter (4.5
ft) O.D. (2.5 ft I.D.) by 18 meters (60 ft) high pilot plant unit, and a semi-
works retort which is 3.2 meters (10.5 ft) O.D. (8.5 ft I.D.) by 23 meters
(75 ft) high. To avoid flaring retort make gases, the old USBM gas combustion
unit has been converted to a thermal oxidizer.
Provision has been made for operating the retorts in either the direct
mode or indirect mode. In the direct mode (Figure 7) the carbonaceous residue
on the retorted shale is burned in the combustion zone to provide the princi-
pal fuel for the process. Low Btu retort gases are recycled to both the com-
bustion zoneandthe residue cooling and gas preheating zone. A typical re-
tort temperature profile for this mode of operation is shown in Figure 8.
16
-------
*from Jones, John B., "The
Paraho Oil Shale Retort,
81st Nat. Mtg., AIChE,
Kansas City, Mo., April 11-14,
1976.
ROTATING SOL'OS
JTO»
HYDRAULICALLY OPERATE
GRATE CONTROLS
RETORTED SHALE
DISCHARGE
Figure 6. The Paraho Retort.*
17
-------
RAW
SHALE
OIL MIST
SEPARATORS
MIST
FORMATION
AND
PREHEATING
RETORTING
ZONE
COMBUSTION
ZONE
RESIDUE
COOLING
AND
GAS
PREHEATING
PRODUCT
GAS
GATE
SPEED
•CONTROLLER!
i
GH
f-OIL
ELECTROSTATIC
PREC1PITATOR
RECYCLE GAS
BLOWER
AIR BLOWER
RESIDUE
Figure 7. Paraho Direct Mode Flow Diagram.
18
-------
RETORT 70NFS
r.c 24 FT -
\yAZ> * • t^ r 1
OUT \
20 FT
t
WATER l5 FT
OR — i-*- 14 FT
STEAM]
DISPERSION
GAS
AIR — p^ 10 FT
IN |
DILUTION
GAS
AIR « ...
IN ~ r*- 6 FT
I 5 FT
DILUTION
QAS
RECYCLE
nA a t- Q
' -^ PREHEATING AND
^^ MIST FORMATION
X
N
\
V PYROLYSIS
\
\
\
\ STRIPPING AND
CO-*- H20-*-C02fH2 v WATER GAS SHIFT
- € •«• H20~*-C0+ H2 \
V
\
\
1
2C-f02 — »2CO '• UPPER PARTIAL
1 COMBUSTION
V
\
l
2C+02 2CO J MIDDLE PARTIAL
v COMBUSTION
X
+* t it ** *•*** * i i ^
C+H20 CO + H2 » LOWER
C4-O2 C02 J COMBUSTION
^'" RESIDUE
,"' COOUNG
,'''
i/iiiliiiili iiii
IN J 500° F 1000° F 1900 °F
AIR
IN
*from U.S. Patent 3,736,247.
Figure 8. Temperature Profile in Paraho Direct Mode Retort.*
19
-------
In the indirect mode (Figure 9) heat for retorting is supplied by hot re-
tort gases from an outside furnace, thus eliminating combustion in the retort
and producing a high heating value, 8000 kcal/std cu meter (900 Btu/SCF) off-
gas.
In either mode of operation (Figures 7 and 9), raw shale is fed into the
top of a Paraho retort by means of a rotary pant-leg distributor, and passes
downward by gravity successively through a mist formation and preheating zone,
a retorting zone, either a combustion zone (direct mode) or heating zone (in-
direct mode), and finally, a residue cooling and gas preheating zone. It is
discharged through a hydraulically-operated grate which controls the desirable
downward velocity and maintains even flow across the retort. This grate, the
rotary feed mechanism, and the multi-levels of heat input are among the unique
contributions of Paraho technology toward improving the retorting principle in
vertical kiln type retorts.
The retorted shale, containing about 2% carbon (direct mode) to 4.5% car-
bon (indirect mode), is discharged from the retort at about 150°C (300°F). It
is then sent to the shale disposal area originally developed by the Bureau of
Mines.
The shale vapors produced in the retorting zone are cooled to a stable
mist by the incoming raw shale (which is thereby preheated), and leave the re-
tort at approximately 60°C (14QOF). This mist is sent to a roughing cyclone,
a condenser, and finally a wet electrostatic precipitator, for oil separation.
The resulting shale oil is transported to storage.
In the direct mode, the remaining cooled, oil-free retort gases (approxi-
mately 908 kcal/std cu meter (103 Btu/SCF) are, in part, recycled to the retort
(Figure 7). The remaining product gases are sent to a thermal oxidizer without
treatment for H2S or NH^ removal, and the resulting flue gases vented to the
'atmosphere. In a commercial size plant the product gases would be processed,
as required, to be H2S and NH3 free, and used as plant fuel or for power gene-
ration in low-Btu turbines. From 116 liters/tonne (28 gal/ton) raw shale,
there is produced some 193 std cubic meters/tonne (6,200 SCF/ton) of product
gases.
The direct mode recycle gases are, in part, used to cool the retorted
shale on the grate in the lower "residue cooling and gas preheating zone."
The remaining recycle gases are used at several levels to dilute the air enter-
ing the retort for combustion.
In the indirect heating mode (Figure 9) the mist-laden off-gases leave
the retort at 138°C (280°F). After oil separation, the oil denuded recycle
gases have a high heating value, about 7,560 kcal/std cu meter (885 Btu/SCF).
Part of these gases are reheated in an outside heater and distributed to the
retort at several levels. It is these hot gases which supply the necessary
heat for retorting the shale. No residual carbon on the retorted shale or gas
is burned in the retort. There is, therefore, no dilution of off-gases with
combustion products and resulting reduction in retort-gas heating value.
20
-------
RAW
SHALE
A
MIST
FORMATION
AND
PREHEATING
D
RETORTING
ZONE
HEATING
RESIDUE
COOLING
AND
GAS
PREHEATING
OIL MIST
SEPARATORS
ELECTROSTATIC-
PRECIPITATOR
RECYCLE GAS
BLOWER
»- PRODUCT
0-
AIR BLOWER,
RESIDUE
Figure 9. Paraho Indirect Mode Flow Diagram.
21
-------
The fuel for the external, recycle-gas heater may be a side-stream of the
recycle gas itself, or an outside fuel. Using recycle gas as fuel, there is
produced some net 15.6 std cubic meters/tonne (500 SCF/ton) of high Btu pro-
duct gas from a 116 liters/tonne (28 gal/ton) shale.
Semi-Works Plant Operating Characteristics
With the Paraho retort, higher throughput rates have been attained than
with previous gas combustion retort designs. Mass rates of 2934 kg/hr sq meter
retort cross-section (600 Ibs/hr sq ft) have been attained in the semi-works
plant, and 3423 kg/hr sq meter (700 Ibs/hr sq ft) in the pilot plant retort.
Carbonate decomposition has been essentially eliminated during indirect mode
operation. During direct-mode operation there has been essentially no clinker-
ing, a problem in earlier gas combustion retort designs. The shale passes
through the retort without substantial change in size distribution (minimum
production of fines).
Product Properties
Shale Oil. Selected properties of the Paraho shale oils from both direct
and indirect mode operation in the semi-works retort are shown in Table 1.
The direct mode oil has essentially the conventional characteristics of a gas-
combustion-type raw shale oil. While no sulfur or nitrogen contents have been
reported by Paraho, these could also be expected to be in the usual range for
oil from internally-heated retorts.t
The indirect-mode Paraho oil has a somewhat lower pour point (18°C, 65°F),
which has also been reported for the crude shale oils from other indirectly-
heated retorts (e.g., Union (650F)). Further lowering of this pour point
would probably require coking.
As a result of the combustion zone in the direct mode retort the volume
of retort gases produced in this mode, as expected, is 12 times that from in-
direct heating mode (see Table 2 ). Conversely, the heating value of the
indirect mode gases, as a result of np_ combustion zone in the indirect retort,
have 9 times the heating value of the direct mode gases.
Retort Gases. The composition of the retort gases from the two retorts
is given in Table 2. It is noted that the indirect heating mode gases are
much lower in carbon dioxide because of the lower indirect heating mode re-
tort temperatures, but have substantially higher concentrations of H2S and
NH,, in the absence of a combustion zone. The HoS and NhU would obviously
have to be reduced in all retort gases prior to their use as fuels. Data on
such upgrading have not yet become available.
Retorted Shale. Paraho retorted shale has essentially the same size
distribution as the raw shale feed (minus 3 in plus % in). In addition to the
fThe White River Shale Project Detailed Development Plan (July 1976) reports
0.7 wt % S, 2.1 wt % N for a Paraho-type direct or indirect mode crude shale
oil.
22
-------
Demonstration Project disposal area at Anvil Points, a series of test plots
for a research and development program on Paraho retorted shale has also been
established. Although this study is still in progress some preliminary re-
sults have been published.1 A series of lysimeter tests has also been ini-
tiated by Colorado State University.
Table 1. Paraho Shale Oil Properties*
Heating Mode
Item Direct Indirect
Gravity, A.P.I. 21.4 21.7
Viscosity, SUS @ 130°F 90 68
SUS (a 210°F 46 42
Pour Point °F 85 65
Ramsbottom carbon wt % 1.7 1.3
Water Content, vol % 1.5 1.4
Solids, B.S.,** wt % .5 .6
Note: from semi-works retorting of the 116 liters/
tonne (28 GPT) shale, at 97% Fischer assay
yield.
*Jones, John B., "The Paraho Oil Shale Retort,"
81st Nat. Mtg., A.I.Ch.E., Kansas City, Mo.,
April 11-14, 1976.
**B.S. (Basal Sediment)
Soluble salts in the processed shale are in the order of 2%; pH is 10.7
to 11.8, and electrical-conductivity is in the range 5 to 20 mmhos. It would
appear from these data that the surface layer of the disposal pile will re-
quire leaching prior to revegetation. Other Paraho spent shale properties
are shown in Table 3. It is noted that compaction densities of 1410-1570
kg/cubic meter (88-98 Ibs/cu ft) have been readily attained in the disposal
piles, at 22-23% H20.
FULL-SCALE COMMERCIAL MODULE
Over a four-year period Paraho has proposed the construction and opera-
tion of a full-scale single commercial module of a Paraho retort with a nomi-
nal throughput capacity of 11,800 tonnes (13,000 tons) per day. The retorting
Woodward-Clyde Consultants, "Research and Development Program on the Disposal
of Retorted Oil Shale-Paraho Oil Shale Project," prepared for US Bureau of
Mines, NTIS PB-253-597 (Feb. 1975); PB-253-598 (July 1975); PB-253-599 (Dec.
1975).
23
-------
Table 2. Paraho Retort Gas Properties*
(dry basis)
Item
°2
CO
co2
CH
C2H6
C3
C4
Item
H2S
NH3
High Heating Value, Btu/SCF
High Heating Value, kcal/m3
Retort Gas Yield, SCF/ton
Retort Gas Yield, m3/ tonne
Note: from semi-works retorting of 116 liter/tonne (28 GPT)
oil shale, at 97% Fischer assay yield.
*Jones, John B., "The Paraho Oil Shale Retort," 81st Nat.
Mtg., A.I.Ch.E., Kansas City, Mo., April 11-14, 1976.
Direct Mode
(vol %)
2.5
65.7
0
2.5
24.2
2.2
0.7
0.6
0.7
0.4
(PPM.)
2660
2490
102
908
6200
193
Indirect Mode
(vol %)
24.8
0.7
0
2.6
15.1
28.7
9.0
6.9
5.3
2.0
(vol %)
3.5
1.2
885
7560
500
15.6
24
-------
Table 3. Physical Properties of Paraho Direct Mode Processed Shale
(Woodward-Clyde, Consultants, Denver, Colorado)
(a)
Gradation (ASTM D422)
Maximum particle size
Clay size (0.005 mm)
Silt and clay size (- No. 200 sieve)
Sand size (No. 200 to No. 4 sieves)
Gravel size (+ No. 4 sieve)
Plasticity (ASTM D423 and D424)
Liquid limit
Plasticity index
Specific gravity (ASTM D854)
Apparent (all sizes)
Relative density^ (ASTM D698)
Dense (100%)
Loose (0%)
Compaction^ (ASTM D698 and D1557)
2 in
2%
22%
23%
55%
(b)
nonplastic
2.59
89.4 Ib/ft
71.5 Ib/ft
3(d)
3(d)
Compact i ve
Effort
6,200 ft-lb/ft3
12,375 ft-lb/ft3
56,259 ft-lb/ft3
Optimum
Moisture
23.7%
22.0%
22.0%
Low
Moderate
High
Permeability^ (USBR Earth Manual, E-13)
Density
(Max. at Optimum
Moisture)
88.0 Ib/ft3
92.5 Ib/ft3
98.0 Ib/ft3*
Low
Moderate
High
Compact! ve
Effort
6,200 ft-lb/ft3
12,375 ft-lb/ft3
56,250 ft-lb/ft3
Permeability at Loading
50 psi
15.5 ft/yr
7.0 ft/yr
1.1 ft/yr
100 psi
5.5 ft/yr
1.4 ft/yr
0.6 ft/yr
200 psi
1.7 ft/yr
0.8 ft/yr
0.08 ft/yr
(a) Sample 1-B taken from Paraho semiworks plant at Anvil Points, Colo,
(b) Average of two values
(c) Minus 1% inch fraction
(d) Lower numbers have been reported by others on similar materials
From White River Shale Project, Draft Detailed Development Plan, p.
3.10-3, April 1976
25
-------
plant and its support facilities, including a mine and processed shale dis-
posal area, will be located on the Naval Reserves at Anvil Points (Figure 10).
As noted in Figure 10, mining will be carried out on a larger scale than
the present room-and-pillar mine underground facilities. Shale will be passed
through a conveyor system to a 5 acre retort plant area located on the present
mine road approximately 3/4 of a mile southwest of the mine, at an elevation
of approximately 7,000 feet. Retorted shale will be conveyed to the disposal
area now being used for the current Paraho operations. Shale oil will be
transported by rail or truck to a refinery for processing. A block flowsheet
of the overall proposed operations is shown in Figure 11.
Underground Mining. Crushing
Mining. It is proposed to extend the present Paraho/USBM mine at Anvil
Points to as much as 56 hectares (138 acres) underground (21.6 hectares, or
53 acres in the first 30 months of operation) in order to permit the extrac-
tion of up to 10 million tonnes (11 million tons) of raw shale. It is anti-
cipated, however, that only 3.6 million tonnes (4 million tons) would be pro-
cessed during the 30-month projected operating period of the modular plant.
Run of the mine shale will average 116 liters/tonne (28 gal/ton).
The haulage entry adit will be approximately 12.2 x 46.5 meters (40 x 150
ft) and initially 610 meters (2,000 ft) long. The underground rooms will be
18.3 meters (60 ft) wide, with 18.3 x 18.3 meters (60 ft x 60 ft) by 24.4
meter (80 ft) high pillars. Upper level drilling on a 12.2 meter (40 ft)
high bench will be done with a two-drill jumbo capable of drilling 10.8 cm
(4.25 in) diameter holes 9 meters (30 ft) deep in a single pass.
The primary blasting agent will be ammonium nitrate-fuel oil placed in
the holes pneumatically. The blasted shale will be loaded into rear dump
trucks with front end loaders.
A ventilation system similar to a coal mine system will be installed with
a total air requirement of approximately 26,470 cu meters (750,000 cu ft) per
minute. Mining water will come from an existing reservoir source on the
plateau above the mine.
Primary Crushing. The primary crusher will be located in the mine (Figure
12) where a single or double-toothed roll crusher will reduce mine-run shale to
minus 25.4 cm (10 in). A 27,200 tonne (30,000 ton) crushed shale surge pile
will be maintained in the mine. After crushing, the shale will be fed into
a 3 meter (10 ft) diameter orepass (Figure 10) which will deliver the shale to
a conveyor adit at the retort elevation. An enclosed conveyor belt will trans-
fer the shale to a secondary crusher at the retort site.
Secondary Crushing and Screening. The secondary crushing and screening
area consists of a crushing unit, a primary screening unit, and a secondary
screening unit so that various feed size ranges may be produced. Dust collec-
tion hoods will be provided at each crushing station and all screening stations,
Hoods will be installed at all conveyor loading and discharge points as well
as the receiving bin of the retort. The hoods will be ducted to induced draft
26
-------
„ r-' "-a£=fc~
•:>
*from Draft EIA, Paraho Project, USBM, May 1975.
Figure 10. Proposed Site Additions to Anvil Points Facilities.*
27
-------
PO
CO
MINE
PRIMARY
CRUSHER
FINES
AIR BLOWER
ORE PASS
CONVEYOR
SYSTEM
RETORT
1
CONVEYOR
SYSTEM
RETORTED
SHALE
PILE
CRUSHING
a
SCREENING
CONVEYOR
SYSTEM
SHALE
STORAGE
BINS
CONVEYOR
SYSTEM
OIL
RECOVERY
WATER
EXCESS
WATER
OIL
STORAGE
RAILROAD
TRANSPORTATION
TO REFINERY
SPECIAL
TESTING
HOLDING
POND
*Paraho Project Brochure, Paraho Oil Shale Demonstration, Inc., 1972.
Figure 11. Block Flow Diagram of Proposed Paraho Modular Plant*
-------
ro
10
VENTILATION ENTRY
MAIN
ENTRY
MINE LAYOUT
*from Draft EIA, Paraho Project, USBM, May 1975.
Figure 12. Proposed Plan for Mine Extension.*
-------
bag-type collectors with clean air discharge to the atmosphere. Undersized
shale from the screening operation (typically 10% fines) will be used partly
for road surfacing and partly for land fill.
RETORTING PLANT AUXILIARY- FACILITIES
The single full-size modular Paraho retort and support facilities will be
constructed on a 61 meter by 244 meter (200 ft by 800 ft) site, probably on
top of the hogback (Figure 10). The vertical kiln will be 12.8 meters (42 ft)
in diameter and 32 meters (104 ft) high, with a nominal capacity of up to
11,800 tonnes (13,000 tons) per day. It will be of the conventional Paraho
design previously described for the Demonstration Project, and will operate in
the same manner.
Minus 7.6 cm (3 in) plus 6 mm (0.25 in) feed from secondary crushing and
screening will be fed to the top of the modular retort. Feed chutes will dis-
tribute the shale uniformly around the top level of the charge. Uniform rock
descent throughout the cross section of the retort will be maintained by the
special hydraulic grate, which also removes the retorted shale from the bottom
of the retort. The shale moves downward through four zones via a mist forma-
tion zone (raw shale preheating), a retorting zone, a combustion zone, and a
cooling zone (gas preheating and residue cooling). In the direct heating mode
air will be fed to the retort at a rate of about 154 standard cubic meters/
tonne (5,000 SCF/ton) of 116 liters/ton (28 gal/ton) raw shale throughput.
To seal the top of the retort against escaping combustion retort gases,
an inert gas will be introduced into the feed chutes just above their dis-
charge level at a pressure slightly higher than that of the gases in the re-
tort. Retorted shale is removed from the bottom of the vessel through a bat-
tery of rotary seals. Dust collector systems will be provided for both the
entry and discharge ends of the retort.
The mixture of shale oil mist-entrained in retort off gases will be col-
lected at the top of the retort and sent through an electrostatic precipitator
and associated separation equipment for oil recovery. Some 954 to 1430 cubic
meters (6,000 to 9,000 barrels) of shale oil will be produced per day from
28 GPT oil shale.
The oil and some associated water would be transferred to the existing
Paraho oil storage facility which has a capacity of about 2,400 cubic meters
(15,000 barrels), or two days production, and subsequently transported to a
local refinery for further upgrading. It is not expected that sulfur or ammo-
nia will be recovered at Anvil Points in the operation of the modular plant.
After leaving the oil recovery system, a portion of the off gases, 500
std cubic meters/tonne (16,000 SCF/ton) of shale, will be recycled to the re-
tort in the direct heating mode. The remainder of the gases, about 250 std
cubic meters/tonne (8,000 SCF/ton) of shale, could be burned in a gas turbine
in order to provide power for the gas and recycle blowers and other plant
power requirements. (It may be, however, that plant power will be purchased
from an outside utility source.) Alternatively, these remaining gases would
be sent to a thermal oxidizer and flared.
30
-------
Shale Oil Upgrading
2
In the original Paraho prospectus proposed flow diagrams were presented
for converting Paraho shale oil to (a) syncrude or (b) low sulfur distillate
fuel oil. These involved conventional delayed coking, gas treating, and hydro-
genation of naphtha and gas oil fractions with the recovery of ammonia, sulfur
and coke. For example, in the syncrude flowsheet for a direct mode Paraho
plant processing 130,600 tonnes (144,000 ton) per calendar day raw shale and
producing 14,300 cubic meters (90,000 barrels) per day of syncrude, there are
obtained per day, as by-products, 2"{ju tonne's (zzU tons) of ammonia, 82 tonnes
(90 tons) of sulfur, and 1,180 tonnes (1,300 tons) of coke.
Yields of syncrude and by-products for a 15,900 cubic meter (100,000
barrels) per day Paraho shale oil plant have also been examined in a more recent
study of energy and water requirements for commercial-scale Paraho production
by McKee and Kunchal.3 These are further discussed in the section on Energy
and Water Requirements.
It should be noted that'quantitative assessment of these upgrading
methods and their yields must await further scale-up of the Paraho retorts.
This is also true of particulate and emission .control technologies for the
Paraho retorting process and associated upgrading methods. These control
technologies have not yet been determined since the basic retorting processes
are still under development. It is expected that such pollution controls will
be more fully delineated, together with the emissions and effluents involved,
as further Paraho research at Anvil Points proceeds during 1977 and 1978.
RETORTED SHALE DISPOSAL
After the shale has been retorted it is discharged from the bottom of the
retort to conveyors for transport to a holding bin. A dust collection system
will be provided at the discharge points. Retorted shale along with some raw
shale fines, will be transported by truck to the present canyon disposal area.
The material will be deposited in a stable manner and moistened as necessary
for dust control and for compaction.
There are approximately 2.5 kg of retort water obtained per tonne (5 Ibs/
ton, or 0.6 gal/ton) of raw shale throughput. (This is only about one tenth
the usual gas combustion retort water yield). From a 13,000 ton/day feed
rate, some 29.5 cubic meters (7,800 gallons) per day of retort water would be
produced. Proposed use of this water for temperature control, dust control,
and compaction of retorted shale should be carefully investigated to determine
any adverse environmental impacts from included contaminants.
2
Paraho Project Brochure, Paraho Oil Shale Demonstration, Inc. 1972.
McKee, J. M., and Kunchal, S. K., preprint, "Energy and Water Requirements
for an Oil Shale Plant Based on the Paraho Process," 9th Oil Shale Symposium,
Colorado School of Mines, April 29-30, 1976.
31
-------
A typical analysis of such Paraho retort water from direct-mode opera-
tion is given in Table 4. A catch basin will be constructed to retain runoff
water from the shale disposal area, and a culvert 1.8 meters (6 ft) in dia-
meter by 1,280 meters (4,200 ft) long will be installed along the canyon
beneath the disposal site to accommodate runoff from above, including that
from a historical 100-year storm.
Table 4. Paraho Retort Water Analysts*
Cations mg/1
Calcium 76.0
Magnesium 58.0
Sodium 290.0
Potassium 35.0
Ammonium 4910.0
Anions
Carbonate 0.0
Bicarbonate 1500.0
Sulfate 5900.0
Chloride 5300.0
pH 7.6
C.O.D. 17,000
Nitrogen (NH3) 3,810
Total Kjeldahl Nitrogen 4,590
Sulfide(s) 0
Solids, Total 18,100
Solids, Dissolved 17,400
Solids, Suspended 700
Total 0)3 1,300
Dissolved Organic Carbon 3,420
*From "Draft Environmental Impact Assessment for
a Proposed Accelerated Paraho Oil Shale Research
Project at Anvil Points, Colorado," U.S. Bureau
of Mines, May 1975
32
-------
It is expected that up to 3.26 million tonnes (3.6 million tons) of re-
torted shale and shale fines could be produced from the 3.6 million tonnes
(4 million tons) of raw shale processed during the projected 30 months of
operation of the modular retorting plant. Some 22 hectares (55 acres) of
canyon area could be involved in their disposal at pile depths from zero up
to 64 meters (210 ft). Some 14% of total canyon area would be involved. The
disposal area would be compacted, contoured, and revegetated.
Paraho has carried out some unpublished studies on the disposal
of partially calcined retorted shale without the addition of water. These
experiments were conducted upon a fairly small area using fairly thin lifts.
If an appreciable amount of time elapsed between the build-up of the various
lifts, it is presumed that the retorted shale would adsorb more moisture than
a full-scale operation. However, until the results of the study are avail-
able, it would be presumptious to judge the merits of such dry disposal tech-
niques in the absence of added water.
ENERGY AND WATER REQUIREMENTS
Energy
It is expected that some 9,000 KVA net outside power requirements will be
needed for mining, crushing, retorting, etc. in the commercial-module plant.
The present utility corridor at Anvil Points can be used for this purpose.
As mentioned above, it would be possible to supply a major portion of plant
power from a gas turbine using excess retort gases as fuel. However, unless
it is desirable to test a particular turbine design, this will probably not be
done. Diesel fuel for mining and truck transport at the modular plant will be
purchased outside.
McKee and Kunchal (see footnote 3) have computed the internal plant power
requirements for a 15,900 cubic meter (100,000 barrels) per day Paraho shale
oil plant processing 125 liter/tonne (30 6PT) oil shale, and operating in
either direct heating or indirect heating mode. The crude shale oil is up-
graded through coking and hydrotreating to either 13,800 cubic meters (87,000
barrels) per day of synfuel (direct mode) or 12,100 cubic meters (76,000
barrels) of synfuel per day (indirect mode). Also produced are 1,910 cubic
meters (12,000 barrels) per day of plant diesel fuel, 2,086 tonnes (2,300 tons)
per day of by-product coke, 263 tonnes (290 tons) of ammonia, and 123 tonnes
(136 tons) of sulfur.
In the direct mode, the internal plant power requirements are 190 mega-
watts, including 49 megawatts for mining, crushing, and spent shale disposal;
72 megawatts for retorting; and 31 megawatts for pre-refining (upgrading).
If the 1,184 kcal/std cu meter (133 Btu/SCF) low-Btu gas and all of the by-
product coke are converted to electric power, some 583 megawatts would be
generated. Therefore, some 393 megawatts (583 minus 190) of power could be
exported for sale.
In the indirect mode, the authors have assumed the same 190 megawatts in-
ternal plant requirements as for the direct mode. However, the 5,875 kcal/std
33
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cu meter (660 Btu/SCF) high Btu gas produced is consumed entirely as internal
plant fuel, and only the by-product coke is converted to electric power. Some
267 megawatts of power would thus be produced, of which 77 megawatts (267
minus 190) could be exported for sale.
Water
In order to supply water for the expanded mining operations, the present
2 acre-ft capacity of an existing reservoir on top of the plateau would be in-
creased by mucking out the bottom. For the remainder of plant water require-
ments, primarily for personnel, the output from the current water treatment
plant at the Colorado River would be increased from its present 45 acre-ft per
year to 100-110 acre-ft per year, representing only 1% of the total in Table 5.
McKee and Kunchal have examined the water requirements for a full-scale
Paraho oil shale plant operating with direct mode or indirect mode heating.
Their data is summarized in Table 5. It is noted that the indirect heating
mode consumes 40% more water than the direct heating mode, primarily for
increased revegetation water needs. The greatest single need for water, in
either mode, is for plant cooling tower makeup.
Table 5. Water Requirements for a 59,000 m3/Day (100,000 BPD) Paraho Shale
Oil Plant*
Basis: 125 liters/tonne (30 gal/ton) oil shale
Water Requirements (Acre-ft/yr)**
Direct Mode Indirect Mode
Plant Cooling Tower Makeup 6,530 6,530
Mining and Crushing 1,260 1,260
Revegetation 2,130 6,110
Misc. Evaporation from Dust Control 1,450 720
Total Water Consumed 11,370 14,620
Retort Water Produced 1,370 620
Net Raw Water Makeup 10,000 14,000
*Adapted from McKee, J. M., Kunchal, E. K., "Energy and Water Requirements
for an Oil Shale Plant Based on the Paraho Process," 9th Oil Shale Symposium,
Colorado School of Mines, April 29, 1976.
**0ne acre-foot equals 1233.5 cubic meters.
34
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TOSCO II OIL SHALE PROCESS
Charles H. Prien
TOSCO II is a process developed by The Oil Shale Corporation (TOSCO). It
is the only U.S. surface retorting method which uses sol id-to-solid heat trans-
fer between hot ceramic pellets and crushed oil shale, in a horizontal,
rotating retort, for shale oil production.
BACKGROUND
Initial development work (1955-1966) was conducted under TOSCO
sponsorship by the University of Denver Research Institute in a 21.6 metric
ton/day (24 ton/day) pilot plant. In 1964 a joint venture of Standard Oil
Company of Ohio, Cleveland Cliffs Iron Company and TOSCO was formed. A 900
metric ton/day (1,000 ton/day) semi-works plant was constructed on the 3441
hectares (8,500 acres) Dow property on upper Parachute Creek near Grand
Valley, Colorado (Figure 13)*. When Atlantic Richfield joined the venture in
1969, the venture name was changed to Colony Development Operation. (Later,
Ashland Oil Company and Shell Oil Company replaced Sohio and Cliffs).
The semi-works plant and associated pilot room-and-pillar mine were
operated until 1972. Over one million metric tons of shale were mined during
this period. Some 31,700 cubic meters (200,000 bbls) of oil were produced
from the 260,000 metric tons (290,000 tons) subsequently retorted.
A full-scale 59,800 metric tons/stream day (66,000 tons/stream day)
commercial plant which would produce 7,400 cubic meters/day (47,000 bbl/day)
of low sulfur fuel oil and 680 cubic meters/day (4,300 bbl/day) of LPG has
been designed. The plant would be located on the Dow West property of the
Middle Fork of Parachute Creek, with spent shale disposal in nearby Davis Gulch
(Figure 14). Plans for commercialization have been dormant since 1974 pending
initiation of a federally-sponsored synfuels commercialization program.
The TOSCO/Colony group probably conducted a more extensive environmental
assessment of its proposed plant than any other shale developer. A 20-volume
All Figures in this Overview Report are reproduced from either the Colony
Environmental Impact Analysis or the BLM Environmental Impact Statement
cited elsewhere as references, q.v.
**
An Environmental Impact Analysis for a Shale Oil Complex at Parachute Creek
Colo., Colony Development Operation, 1974.
35
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UINTAH COUNTY
T T -pJ 1
BRANDI COUNTY
I J
FEDERAL OIL SHALE
LEASE TRACTS
0) PIPELINE MILEAGE
Figure 13. Area Setting of Proposed Action
36
-------
I 23456 78
I RETORTING AND UPGRADING UNITS 2 PYROLYSIS 3 SECONDARY CRUSHER 4 COARSE ORE
STORAGE 5 COARSE ORE CONVEYOR FROM TUNNEL TO FINAL CRUSHING 6 PLANT MINE BENCH
ACCESS ROAD 7 MIDDLE FORK OF PARACHUTE CREEK 8 COARSE ORE CONVEYOR THROUGH TUNNEL
FROM MINE BENCH 9 MINE BENCH AND PRIMARY CRUSHING 10 MIDDLE FORK DAM II ACCESS
ROAD TO PROCESSED SHALE DISPOSAL 12 PROCESSED SHALE DISPOSAL IN DAVIS GULCH SIDE GULLY
13 PROCESSED SHALE CONVEYOR 14 DAVIS GULCH DAM 15 DAVIS GULCH
Figure 14. Shale Oil Complex - Composite Aerial View
37
-------
Environmental Impact Analysis was published by Colony in 1974*. A formal
Draft Environmental Impact Statement, by the Bureau of Land Management was
issued in December 1975**. Hearings on the latter occurred in January 1976.
As of late 1976, final approval of the EIS had not been granted.
The above environmental studies have resulted in a more detailed
disclosure of the TOSCO II process and its proposed control technologies, than
any other U.S. process to date. The technical details available from these
sources have been utilized in this Overview Report together with supplemental
information kindly furnished through contacts with TOSCO personnel.
The technical description of the TOSCO II Process in the sections which
follow is based upon the proposed full-scale 66,000 tons/stream day commercial
plant complex (Figure 14). This includes an underground mine eventually.extend-
ing over 4,000 acres, a retorting and upgrading facility, a processed shale
disposa-1 area, and two water reservoirs. A 40 cm (16 inch) diameter, 310 km
(194 mile) long product fuel oil pipeline (Figure 13)* is proposed to Lisbon
Valley Station, Utah, for eventual connection to a major interstate pipeline
at Aneth, Utah.
UNDERGROUND MINING, CRUSHING
The TOSCO II commercial plant will include conventional underground room-
and-pillar mine (Figure 15), with access by means of seven 9 meter by 9 meter
(30 ft by 30 ft) adits from Middle Fork Canyon. The mine will produce
55,000 metric tons/day (61,000 tons/day) of 145 liters/metric ton (35 gallon/
ton) oil shale, from an 18 meter (60 ft) seam of the upper Mahogany Zone. Some
six 15 meters high by 9 meters wide (50 ft by 30 ft) ventilation openings,
without scrubbers, will be provided for air circulation. The diesel equipment
used underground will utilize mounted catalytic scrubbers. Total hourly
emissions from the mine ventilation system are estimated to average 20 kg parti-
culates (higher during blasting), 22 kg hydrocarbons, 113 kg NOx, and 200 kg CO.
Dust concentrations are estimated not to exceed 4,000 micrograms/cubic meter
(except during blasting).
Primary crushing of the run-of-mine shale will be carried out at the mine
portal bench. The coarse ore product will be transported by totally enclosed
incline conveyor to the final crusher at the plant site on top of the plateau,
275 meters (900 ft) above the mine portal bench. The product from the final
crusher is the minus 1.25 cm (0.5 in) feed for the retorting plant. Particu-
late emissions are estimated to be 3.6 kg/hr from the primary crusher, 5.4 kg/
hr from transfer points, 16.8 kg/hr from the final crusher, and 2.1 kg/hr from
final fine ore (retort feed) storage (or 27.9 kg/hr total).
An Environmental Impact Analysis for a Shale Oil Complex at Parachute
Creek, Colo., Colony Development Operation, 1974.
Proposed Development of Oil Shale Resources by Colony Development
Operation in Colorado, Draft Environmental Impact Statement, Bureau
of Land Management, Dept. of Interior, December 1975.
38
-------
CO
10
Figure 15. Room-and-Pillar Mining Concept
-------
RETORTING AND OIL RECOVERY UNIT
Unlike some U.S. oil shale processes, the TOSCO II/Colony commercial
plant is designed not only to produce shale oil, but also to upgrade it
on-site to produce synthetic crude oil and LPG, with ammonia, sulfur, and
coke as by-products. In addition, a treated fuel gas, a C4 liquid stream,
fuel oil, and diesel oil are obtained for internal plant use. The overall
process flowsheet to carry this out is shown in simplified form in Figure 16.
It is noted that processed shale is the major waste material for disposal.
The heart of the processing sequence is the TOSCO II pyrolysis
(retorting) unit and associated oil recovery equipment. The flowsheet for a
single unit (or "train"), is shown in Figure 17. The commercial plant will be
composed of six such retorting/oil recovery units, each with a design
capacity of up to 10,000 metric tons/day (11,000 tons/day) of raw shale.
The minus 1.25 cm (0.5 in) raw shale from the final crusher is first fed
to a dilute phase fluidized bed, where it is preheated to about 260°C (500°F)
with flue gases from the ball heater (see Figure 17'). The residual hydrocarbons
in the flue gases are simultaneously burned. The cooled flue gases are
separated from the preheated shale, wet-scrubbed to remove particulars, which
are disposed as a sludge (780 metric tons/day - 860 tons/day per train), and
vented to the atmosphere at about 55°C (130°F). The hourly gaseous emissions
from each of the six trains are estimated to be 3.7 kg S02, 99.5 kg NOX»
3.3 kg CO, 20.4 kg total hydrocarbons, and 18.4 kg particulate matter.
The preheated shale is fed to a horizontal rotating retort (pyrolysis
drum), together with approximately 1.5 times its weight in hot ceramic balls
from a ball-heater in order to raise the shale to pyrolysis temperature (900°F)
and convert its contained organic matter to shale oil vapor. The shale vapors
are withdrawn and fed to a fractionator for hydrocarbon recovery. The mixture
of balls and denuded shale are discharged through a trommel, in order to
separate the emerging warm balls from the processed shale.
The warm balls are purged of dust with flue gases from a steam preheater,
and the dust removed from the flue gases by wet scrubbing. Each of the six
10,000 metric ton/day "trains" of the commercial plant will produce some 59
metric tons/day (65 tons/day) of sludge dust for disposal. The scrubbed flue
gases are discharged to the atmosphere. The hourly emissions in the flue gases
from each train are estimated to be 7.2 kg S02, 8.6 kg NOX, 0.2 kg CO, and
16.3 kg particulate matter.
The dust-free warm balls are returned to the ball heater via the ball
elevator. In the ball-heater they are reheated to about 700°C (1300°F), using
in-plant fuel, and recirculated to the pyrolysis drum.
The hot processed shale (denuded of oil) is cooled to about 150°C (300°F)
in a rotating drum cooler and moisturized to about 14% water content with
6,000 liters/minute (1,500 gal/rrrin) per train of NHa, H2S, and C02-free water
from the plant's foul water stripper unit. The wetted shale, at below 93°C
(200°F) is transported to the Davis Gulch disposal site. The steam-dust
mixture produced in the moisturizer is wet-scrubbed to remove dust and
40
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Figure 16. Block Flow Diagram Retorting and Upgrading Units
-------
auE GAS
TO ATMOSPHERE
PREHEAT SYSTEM
STACK
RAW
CRUSHED
SHALE
ro
VENTURI
WET SCRUBBER
WATER.
f*
SEPARATOR
GAS OIL TO GAS OIL
-»• HYDROGENATIOM
UNIT
HYDROCARBON
VAPORS
BOTTOMS OIL TO
DELAYED COKER
UNIT
BALL CIRCULATION
SYSTEM STACK
NTURI
WET
CRUBBER
FROM STE
SUPERHEATER
HOT
PROCESSED
SHALE
MOISTURIZER*
PREHEAT SYSTEM
(INCLUDES INCINERATOR)
* ALL SCRUBBER SLUDGE STREAMS
TO PROCESSED SHALE DISPOSAL
** TO GAS RECOVERY AND
TREATING UNIT
MOISTURIZER
SCRUBBER
STACK
VENTURI WET
SCRUBBER
MOISTURIZED PROCESSED
SHALE TO DISPOSAL
COVERED PROCESSED.
SHALE CONVEYOR
Figure 17. Pyrolysis and Oil Recovery Unit TOSCO II Process
-------
discharged to the atmosphere. Each train discharges 18.4 kg/hr of
participate matter to the atmosphere, and disposes of 39 metric tons/day
(43 tons/day) of dust as wet sludge.
The shale oil hydrocarbon vapors from the pyrolysis drum are separated
into water, gas, naphtha, gas oil, and bottom oil in a fractionator. The
water is sent to the foul water stripper, the gas and naphtha to the gas
recovery and treating unit, the gas oil to a hydrogenation unit, and the
bottoms oil to the delayed coking unit. The upgrading plant is discussed
more fully below.
UPGRADING UNITS
As shown in Figure 16, the upgrading section of the commercial plant
consists of the following units: gas recovery and treating, hydrogen produc-
tion, gas oil hydrogenation, naphtha hydrogenation, ammonia separation, sulfur
recovery, delayed coking and foul water stripping. These upgrading units
process the individual fractionator product streams from all six pyrolysis
and oil recovery trains.
Gas Recovery and Treating Unit
The gas and raw naphtha from the six shale oil fractionators, delayed
coker, and the naphtha and gas oil hydrotreaters are all fed to the Gas
Recovery and Treating Unit (Figure 18), where they are separated into stabilized
naphtha, LPG, butanes, and fuel gas. The stabilized naphtha is sent to the
naphtha hydrotreater. The butanes are used as plant fuel, as is part of the
treated fuel gas. The remainder of the fuel gas is fed to.the hydrogen plant.
The LPG is sent to storage for sale. Acid gas from the amine treaters is sent
to the sulfur unit. Since all streams exiting from the Gas Recovery and
Treating Unit are sent to other units, there are no emissions to the
atmosphere or byproduct liquid effluents.
Hydrogen Unit
Hydrogen is needed for the naphtha and gas oil hydrotreaters to remove
nitrogen and sulfur and saturate olefins. This hydrogen is produced from a
portion of the fuel gas from the gas recovery and treating unit using a con-
ventional steam-reforming process (Figure 19) with the usual nickel- catalyst
plus iron/chromium oxide and copper/zinc shift catalysts. Prior to reforming,
the gas is desulfurized. The normal hourly emissions to the atmosphere from
the reformers are estimated to be 12.4 kg SOe, 37.3 kg NOX, 3.6 kg CO, 5.2 kg
solid particulates, and 0.72 kg total hydrocarbons. In addition, there will
be emitted 98 metric tons/hr (108 tons/hr) of C02 from the carbon dioxide
scrubbers. Spent catalysts will be sent off-site for reclamation or disposed
of in the processed shale pile.
Gas Oil Hydrogenation Unit
The feeds to this unit (Figure 20) are the gas oil streams from the oil
recovery fractionators and the delayed coker unit. These are hydrogenated to
reduce sulfur and nitrogen and saturate olefins. Arsenic is also removed
43
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TREATED GAS
LEAN SPONGE OIL
FROM PYROLYSIS
FRACTIQNATQR _
SPONGE
ABSORBER
RAW NAPHTHA FROM PYROLYSIS
AND COKER FRACTIONATORS _
AND GAS OIL HYDROTREATER f"
Ct AND LTR
GAS
TREATING
COLUMN
.TO FUEL GAS AND
H. UNIT FEED GAS
ACID GAS TO
SULFUR UNIT
REBOILED
ABSORBER STRIPPER
GAS COMPRESSOR
AND AFTERCOOLER
RAW GAS FROM
PYROLYSIS AND COKE
FRACTIONATORS 8
NAPHTHA a 6AS
OIL HYDROTREA-
TERS STEAM
T
RAW
NAPHTHA
STABILIZER
AMINE
REGENERATOR
RICH SPONGE OIL
TO PYROLYSIS
FRACTION ATOR C,/C,
OVERHEAD
LEAN ~"
OIL
RICH OIL
LPG SPECIAL
TO STORAGE
FOR SALES
STABILIZED RAW NAPHTHA
TO NAPHTHA HYDROTREATER
LIQUID
SYSTEM
TO
FUEL
Figure 18. Gas Recovery and Treating Unit
-------
FUEL GAS FROM
GAS TREATING UNIT
COOLER
REFORMERS(2)
CARBON MONOXIDE SHIFT CONVERTERS
HIGH TEMPERATURE
SHIFT CONVERTER
LOW TEMPERATURE
SHIFT CONVERTER
RICH AMINE /SPENT CAUSTIC^
TO REGENERATION / TO DISPOSAL
rx
WATER
tn
/ IN GAS TREATING / /
/ /"NIT / /
HDS AMINE CAUSTIC ZnO GUARD
REACTOR ABSORBER WASH BED
DESULFU
/
•
V
1
RIZATION
LI
vSOL
/ "*
i
:AN
JTION
\
' ^v"
SI
RICH SOLUTION
COt
A.
w
j
n
^T\ /O<^ HYDROGEN TO
i VJ^ )£j HYDROTREATERS
_J
C02 ABSORBER
SOLUTION REGENERATOR
METHANATOR
Figure 19. Hydrogen Unit, Steam Reforming Process
-------
HYDROGEN MAKEUP.
FROM
UNIT
HYDROGEN RECYCLE
HYDROGEN
GAS OIL FROM
PYROLYSIS AND
DELAYED COKER
UNITS
FURNACES
WASH
_ WATER
REACTORS
882fi
BOSS
HIGH PRESSURE
SEPARATOR
fSOUR WATER
I TO AMMONIA
SEPARATION UNIT
OVERHEAD TO GAS
RECOVERY UNIT
LOW PRESSURE
SEPARATOR
OVERHEAD TO GAS
RECOVERY UNIT
NAPHTHA TO GAS
RECOVERY UNIT
FR ACTION ATOR
DIESEL FUEL TO MINE.
AND PROCESSED SHALE
DISPOSAL OPERATIONS
•*-
REBOILER FURNACE
TREATED GAS OIL PRODUCT
TO PIPELINE BLENDING
Figure 20. Gas Oil Hydrogenation Unit
-------
using a proprietary catalyst. The major products are a low sulfur and
nitrogen treated gas oil for sale, and diesel fuel for in-plant use (mine,
and processed shale disposal operations). The gas and naphtha from the
fractionator are sent to the gas recovery unit. Sour water from the washing
operations, containing NH3 and H2S, is fed to the ammonia recovery unit,
where H2$ is removed and sent to sulfur recovery. The hourly atmospheric
emissions from the gas oil hydrogenation unit reboiler furnace are 1.7 kg S02,
5.1 kg NOX, 0.65 kg CO, 0.7 kg particulate matter, and 90 grams total hydro-
carbons. In addition, some 240 kg (531 Ibs) per day of arsenic in solid form
will be discarded on the processed shale disposal pile.
Naphtha Hydrogenation Unit
The stabilized naphtha stream from the Gas Recovery and Treating Unit is
catalytically hydrogenated to remove sulfur and nitrogen and saturate the
olefins present, in the Naphtha Hydrogenation Unit (Figure 21). Prior to
hydrogenation arsenic is removed over a proprietary catalyst. Some 27 kg
(59 Ibs) per day of arsenic are produced, for discard on the spent shale
pile.
The arsenic-free feed is hydrogenated in the presence of an HDN (hydrode-
nitrogenation) catalyst, and the reactor effluent 1s washed with stripped water
from the ammonia separation unit, in order to remove HoS and NHg. The result-
ing sour water is sent to the Ammonia Separation Unit for purification.
The resulting H2$ and NH3~free mixed hydrocarbon stream is sent to an
absorber to remove heavier hydrocarbons. The absorber's
overhead gases are returned to the Gas Recovery and Treating Unit. The
treated naphtha product is blended with the previously mentioned treated gas
oil product to form the low sulfur fuel oil for sale.
The hourly emissions from the Naphtha Hydrogenation Unit are 0.18 kg S02,
0.6 kg NOX, 0.9 kg CO, 0.047 kg total hydrocarbons, and 0.9 kg particulates.
The solid wastes, in addition to the arsenic previously mentioned, include up
to 68 metric tons (75 tons) of spent HDN catalyst annually.
Delayed Coker Unit
In the delayed coker unit (Figure 22) the heavy bottom oil from each of
the oil recovery fractionators is converted into lighter fractions and by-
product coke. The naphtha and gas are returned to the Gas Recovery Unit, the
gas oil is fed to the Gas Oil Hydrogenation Unit, and the condensed water is
sent to the Foul Water Stripper. Approximately 725 metric tons (800 tons)
of coke is expected to be produced daily. Pending establishment of a market
for this coke, it will be stored on the processed shale pile.
The estimated hourly atmospheric emissions from the cracking furnace of
the Unit are as follows: 1.3 kg S02t 3.8 kg NOX, 0.5 kg CO, 0.5 kg particulate
matter, and 90 grams total hydrocarbons.
47
-------
oo
HYDROGEN
MAKEUPr ^
FROM
HYDROGEN
UNIT
STABILIZED
NAPHTHA FROM
GAS RECOVERY,
AND TREATING UNIT
eA]
^^
FURNACE
HYDROGEN
RECYCLE
mm^^m
M^MHM
a
B
1
<. )
WASH
WATER
REACTOR
r
i
/^
\
^\
A
^
c
SEPARATOR
OVERHEAD TO GAS
RECOVERY UNIT
/
| LEAN OIL
^(TREATED GAS
OIL)
ABSORBER
r^ ^T TREATED NAPHTHA
1 PRODUCT _ TO
gUR^WATER TO
PIPELINE BLENDING
MONIA
UNIT
:PARATION
Figure 21. Naphtha Hydrogenation Unit
-------
COKER
FRACTIONATOR
HEATER
BOTTOMS OIL FROM
PYROLYSIS AND OIL
RECOVERY UNIT
to
GAS TO GAS RECOVERY UNIT
NAPHTHA TO GAS RECOVERY UNIT
FOUL WATER TO FOUL WATER STRIPPER UNIT
GAS OIL TO GAS OIL
HYDROGENATION UNIT
HOT VAPORS
FURNACE
AAA
V
COKE
DRUMS
COKE TO STORAGE FOR SALES
Figure 22. Delayed Coking Process
-------
Ammonia Separation Unit
The sour water from the hydrotreaters is treated in the Ammonia Separa-
tion Unit (Figure 23) to remove hydrogen sulfide which is sent to the Sulfur
Recovery Unit. Ammonia i's then removed in an ammonia stripper, and compressed
and cooled to liquid ammonia for sale. Some 122 metric tons (135 tons) of
anhydrous ammonia are estimated to be produced daily. The stripped water is
returned to the hydrotreaters or used to moisturize the processed shale.
There are no expected atmospheric emissions or other effluents from this Unit.
Sulfur Recovery Unit
The acid gases from the Ammonia Separation, Foul Water Stripper, Gas
Recovery and Treating Units are fed to two conventional Claus-type Sulfur-
Recovery trains to convert ^S to liquid elemental sulfur. Some 176 metric
tons (1,94 tons) of sulfur are expected to be produced daily. The tail gases
from the Claus trains are fed to a standard Wellman-Lord sulfur recovery pro-
cess to further reduce their residual sulfur content to approximately 250 ppm
by volume. The S02 produced is recycled to the Claus trains.
There are no air emissions from the Claus trains, but 42.9 kg/hr of SOg
are estimated to be emitted to the atmosphere from the Wellman-Lord processing
unit. Also, approximately 68 metric tons/year (75 tons/year) of spent alumina
catalyst from the Claus trains disposed of on the processed shale pile are
expected.
DISPOSAL OF SOLID WASTES
Some 18,300,000 metric tons (20,200,000 tons)* of solid plant wastes must
be disposed of annually, or an average of 50,000 metric tons (55,000 tons)
daily. Some 97% of this waste, or 48,300 metric tons (53,300 tons) per day,
is processed shale (and its dust). An additional 385 metric tons (425 tons)
per day is raw shale dust. The remaining solids are spent catalyst materials,
sludges, arsenic-laden solids, and processed plant sanitary wastes.
The processed shale is to be transported by closed conveyor to Davis
Gulch (Figure 14) where a processed shale embankment will be created in the
form of a compacted land fill with a typical average density of 1,360 kg/cubic
meter (85 Ibs/cu ft). A drainage system will be provided together with a
catchment basin for run-off.
After final contours are established, contained salts in the top of the
pile will be leached down into the pile, a 15 cm (6 in) layer of topsoil added,
and a revegetation program initiated. The latter will include the requisite
chemical fertilization and irrigation over a period of years to insure a
stable, self-sufficient soil cover of about 45% grasses, 40% shrubs, and
15% forbs.
Figures are given on an equivalent, moisture-free basis, exclusive of the
water content of moisturized processed shale and shale dust sludges.
50
-------
fteS TO SULFUR UNIT
S°UFROMTER TREATING UNIT
HYDROTREATERS /
DEGASSING
SECTION
J
SOUR WATER FEED
STORAGE
NH3 COMPRESSOR
AND AFTER COOLER
H2S
RIPPER
RBONS
0 GAS
JIT
t
^^^^^_
SI
i
STEAM
%
NH3
'RIPPER
i
STE
t
ra.
LIQUID
STORAGE FOR
SALES
H2S-NH3 -RECYCLE
STRIPPED WATER PURGE
TO PYROLYSIS UNIT
STRIPPED WATER
RETURN TO
HYDROTREATERS
Figure 23. Ammonia Separation Unit
-------
SUPPORTING REQUIREMENTS
The proposed commercial plant will require diversion of 0.35 cubic
meters/sec (12.5 cubic ft/sec) of water for consumptive use from the Colorado
River. Two 230 kv power lines must be built (to insure no interruptions) by
Public Service Company of Colorado to satisfy the 100 Megawatt plant opera-
tional load. A 24 km (15 mile) service corridor must be provided in
Parachute Creek Valley, from the plant site southward to Grand Valley,
Colorado, to permit construction of three pipelines (water, ammonia, LPG) and
a two-lane highway. A 40 cm (16 in) diameter product pipeline some 310 km
(194 miles) long to Lisbon Valley Station, Utah is proposed with connections
to a major interstate pipeline at Aneth, Utah.
52
-------
THE LUR6I-RUHRGAS PROCESS FOR OIL SHALE RETORTING
C. C. Shih
Lurgi has been engaged in the development of oil shale retorting
technology for approximately forty years, beginning with the design and
installation of two tunnel kilns in co-operation with an Estonian shale oil
company in the late 1930's. In this design, the oil shale was retorted in
wagonetts which were pulled at short intervals through the tunnel kiln. In
the ensuing years, several other oil shale retorting processes were developed
by Lurgi to commercial stage. These included: a low temperature carbonization
process (the Lurgi-Splflgas kiln); a batch process in which lumpy oil shale was
distilled in retorts by sucking air through it from top to bottom (the Lurgi-
Schweitzer process); a continuous process in which the shale traveled slowly
on an inclined oscillating grate through the retort chamber and was distilled
by air drawn through the shale bed from top to bottom across the length of the
chamber (the Hubofen); and a fluidized-bed process involving the combustion of
fine-grained oil shale for the direct generation of electricity (the
Rohrbach-Lurgi process).
The Lurgi-Ruhrgas process was originally developed by Lurgi in collabora-
tion with Ruhrgas AG in the 1950's for the production of pipe-line quality gas
by the devolatilization of coal fines. The process utilizes circulating solid
heat carriers for retorting and has been applied on the commercial scale for
the devolatilization of lignite fines, the production of char fines for hot
briquetting from subbituminous coal, and the cracking of naphtha and crude oil
to produce olefins. To demonstrate the applicability of the process for the
distillation of oil shale, Lurgi has carried out a number of pilot plant tests
at the Herten works in the Ruhr district of Germany. Two test series with
Colorado oil shale were conducted in 1967 and 1968 when approximately 45
tonnes* (50 tons) of oil shale over a one week period and 220 tonnes (240 tons)
of oil shale over a three week period were distilled. The oil shale charged to
the pilot plant was in the 0 to 0.635 cm (0.25 in) and 0 to 1.27 cm (0.5 in)
size range and had a Fischer assay from 10.2 to 12.6 percent (equivalent to
27-33 gal/ton). The pilot tests showed that at temperatures of about 530°C
(986°F) and optimum throughout feed rates, high oil yields of over 100 weight
percent of those indicated by the Fischer assay could be attained in the
retorting steps.
American Lurgi Corporation and Dravo Corporation have recently presented
a proposal to fourteen major oil shale land owners and leasees seeking indus-
try support of a project to demonstrate the Lurgi-Ruhrgas process at the
3,630 tonnes/day (4,000 tons/day) level, at an estimated cost of $25 to $30
million. The 3,630 tonnes/day demonstration plant is considered by Lurgi to
be a fully commercial-scale module, and a commercial plant would consist of a
1 Tonne - 1,000 kg
53
-------
number of such modules. In the proposed plan, Lurgi estimated that the
demonstration plant could be operational 36 months after project approval.
Lurgi was recently commissioned to provide two 3,630 tonnes/day plants for
the processing of oil shale in Bulgaria. These plants are similar to those
proposed for the processing of Colorado oil shale, except the minor modifi-
cations made to accommodate a different type and grade of shale. In addition,
American Lurgi Corporation and Dravo Corporation have also presented a proposal
for the design, construction and operation of a 907 tonnes/day (1,000 tons/day)
demonstration plant for the Lurgi-Ruhrgas process to smaller companies.
Mining and Crushing
The mining and crushing operations for the Lurgi-Ruhrgas process will be
similar to those for the other above-ground retorting processes. The conven-
tional room-and-pillar method will probably be used for production mining of
the shale. Both primary and secondary crushing of the shale may be performed
underground. Primary crushing will reduce the size of the run-of-mine shale to
minus 20 cm (8 in), and secondary crushing will further reduce the shale size
to minus 6 mm (0.25 in). It may also be noted that fine-grained oil shale
rejected as feed for other retorting processes is ideally suited as feed for
the Lurgi-Ruhrgas process.
Retorting and Upgrading
In the Lurgi-Ruhrgas process, shown in Figure 24, crushed oil shale of
minus 6 mm (0.25 in) size is fed through a feed hopper to a double screw mixer,
where it is intimately mixed with 6 to 8 times its volume of the hot circulat-
ing shale residue at 630°C. The fresh shale feed is heated to 530°C within
a few seconds, resulting in the evolution of gas, shale oil vapor and water
vapor. The circulating heat carrier and the partially retorted, fresh shale
feed are then dropped from the screw mixer into the surge hopper where residual
oil components are distilled off.
The mixture of heat carrier and retorted shale residue is passed through
to the lower section of the lift pipe where combustion air at 400°C is intro-
duced, raising the mixture pneumatically to the collecting bin, and burning
the carbon contained in the retorted shale residue during the transport
process. The heat carrier is now separated from the flue gases in the
collecting bin. The fines are carried through with the flue gas stream,
whereas the coarse grained shale residue accumulates in the lower section of
the collecting bin and flows from there continuously to the mixer. The
combustion air supplied to the lift pipe is preheated by countercurrent heat
exchange with the flue gas stream.
The volatile gas product stream from the retorting of the oil shale is
passed through two series - connected cyclones, and the dust separated in these
cyclones is returned to the recycle system. The gas stream then enters a
sequence of three scrubbing coolers. The first scrubbing cooler is designed
to operate at higher temperature to remove the residual dust from the gas
stream by washing and circulating condensed heavy oil. In the next scrubbing
NOTE: Figure 24 is obtained from Reference 1.
54
-------
CJ1
en
—O I HEAT
^ TEX
EXCHANGER
STACK
WASHING
OIL
RESIDUE MOISTENING
MITH 10X HATER
WATER
BOILER
FEEDHATER
GAS
LIQUOR
WASHING
OIL AND
NAPHTHA
SURPLUS
GAS
Figure 24. The Lurgi-Ruhrgas Process for the Retorting of Oil Shale
-------
cooler, major condensation of the oil takes place at a temperature above the
dew point of water to produce a dust-free heavy oil. Final cooling is by
circulating the condensate in the last scrubbing cooler, after the condensate
has been recooled in air and water coolers. The condensate is separated into
middle oil and gas liquor in an oil/water separator. Finally, the gas is
scrubbed with light oil for the recovery of naphtha.
The flue gas stream evolved in the lift pipe is dedusted in a cyclone
after leaving the collecting bin and then routed through a heat exchanger for
the preheating of combustion air, a waste heat boiler, a feedwater preheater,
another cyclone, a humidifier and an electrostatic precipitator before dis-
charge to the atmosphere. In the humidifier the flue gas stream is cooled from
approximately 320°C to 150°C by water injection, and a portion of the shale
dust contained in the flue gas is separated and discharged to a chain
conveyor. The residual dust is removed from the flue gas stream in the
electrostatic precipitator and discharged onto another chain conveyor. The
two chain conveyors then carry the fine dust from the cyclone, heavy oil dust
from the heavy oil dust removal step, and moistening water to a combined
residue mixer. The final spent shale residue requiring disposal has a
moisture content of 10 to 12% water and a temperature of 65°C.
The dust-laden heavy oil obtained in the first scrubbing cooler is freed
of dust by sedimentation and centrifuging after addition of naphtha to reduce
the viscosity of the heavy oil. The final products obtained include a dust-
free heavy oil, a middle oil, a gas naphtha, and a distillation gas. The
properties of these hydrocarbon products are presented in Table 6 (Reference 1).
However, information on the ash, arsenic, sulfur and nitrogen content of the
liquid products is not presently available from Lurgi. This information is
necessary to the estimation of the type and quantity of waste streams, as well
as the capital investment costs and the utilities requirements associated with
the upgrading of the crude shale oil produced by the Lurgi-Ruhrgas process.
Air, Water and Solid Wastes
The major atmospheric emission stream from the Lurgi-Ruhrgas process
is the flue gas from the combustion of the shale residue. For a 7,950 m^ per
stream day (50,000 BPSD) plant, the amount of flue gas released to the atmos-
phere is estimated to be 724,400 Nm3/hr (27 MMSCFH). In the pilot plant tests
conducted by Lurgi there were only two cyclones available for removing
particulates from the flue gas. As a result, the flue gas discharged from
the cyclones still contained approximately 20 g/Nm3 of particulates with
particle diameter of less than 40 ju (Reference 2). This was equivalent to a
particulate collection efficiency of 95%. In Lurgi's assessment, particulate
collection efficiencies of up to 99.98% are achievable by the addition of
electrostatic precipitators based on the measurement of the electrical
resistance of the particulates in the flue gas atmosphere and temperature dur-
ing the pilot plant tests and Lurgi's experience with over 300 commercial
electrostatic precipitator installations. In the pilot plant tests, it was
also found that the S02 content of the flue gas was only approximately
30 mg/Nm3 (10.5 ppm). This was probably because the major portion of the S02
released during combustion was recaptured by the CaO and MgO formed and dis-
charged with the retorted shale. NOx measurements of the flue gas were not
56
-------
Tabl e 6. JPrope.Cl^s
a) Heavy Oil (dust free):
Density(50oc)
V1scosity(50oc)
Flash point
Settling point
Conradson test
Initial boiling point
(at 760 Torr)
b) Middle Oil:
Density(20oc)
Viscosity
Flash point
Settling point
Conradson test
Initial boiling point
(at 763 Torr)
Final boiling point
(at 763 Torr)
kg/1
cP
°C
°C
wt%
°C
kg/1
cP
°C
°C
wt%
°c
°C
c)
0.954
98
153
24
8
130
d)
0.818
1.25
<+20
<-40
0.42
70
283
Gas Naphtha:
Density(20ocj kg/1
FIA analysis:
Aromatics and
diolefins vol%
Olefins vol*
Paraffins vol%
Initial boiling point °C
(at 738 Torr)
Final boiling point °C
(at 738 Torr)
Distillation Gas (Naphtha Free)
Net calorific value kcal/Nm3
Composition:
C02 vol% 28.8
CO vol% 3.1
H2 vol% 21.3
N2 vol% 8.9
Ci vol% 13.7
Co vol% 13.8
£>
C3 vol% 10.3
H2S g/Nm3 2.28
S0« g/Nm3 0.07
0.699
84.4
1.7
13.9
36
137
7,150
57
-------
made during the pilot plant tests. Measurements on the combustion products
from a commercial fluidized-bed oil shale combustion plant (the Rohrbach-Lurgi
process) in South Germany, however, indicated that the combustion product con-
tained only approximately 100 ppm of NO and no detectable N02. Since the
fluidized-bed combustion 'of the oil shale took place in an oxidizing atmos-
phere and at a much higher temperature (approximately 800°C) than the
combustion temperature of the shale residue in the Lurgi-Ruhrgas process
(below 700°C), the NOX content of the flue gas stream from the Lurgi-Ruhrgas
process is expected to be lower than 100 ppm.
The major liquid waste stream from the Lurgi-Ruhrgas process is the gas
liquor produced in the distillation of the oil shale. The rate of gas liquor
production is estimated to be 38.53 m3/hr (170 gpm), for a 7,950 m3 per stream
day (50,000 BPSD) plant. The gas liquor contains minor amounts of ammonia,
oil and phenols, and is used for cooling and moistening of the spent shale.
Lurgi indicates that the minor contaminants present in the gas liquor will be
absorbed by the shale residue without posing an environmental problem. For
this reason, treatment of the gas liquor by oil separation and by stripping
to remove the ammonia and hydrogen sulfide components, has not been included
in the Lurgi process scheme.
The major solid waste streams from the Lurgi-Ruhrgas process include the
heavy oil dust discharged from the dryer in the heavy oil dust removal step,
and the retorted shale. For a 7,950 m3 per stream day (50,000 BPSD) plant,
1,270 tonnes (1,400 tons) of heavy oil dry dust and 39,700 tonnes (43,770 tons)
of retorted shale are generated per day. The heavy oil dust is almost com-
pletely free of oil and can be dumped together with the retorted shale after
moistening water and the gas liquor are added to increase the moisture content
of the retorted shale to approximately 10%. At the present time, Lurgi has not
provided any information on the detailed characterization of the gas liquor and
the shale residue.
Oil Shale Retorting Products and Utilities Requirements
For a commercial size plant processing 51,377 tonnes (56,633 tons) of
35.7 gpt oil shale per stream day, the Lurgi-Ruhrgas process will generate the
following products.
Shale Oil: 7,950 m3/(50,000 bbl) per stream day
Make Gas (naphtha free): 47,780 Nm3/hr (1.78 MMSCFH)
Retorted Shale (dry basis): 40,970 tonnes (45,160 tons) per stream day
Waste Wa'ter (contained in the spent shale residue): 183 m3/hr (806 gpm)
The total water consumption rate is estimated by Lurgi to be 334 m3/hr
(1,470 gpm) and the power requirement to be 28,770 kw (Reference 2). The fuel
requirement for the retorting of the oil shale will be met by the combustion
of the retorted shale residue. It may be noted that the mining and crushing of
the oil shale, the recovery and treatment of the make gas, and the upgrading
of the crude shale oil product are not included in the estimation of the
utilities requirements provided above.
58
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REFERENCES
1. Schmalfeld, P., The Use of the Lurgi-Ruhrgas Process for the Distillation
of Oil Shale, Quarterly of the Colorado School of Mines, 70 (3): 129-145,
July 1975.
2. Development of the Lurgi-Ruhrgas Retort for the Distillation of Oil Shale,
Lurgi Mineraloltechinek GMBH, Frankfurt (Main), October 1973.
59
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SUPERIOR OIL SHALE PROCESS
Charles H. Prien
The Superior Oil Shale Process is unique among current, potential indus-
trial U.S. shale processing methods in two respects, i.e.,its recovery of
saline minerals and its use of a circular grate retort. Superior has 2645
hectares (6500 acres) of private shale holdings on the northern edge of
Colorado's Piceance Creek basin (Figure 25). The tract contains substantial
quantities of the saline minerals nahcolite (NaHC03> and dawsonite (NaAl
in addition to oil shale. Most of these saline minerals occur in the Lower
Zone of the Parachute Creek member of the Green River Formation, 500-760
meters (1700-2500 ft) below the surface.
UNDERGROUND MINING, CRUSHING, NAHCOLITE RECOVERY
A porous, highly fractured "leached" zone, located above the Lower Zone
oil shales and their associated saline minerals, is at present filled with
strongly saline water. Sinking a vertical shaft through this zone to the
underlying deep oil shale strata and its associated saline minerals does not
appear economically desirable. Superior proposes instead to drive a 9° in-
cline adit some 4 kilometers (2.5 miles) long from the surface to the 610
meter (2,000 ft) deep shale beds, beginning at a surface outcrop point outside
the area of the "leached" zone aquifer (Figure 26). This incline adit with a
cross-section of 3.6 meters by 6.1 meters (12 ft by 20 ft) would be below the
•dish-shaped "leached" zone strata, and would therefore reach the lo.wer oil
shale zbne without the necessity of passing through the aquifer.
Multi-level underground mining at a rate of 22,700 metric tons/day
(25,000 tons/day) will be done using the room and pillar method. In order to
provide protection against unforeseen leakage, especially from the "leached"
zone aquifer some 155 meters (510 ft) or more above the mining zone, the mine
rooms will be grouped into a series of "panels" or cells 460 meters x 820
meters (1,500 ft x 2,600 ft) (Figure 27)with each cell enclosed entirely (ex-
cept for an entrance.) by a rib pillar (barrier wall). Panels within a level
will be aligned with corresponding panels in levels above and/or below. In
the event of excessive water leakage into a cell it can thus be sealed off
from the balance of the mine.
Nahcolite producing levels will be mined with an estimated face height
of 12 meters (40 ft). Oil shale levels with little or no nahcolite will have
an estimated height of 60 feet. Approximately 55-65% of the mineable zone is
Note: Illustrations are from Weichman, B., Colorado School of Mines Quarterly
69_, No. 2, 25-44 (1974); and Superior Oil Company.
60
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R 100 W
R 99 W
R 98 W
R 97 W
R 96 W
R 95 W
R 94 W
THE SUPERIOR OIL COMPANY
STRUCTURE CONTOUR MAP
CONTOURED ON TOP OP THE GARDEN SULCH MEMBER,
C.l. 500' I 1
8. WEICHMAN I I SUPERIOR LAND
OIL SHALE OUTCROP
I
CROSS
SECTION
R'O_BLANCO CbilNTr
GARRIELO COUNTY"
I
R 100 W R 99 W
R 98 W 6 R 97 W R 96 W R 95 W R 94 W
Figure 25. Structure Contour Map.
-------
SOUTH OUTCROP
NORTH OUTCROP
ro
Elevation
above Sea
+8000
+6000
+4000
OVERBURDEN
Elevation
above Sea
+ 8000
+ 6000
NAHCOLITE
+ 4000
36 MILES
Figure 26. Schematic Cross Section of the Parachute Creek Member Showing Three Zones in Oil Shale.
-------
CO
I
w
0
000000
000000
000000
000000
0
000
000000
.— ACCESS OPENING
000000
0 0 0 0 0 0
000000
0000
0 0 0 E
0 0 0 E
0 0 0 0 0 0
000000
0 0 0 0 0 0
000000
000000
0 0 0 0 E^0
000000
000000
0 0 0 E
0 0 0 [
000000
0
0
0
0
000000
000000
000000
000000
0 0 12 0 0
00000
00000
00000
000000
0 E3 0 0 0
•00000
00000
00000
00000
0 E3 0 0 0
00000
00000
00000
00000
00000
00000
00000
00000
00000
00000
00000
0.
'/w
I
Figure 27. Typical Mine Panel Showing Spent Shale Return.
-------
expected to be removed for processing, depending upon the depth of the mine
below the surface and the percentage of nahcolite in the shale. A typical
mine-run raw shale from a nahcolite producing level as fed to the crushers is
expected to average 20% nahcolite and 10% dawsonite.
Crushing
Primary crushing of the mine-run shale to minus 20 cm (8 in) will be done
underground. Secondary crushing to minus 7.5 cm (3 in) size in Hazemag im-
pact crushers can be done either.underground or at the surface. Fugitive
dust from the crushers will be removed by bag filters.
Eighty percent to 95% of the raw nahcolite will be separated from the
shale by secondary crushing and screening. Upgrading of the nahcolite-rich
fractions may be accomplished by photo-reflectance sorting. The nahcolite
remaining in the shale is allowed to continue through the retorting process
where it is calcined to soda ash and recovered in the subsequent leaching
operations.
Retorting and Partial Refining
The three raw shale streams are fed to a travelling circular grate re-
tort (Figure 28). The finest material, minus 25 mm plus 6 mm (minus 1" plus
V), is laid down first on the grate, followed by the minus 50 mm plus 25 mm
(minus 2" plus l"))intermediate fraction, and on top by the coarsest fraction,
minus 7.5 cm plus 5 cm (minus 3" plus 2"). A commercial sized retort is esti-
mated to be 56 meters (185 ft) in diameter with a capacity of 20,900 metric
tons (23,000 tons) of feed per day. The bed depth of shale is expected to be
some 135 cm (54 in). The retort would be gas-tight by virtue of simple but
very effective water seals (Figure 29). An airlock system for loading raw
shale and a water-sealed (airlock optional) dump system precludes exit of re-
tort gas to the atmosphere.
The doughnut-shaped retort (Figure 30)is divided into five separately
enclosed sections,- viz a loading zone, a retorting zone, a residual carbon re-
covery zone, a cooling zone, and to complete the circle, an unloading zone
adjacent to the original loading sector. In a typical operation the prepared
bed of shale loading on the travelling grate passes first into the retorting
zone, where the shale is contacted by a stream of hot (neutral or reducing)
gases. The hot gases are drawn downward through the bed where they heat the
shale to retorting temperature. The oil-vapor-laden gas mixture leaves the
bed and passes to a separator-condenser system to remove the product shale
oil. The oil-denuded and cooled recycle gases then pass through the retorted
shale bed in the cooling zone of the retort to cool the shale before dumping,
and then directed to the combustion zone.
The retorted shale travels from the retorting zone to the residual car-
bon recovery (or combustion) zone where it is contacted with steam and air to
form producer gas by reaction with the carbon residue. This producer gas pro-
vides fuel for the utility plant.
64
-------
en
Figure 28. Artist's Conception of Circular Grate Retort.
-------
SHALE BED
.-- HOOD
- — ' WATER SEALS
SUPPORTING
IDLER WHEEL
Figure 29. Cross Section of Circular Grate Retort.
(Courtesy Arthur 6. McKee & Co.)
66
-------
Figure 30. Plan View of Circular Grate Retort Showing Movement of Charge
thru Various Zones.
67
-------
The retorted shale travels to the retort cooling zone where its tempera-
ture is reduced. It then moves to the unloading zone where it is discharged
from the retort and sent to the leaching plant for recovery of alumina and
soda.
The product shale oil,23BOcu meters/day (15,000 bbl/day) from a 18,100
metric ton/calendar day (20,000 TPCD) total plant input, is expected to have
a gravity of 26° API and a pour point of 21°C (70°F). It typically contains
2% nitrogen and 0.8% sulfur without further treatment. It has been proposed,
however, that the sulfur content can be considerably reduced by including
crude nahcolite with the dawsonitic shale fed to the retorting zone. If this
is not done the sulfur could be removed in subsequent processing.
The only energy produced off site and consumed in the process is elec-
trical energy.
Alumina and Soda Ash Recovery
During the retorting of the dawsonitic oil shale, the dawsonite present.
is converted to alumina and sodium carbonate:
2NaAl(OH)C0 heat
23 23 23 2 2
This reaction occurs between about 370°C and 670°C (700°F and 1240°F).* Pre-
cise temperature control is necessary to optimize the solubility of the alum-
inum oxide.
The residual nahcolite in the raw shale is calcined during retorting to
soda ash:
/
heat > Na2C03 + C02 + H20
which also remains in the spent shale.
In order to recover the aluminum and sodium compounds, the cooled spent
shale from the retort is crushed and fed to countercurrent decanters where it
is dissolved in an alkaline leach solution. Recirculated carbonate liquor
and make-up water from the "leached" zone form the leach solution. Sodium
hydroxide may be added to adjust the pH.
The alumina in the spent shale is solubilized by the caustic solution to
sodium aluminate:
A1203 + 2NaOH - » 2NaA102 + H20
After leaching, the spent shale is washed, separated from the liquor and re-
turned to the mine for disposal (see following paragraph).
*Shale retorting temperature is 425-480°C (800-900°F)
68
-------
After filtration, the highly saturated sodium aluminate liquor is nucle-
ated and carbonated to precipitate alumina trihydrate:
2NaA102 + C02 + 3H20 > Na2C03 + A1(OH)3
The insoluble A1(OHJ3 is filtered from the carbonate-rich liquor and the crys-
tals sent to a calciner for conversion to cell grade alumina:
2A1 (QH)3 heat > A1203 +' 3H20
The carbonate-rich liquor is decolorized and then fed to a multiple-effect
evaporator to remove the water and produce soda ash crystals (Figure 31). These
are centrifuged from the mother liquor and dried for sale. Impurities in the
recovery system circuit are periodically purged, and the purged solution is
added to the spent shale for underground disposal. The water vapor from the
evaporators is recovered as pure water by condensers for use wherever high-
grade, potable water is needed.
Processed Shale Disposal
In the Superior multi-mineral process, over 40% of the original mined
volume of rock is "consumed" in producing shale oil, alumina, soda ash and
nahcolite. As a result of the volume reduction, all of the remaining process-
ed shale can be returned underground, thus eliminating both surface distur-
bance due to spent shale discard piles and the need for revegetation.
Superior proposes to return the leached shale to the mine as a wet cake
on the flip side of the production conveyor. An underground slurry plant
would prepare the shale for emplacement. The slurry water will be recycled
to and from the slurry plant with make-up water obtained from the "leached"
zone aquifer.
The slurry is pumped into the underground "rooms" between the pillars
(Figure 27^ and allowed to drain to approximately 25% moisture content. Be-
cause of the dipping beds, the slurry can be emplaced to the ceiling by stra-
tegic withdrawal of the slurry discharge pipe as the room fills. Refilling
the mine with processed shale will eliminate pillar spa!ling, lateral creep,
and post-mining fracturing.
Water Requirements
The Superior multi-mineral process will produce the following products
from 22,220 metric tons/day (24,500 TPD) of mined shale:
Shale oil-.1600 to 2380 cu meters/day (10,000 to 15,000 bbl/day)
Nahcolite: 4,360 metric tons/day (4,500 tons/day)
Cell Grade Alumina: 455-725 metric tons/day (500-800 tons/day)
Soda Ash: 725-945 metric tons/day (800-1,300 tons/day)
69
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Na2C03 RICH
LIQUOR
MULTIPLE EFFECT
CRYSTALLIZERS
DECI
PERIODIC PURGE*
TO SPENT SHALE
CONDENSER
CONDENSED
WATER
SODA ASH « VAV**^ CENTRIFUGE
Figure 31. Conceptual Design Soda Ash Plant.
-------
Total net consumptive water required for this production is estimated by
Superior to be 4,760 metric tons (1.26 x 106 gal) per day, plus the additional
generation of 3,540 metric tons per day of condensed water (make condensate)
available for fresh water use. Of the 4,760 metric tons per day that is con-
sumed, 3,475 metric tons per day (73%) is used for spent shale disposal, and
1,285 metric tons per day (27%) is consumed or evaporated in chemical pro-
cessing.
All water requirements will be satisfied by the 27°C (80°F) saline water
in the "leached" zone, including plant cooling wateY. After use, the 49°C
(120°F) return cooling water, unaltered in chemical composition, would be in-
jected back into the aquifer, possibly at a point of equal temperature and
equal salinity. The cooling water recycled back into the "leached" zone aqui-
fer represents 75% of the total daily water demand required to sustain the
Superior process.
71
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USBM GAS COMBUSTION PROCESS
Charles H. Prien
The Synthetic Fuels Act of 1944 authorized the construction and operation
of demonstration plants for synthetic fuels, including oil shale. Under the
Act, a number of experimental retorting systems were developed and tested at
the U.S. Bureau of Mines Oil Shale Experiment Station at Anvil Points, Colo-
rado. The most successful of these was the Gas Combustion retort which is the
subject of this Overview Report.
BACKGROUND
The gas combustion retorting process evolved from studies begun by the
Bureau of Mines at Anvil Points in mid-1949. Previous retorting concepts
tested had included the old NTU design, a Royster low temperature type, and
a cross-flow configuration.
The initial gas combustion design was an internally-heated dual flow
pilot unit 51 cm (20 in) I.D. by 3.5 meters (11.5 ft) high.with downward grav-
ity flow of raw shale. Heat was produced by burning a combination of recycled
retort gases and the carbonaceous residue on the spent shale.
The recycle gases and air entered the bottom of the retort and were pre-
heated by downflowing hot spent shale. They then passed upward into a combus-
tion zone. The resulting hot combustion gases were withdrawn from the retort
at the top of the combustion zone (prior to entering the retorting zone), and
bypassed to the top of the retort where they passed downward in co-current
flow with the raw shale, preheating and then retorting the shale. The result-
ing retort gases and shale oil mist were withdrawn from the retort at the
bottom of the retorting zone, the product oil condensed, and a portion of the
denuded gases recycled and returned to the retort vessel.
The next step in development was a change to complete countercurrent
flow between descending shale and upward flowing recycle gas/combustion gases
without the mid-retort withdrawal of combustion gases in the previous design.
The recycle gas and air entered the bottom of the retort where the gases were
preheated and almost immediately ignited, and passed upward through the com-
bustion zone, retorting zone, and shale preheating zone.
Because the combustion zone was near the bottom of the retort, the spent
shale was discharged at fairly high temperatures (2880C to 315°C9 550°F to
600°F) with subsequent loss of sensible heat. This suggested introducing the
air for combustion higher in the retort, thus moving the combustion zone up-
ward and increasing the depth of the gas preheating zone beneath. The result
72
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was the gas combustion concept (Figure 32). The concept was modified in later
developments to include diluting the air with a portion of the recycle gas,
in order to avoid severe clinkering in the vicinity of the air distributors
(Figure 33).
Evaluation runs were made in the 51.cm (20 in) I.D., 5.4 tonnes/day (6
tons/day) pilot plant, under a variety of operating conditions, over a period
of 5% years. The unit served as a testing device for the larger retorts which
followed.
A 22.7 tonnes/day (25 ton/day) rectangular gas combustion pilot unit was
next constructed with inside dimensions of 71 cm by 122 cm (28 in by 48 in).
This was later scaled-up to a 136 tonnes/day (150 tons/day) engineering-scale
plant (Figure 34) using a rectangular, refractory-lined retort with an inside
cross-section of 1.8 meters by 3.0 (6 ft by 10 ft). Mass flow rates of approx
.imately 1470 kg/hr/sq meter (300 Ibs/hr/sq ft) were attained in these larger
retorts before the Bureau of Mines discontinued its 12 year experimental pro-
gram at Anvil Points in 1956.
Between 1964 and 1967 a consortium of six petroleum companies* leased
the Anvil Point facilities and continued development of the gas combustion
concept. Between May 1964 and April 1965 investigations were conducted under
"Stage I," using the 6 TPD and 25 TPD pilot units previously described. This
was followed by completely rebuilding and operating the 150 TPD experimental
retort during the "Stage II" period, April 1966 to September 1967.
Throughput rates of 327 tonnes/day (360 tons/day corresponding to mass
flow rates of 2445 kg/hr/sq meter (500 Ibs/hr/sq ft) cross-section were attain-
ed prior to completion of the experimental program. Shale oil yields were
83-87% of Fischer assay.
It was concluded that commercial scale-up of the modified gas combustion
retort configuration, as tested by the consortium, would be "restricted with-
in rather narrow (operating) limits." Specific difficulties were encountered
with small shale sizes, high rates of gas and shale throughput, and bridging
due to rich shales. As a result there are no present plans to scale-up the
USBM modified gas combustion process, per se, to a commercial-size module.
However, the Paraho/DEI version of the combustion retorting concept has been
designed to overcome the above limitations and to be expanded to commercial
size.
MODIFIED GAS COMBUSTION PROCESS
The description of the Gas Combustion Process given below is based upon
the modifications developed at Anvil Points fay the six company consortium
during the period 1964 to 1967. The earlier designs of the U.S. Bureau of
Mines have been published by Matzick, et al (Reference 1) (see list of Refer-
ences at the end of this report) and are not repeated here.
*Mobil, Humble, Pan American, Sinclair, Phillips, Continental
73
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RAW
SHALE
PRODUCT
COOLING
ZONE
RETORTING
ZONE
COMBUSTION
ZONE
HEAT
RECOVERY
ZONE
LIQUID
PRODUCT
' A ^
•*•*• /\ \
•-t J V .. ..**—
PRODUCT
GAS
RECYCLE GAS
RETORTED
SHALE
*from Cramer, R. H., et al, "Evaluation of Pilot Plant Results from Gas-
Combustion Retorting of Oil Shale," preprint, AIME Meeting, Washington,
Q.C., February 19, 1969.
Figure 32. Conceptual Process Flow Diagram.*
74
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OIL 9HALC
ELECTROSTATIC
fRCCIMITATOR
PROCESSED
SHALE
200'F
(product
cooling zone)
(retortincj zone
(combustion
s zone)
(0ft
(heat recovery
zone)
130°F
AIR
Diluent
Gas
RECYCLE CAS
,
100
8TU/CF
PRODUCT
CAS
Figure 33. Gas Combustion Retort.
75
-------
*from Clarnpitt, R. L., et al, preprint,
161st Nat. Mtg. ACS, Los Angeles, March 29, 1971
Figure 34. USBM 150 ton/day Gas Combustion Retort.*
76
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Underground Mining, Crushing
Initial mining operations by the consortium at Anvil Points utilized the
USBM demonstration mine. Some 31,700 tonnes (35,000 tons) of shale were mined
before it was determined that better safety and mining research conditions
existed on a nearby Mobil oil shale property. A new experimental mine was
accordingly opened and used for the duration of the research program.
Shale from the experimental mine at approximately 2440 meters (8000 ft)
altitude was trucked to the processing area at an elevation of about 1,830
meters (6,000 ft). At the plant site the mined shale was crushed in the pri-
mary and secondary circuits of the USBM crushing plant and screened into var-
ious feed-size ranges for the 136 tonnes (150 ton/day) modified gas combustion
retort. The 10-15% fines from screening were stockpiled.
Feed size range was one of the variables examined during the experimental
program. The two longest demonstration runs were attained with shale feeds
with a nominal range of 2.5 to 6.4 cm (1 to 2% in) and 6 mm to 6.4 cm (% to 2%
in).
Retorting
A flow diagram of the modified 15J3 ton/day gas combustion retorting pro-
cess is shown in Figure 35. The refractory-lined rectangular retort (Figure 34)
was 1.8 meters (6 ft) by 3.0 meters (10 ft) cross-section, with a shale bed
height of 1.1 meters (3.7 ft) to 4 meters (13 ft). The raw shale feed varied
in richness from 97.8 liters/tonne to 130.6 liters/tonne (23.5 to 31.4 gal/
ton). It entered the top of the retort in the usual way, through a rotating
chute and passed downward through the conventional gas combustion product
cooling zone, retorting zone, combustion zone, and heat recovery zone. The
spent shale, at about 55°C (130°F), was discharged through a single-level
drawoff device and sent to a disposal pile in an adjacent canyon. It contain-
ed 2-3% organic carbon.
During the operating phase of the consortium's experimental program mass
shale flow rates in the 150 TPD retort were varied from 1247 to 2494 kg/hr/sq
meter (255-510 Ibs/hr/sq ft) retort cross-section. Air rates ranged from 121
to 255 cubic meters/tonne (3,880 to 8,200 ft3/tonK recycle gas rates from
312 to 550 cubic meters/tonne (10,000 to 17,600 ffrvton), and dilution gas
rates from 0 to 94 cubic meters/tonne (0 to 3,020 ft^/ton). Some 132 runs
were completed in the 150 TPD retort. Most were of 8-12 hours duration but
several demonstration runs varied from 10 to 17 days total in 2 to 5 day
increments.
The air distributor headers were oriented perpendicular to the recycle
gas headers in order to reduce recycle gas channeling. It was found that the
number and location of air injection points was a strictly empirical matter
if clinker formation was to be avoided.
The oil recovery system was modified to include a multiclone separation
unit for removal of large shale mist particles and an electrostatic precipita-
tor for very small particle removal. The efficiencies of these separation
77
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Row shole
Sample
crusher
8-stoge
splitter
Sample
Ra* shale
reject
Bucket
elevolor
7-stage
splitter
Sample
Raw shale
sampler
r (6,000 Ib/doy)
J^S Vibrating feeder
3 Pocket leeder
Recycle gas
blower suction
Spent shale
reitcl
- Spent shole sampler
(3,000 Ib/doy) Gas sample
Line
skimmer
Scrubber
*from USBM Rept. of Investigations #7540 (July 1971).
Figure 35. Flow Diagram of 150 TPD Modified Gas Combustion Retort and
Auxiliaries?
78
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units was a function of shale rate, shale particle size distribution, and re-
tort gas rates. The product oil obtained was fed to a decant tank to separate
the water of retorting. Total water yields varied between approximately 25
and 45 kg/tonne (50 and 90 Ibs/ton) of shale processed, from shale of 104 to
125 liters/tonne (25 to 30 g'al/ton) richness. Oil yields were in the range of
82.5 to 86.6% of Fischer assay.
Demonstration Runs
Included in the 1966-67 operation of the 150 TPD modified gas combustion
retort by the six company consortium were two demonstration runs. The first
of these, using 2.5 cm to 6.4 cm (1 in to 2% in) raw shale, was of 10 days
duration divided into two five-day increments, each with somewhat different
operating conditions. The parameters for one of these 5-day runs is shown in
Table 7. Also shown in Table 7 are parameters for one of the five-day incre-
ments from a 17-day demonstration run which used a 6 mm to 6.4 cm (% in to 2%
in) shale feed.
Table 7. Selected Demonstration Run Results Modified Gas Combustion Process*
Shale Feed Size, inches
Item 1 to 2.5 0.25 to 2.5
Raw Shale, GPT 25.5 29.4
Operating Conditions
Shale Feed Rate, Ibs/hr/ft* 400 301
Air Rate, SCF/ton 4,600 4,250
Recycle Rate, SCF/ton 14,500 13,200
Retorted Shale Temp., °F 374 496
Products Recovered
Oil Yield, vol % Fischer Assay 86.6 85.6
Oil Gravity, ° API 20.1 20.5
Total Water Yield, Ibs/ton 76 55.2
Dry Gas Yield, SCF/ton 6,050 5,800
Dry Gas Heating Value, Btu/SCF ca 100 ca 100
Avg. Spent Shale Organic Carbon, % 2.1 2.5
Mineral Carbonate Decomposed, % 38.2 23.8
Duration of Operating Conditions, days 5 5
Total Duration of Run, days 10 17
*Adapted from Clampitt, R. L., et al, "Gas Combustion Retorting Perfor-
mance in a Large Demonstration Retort," 161st National Meeting ACS,
Los Angeles, March 29, 1971.
79
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It is noted from the table that the API gravity and yields of shale oil
were essentially the same in the two cases even though the mass throughput
rate of the finer shale was less. The residual organic carbon on the spent
shale from the +V to 2%" feed was somewhat higher. This could reflect a
higher retorting temperature and the higher spent shale discharge temperature
noted, except for the fact that mineral carbonate decomposition was substan-
tially lower for the finer shale run. It is felt that the high shale dis-
charge temperatures and the large mineral carbonate decompositions noted would
both have to be considerably less than shown, for any practical commercial
retort, in order to increase process heat economy.
Retort water yields, 2.8 to 3.8% of shale feed (equivalent to 27.5-37.8
liters/tonne or 6.6-9.1 gals/ton), are in the usual range previously reported
for USBM gas combustion retorting. The analysis of these waters was not mea-
sured nor was the plant air emissions.
It was concluded from the consortium's experimental test program that
"substantial modifications to the (gas combustion) process would probably have
to be developed and tested in order to extend the operating range and yields
much beyond those demonstrated," and that this would require considerable
further prototype-size testing before scale-up to a commercial module.
ENVIRONMENTAL IMPACTS
All pilot plant research and demonstration programs carried out on the
USBM Gas Combustion process were completed by September 1967, more than two
years before the National Environmental Policy Act of 1969 or the subsequent
Clean Water and Clean Air legislation. It is therefore not surprising that
little or no data are available from these programs on spent shale character-
istics or disposal methods, air emissions, liquid effluents, or other environ-
mental impact factors. Any assessments of the process in this regard must be
based pn extrapolations from other (similar) retorting methods, or theoreti-
cally computed.
The Paraho direct-mode process is a variation of the USBM Gas Combustion
process, and hence the most similar to the latter. It is to be noted, however,
that the Paraho process is, itself, still under development and that environ-
mental data are still limited since they are presently still being determined.
Some conclusions as to gas combustion process environmental characteristics
are possible, however, by analogy with Paraho direct-mode retorting.
Retorted Shale
It is noted in Table 7 that organic carbon on the gas combustion (GC)
retorted shale varies from about 2 to 2.5% which is similar to the 2% carbon-
aceous residue on the Paraho shale. The GC retorted shale might therefore be
expected to have the same disposal characteristics as Paraho shale. Among
these are:
(1) Size range essentially unchanged from raw shale feed distribution.
(2) Compaction to from 1410 to 1570 kg/cu meter (88 to 98 Ibs/cu ft)
density in a disposal pile, with 22-23% moisture
80
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(3) Soluble salts content in the order of 2% with a pH of
approximately 8.8 to 11.0 and electrical conductivities
of 5-20 mmhos.
(4) Surface layers of disposal piles should be leached prior
to revegetation.
Retort C&ses
The GC retort gases have heating values in the order of 890 kcal/std cu
meter (100 Btu/SCF). On a dry basis they contain from 22-25% 002, 61-63% N2,
2-3% CO, and 2-5% H2. The hydrogen sulfide and ammonia contents have not
usually been measured"1" but can be expected to be similar to those for Paraho
direct mode retort gases, which are reported in one case to be 2660 ppm H2S
and 2490 ppm NH3. The sulfur (and ammonia) in the product gases would require
reduction prior to combustion as a plant fuel.
Retort Water
An analysis of the retort water separated from GC shale oil has been re-
ported in the literature, as shown in Table 8. It is noted that ammonia con-
tents are 12.4 g/1 (vs. 4.9 g/1 for Paraho retort water), chloride is 5.4 g/1
(Paraho: 5.3) and total nitrogen is 10.2 g/1 (Paraho: 4.6). The pH of 8.8 is
similar to that for Paraho water (7.6). The GC water will probably be used
to moisten the spent shale disposal pile.
Table 8. Analysis of Gas Combustion Retort Water*
Components Concentration
(grams/liter)
Ammonia 12.4
Sodium 1.0
Carbonate 14.4
Total Carbon 18.5
Chloride 5.4
Ni trate Trace
Total Nitrogen 10.2
Sulfate 3.1
Sulfur, non-sulfate 1.9
pH 8.8
*From Synthetic Fuels Data Handbook, Cameron Engineers,
Denver, 1975, p 101.
fThere is one literature value of 1000 ppm H2S from unpublished USBM data.
81
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Shale Oil
A typical analysis of the shale oil obtained by the consortium from the
modified Gas Combustion retort is shown in Table 9. It is noted that the
properties are similar to those for conventional shale oils from internally-
heated retorts involving direct combustion for heating. A typical direct-
mode Paraho shale oil, for example, has a pour point of 29°C (85°F), vs. 8QOF
for GC oil and an API gravity of 21.4°, vs. 19.7 for GC oil.
Table 9. Properties of Shale Oil from Modified Gas^tombustjion Retort
(dry basis) —— "
API Gravity, ° 19.7
Pour Point, °F 80
Viscosity, SUS, 100°F 256
Sulfur, wt % 0.74
Nitrogen, wt % 2.18
Carbon Residue, wt % 4.5
(calc'd from residuum)
*From Ruark, J. R., et al, USBM Rept. of
Investigation #7540 (1971).
50,000 BPD COMMERCIAL PLANT
Katell and Wellman (Reference 5) have presented economic analyses of
several commercial-scale oil shale plants utilizing the Gas Combustion Process.
The study must be considered of a preliminary nature since it is evident from
the previous sections of this report that additional research and development
will be required in mining, processing, and environmental controls technology
before the reliability of such extrapolations is insured. However, the order-
of-magnitude results are of interest.
Some highlights of this study are presented below for a plant producing
7,940 cubic meters/calendar day (50,000 BPD) of partially refined (hydrofined)
shale oil, from 71,290 tonnes/day (78,600 tons/day) of raw shale with a rich-
ness of 125 liters/tonne (30 GPT). Included in the technology are an acti-
vated carbon unit for removal of H2S and a slurry system for spent shale dis-
posal, neither of which has ever been tested in actual operation. The econom-
ic data are in mid-1973 dollars and hence require considerable escalation to
reflect present-day costs, selling prices, etc.
The plant is estimated to produce, in addition to shale oil, per calendar
day some 116 tonnes (128 tons) of sulfur, 125 tonnes (138 tons) of ammonia,
and 775 tonnes (855 tons) of by-product coke. Six Gas Combustion retorts are
projected, each 17 meters (56 ft) in diameter with a shale bed depth of 5.5
meters (18 ft). Each retort has a throughput of 13,060 tonnes (14,400 tons)
per stream day of raw shale, and produces 1,540 cubic meters (9,700 barrels)
per day of crude shale oil, 10,160 tonnes (11,200 tons) per day of spent shale,
82
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and 2.45 million standard cubic meters per day (86.2 million SCF/day) of ex-
cess low Btu gas. It is estimated that 60-70% of the spent shale would be
disposed of in the underground mine, and the remainder on the surface.
The capital investment* for the mine, retort plant, refinery, and assoc-
iated facilities were estimated to be nearly $230 million. Catalyst and chem-
icals inventory, interest during construction and start-up, plus working capi-
tal increased the total capital investment to $280 million. Annual operating
costs were calculated to be $63 million (before a by-product credit of $4
million is taken). The unit cost of shale oil, before by-product credit, was
thus estimated to be $21.60 cubic meter ($3.45/bbl). A selling price of $35.50
cubic meter ($5.65/bbl) was projected, based upon 12% discounted cash flow and
a 20-year plant life.
It is obvious that the above costs and selling price are now obsolete,
based upon present economics.
REFERENCES
The development of the gas combustion process by the U.S. Bureau of Mines,
and later the six-company consortium directed by Mobil Oil, is documented in
the following pertinent literature references:
1. Matzick, A., et al, "Development of the Bureau of Mines Gas-Combustion
Oil-Shale Retorting Process," U.S. Bureau of Mines Bulletin 635 (1966).
2. Ruark, J. R., Sohns, H. W., Carpenter, H. C., "Gas Combustion Retorting
of Oil Shale Under Anvil Points Lease Agreement: Stage I," USBM Report
of Investigation 7303 (1969); Stage II, ibid USBM Report of Investigation
7540 (1971).
3. Clampitt, R. L., et al, "Gas Combustion Retorting Performance in a Large
Demonstration Retort," preprint, 161st National Mfg., American Chemical
Society, Los Angeles (March 29, 1971).
4. Katell, S. and Wellman, P., "Mining and Conversion of Oil Shale in a Gas
Combustion Retort," USBM Technical Progress Report, TPR 44,(October 1971).
5. Katell, S. and Wellman, P., "An Economic Analysis of Oil Shale Operations
Featuring Gas Combustion Retorting," USBM Technical Progress Report, TPR
81, (September 1974).
6. Katell, S., Stone, R., Wellman, P., Oil Shale - A Clean Energy Source,
Colorado School of Mines Quarterly, Vol. 69, No. 2, 1-19 (April 1974).
*A11 dollars are mid-1973 dollars, and costs are at mid-1973 rates
83
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OCCIDENTAL MODIFIED IN-SITU PROCESS
C. C. Shih
Occidental Petroleum Corporation's involvement in oil shale technology
is a relatively recent development. In late 1972, Garrett Research and Dev-
elopment Company (now Occidental Research and Development), a subsidiary of
Occidental Petroleum Corporation, announced plans for the field testing of a
modified in-situ shale oil recovery scheme which is the subject of U.S. Patent
3,661,423. The actual work began in the summer of 1972 on the D.A. Shale pro-
perty at the head of Logan Wash, outside of Debeque, Colorado (Figure 36). In
the ensuing months, three research retorts, each 9.1 m (30 ft) on a side and
21.9 m (72 ft) high, were prepared and ignited. At the end of 1974 the pro-
ject was transferred to an operating branch of the company, when Occidental Oil
Shale, Inc., a subsidiary of the Occidental Oil and Gas Production Division,
was set up. Concurrently, a decision was made to initiate the development of
a commercial size retort in the commercial mine, located in a canyon off the
north side of Logan Wash about a quarter mile below the head. The commercial
mine is being developed at a new location because there is insufficient room
at the head of Logan Wash (the research mine location) to permit a large min-
ing operation, and because the research mine is located just below the Mahog-
any Ledge and too high for the construction of commercial size retort columns.
The first commercial size retort (Retort No. 4), with a 36.6 m (120 ft) by
36.6 m (120 ft) cross section and 76.2 m (250 ft) height and containing 15 gpt
rubblized shale, was ignited from the top on December 10, 1975. The burn was
continued successfully until late June 1976 with a total production of 27,500
barrels of crude shale oil. Sustained combustion and temperature control was
achieved by recycle of a portion of the retort gas. A second commercial size
retort (Retort No.1 5) similar in dimensions to Retort No. 4 was then also pre-
pared .
MINING AND FRACTURING
The modified in-situ process for shale oil recovery consists of retort-
ing a rubblized column of broken shale, formed by expansion of the oil shale
into a previously mined out void volume. The Occidental process involves
three basic steps. The first step is the mining out of approximately 20 to
25% of the oil shale deposits (preferably low grade shale or barren rock),
either at the upper and/or lower level of the shale layer. This is followed
by the drilling of vertical longholes from the mined-out room into the shale
layer, loading these holes with an ammonium nitrate-fuel oil (ANFO) explosive,
and detonating it with appropriate time delays so that the broken shale will
fill both the volume of the room and the volume of the shale column after
blasting. Finally, connections are made to both the top and bottom and re-
torting is carried out (Figure 37).
84
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RIoJHancoVCounty
GarflelTCoVnty
^ tt
OCCIDENTAL
Garfleld County
Mesa County
R94W
T PARAHO
7 (ANVIL
S POINTS)
8
S R100U
Figure 36. Occidental Oil Shale Lease Property in Piceance Creek Basin,
Colorado
85
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RAW SHALE
OIL
OIL RECOVERY
VENT GAS
n ^
RECYCLE GAS
COMPRESSOR
FUTURE RETORT
CENTER SHAFT
AIR MAKE-UP
COMPRESSOR
i OIL SUMP AND PUMP
Figure 37. Retorting Operation of the Occidental Modified In-Situ Process,
86
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A plan view of a typical commercial development based on the Occidental
scheme is presented in Figure 38. The commercial size rooms would be 36.6 to
48.8 m (120 ft to 160 ft) square with a height determined by the height of
the oil shale zone. The thickness of the walls between adjacent retorts de-
pends on whether the rubblized chimney will be a totally load supporting mass
by itself or whether the walls are required to serve as actual pillar supports.
In the former case, a wall thickness of 20 feet is probably adequate since the
walls only serve to physically separate the retorting chambers from one
another. In the latter case, however, the dimensions of the walls will be
significantly greater.
Both the size of the retorting chamber and the thickness of the walls
have an important impact on the fraction of the cross section of the shale
formation available for retorting. With 40 feet thick walls, the cross sec-
tion of the shale formation available for retorting would be 56% for 36.6 m
(120 ft) square retorting chambers and 64% for 48.8 m (160 ft) square retort-
ing chambers. With 20 feet thick walls, the cross section of the shale forma-
tion available for retorting would be 73% for 36.6 m (120 ft) square retorting
chambers and 79% for 48.8 m (160 ft) square retorting chambers. Thus large
retorting chambers and thin walls are necessary for the optimum recovery of
oil shale resources.
Assuming that 20% of the rock is mined out to create the void volume
necessary for subsequent rubblization, a 36.6 m x 36.6 m x 76.2 m (120 ft x
120 ft x 250 ft) commercial size retort could yield 8,042 m3 (50,584 barrels)
of crude shale oil, at 65% retorting efficiency and for 15 gpt shale. The
results from the Occidental experiments indicated a retort burn rate of 1.372
cm/hr (0.54 in/hr), thus the production period of a 76.2 m (250 ft) high re-
tort is 232 days and the production rate of crude shale oil from a commercial
size retort is 34.74 m3/day (218.5 BPD). As shown in Table 10., 229 retorts
would be required to operate simultaneously to produce 7,950 m3/day (50,000
BPD) of crude shale oil if the average Fischer assay of the shale zone is 15
gpt. For a shale zone with an average Fischer assay of 25 gpt, a minimum of
149 retorts would still be required if the production goal of 7,950 m3/day
(50,000 BPD) of crude shale oil were to be realized (Table 10).
In the construction of the commercial size retort, Occidental plans min-
ming at two levels (Figure 39). The upper mining level will be a complete
heading at or near the top of the retort, and will serve as a base from which
vertical longholes will be drilled for the loading of explosives. In the re-
torting process, combustion air will be supplied through the heading.
Note: Figures 37 and 40 are obtained from the paper "Development of the Modi-
fied In-Situ Oil Shale Process" by H. E. McCarthy and C. Y. Cha, pre-
sented at the 68th AIChE Annual Meeting, Nov. 16-20, 1975, Los Angeles,
California. Figures 38 and 39 are obtained from the Synthetic Fuels
Quarterly Reports published by Cameron Engineers, Inc., June 1974 and
June 1975, respectively.
87
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Figure 38. Occidental's Proposed Commercial Scale In-SItu Mining Scheme,
-------
Lower Mining Level
Not to scale
Scheme No. 1: No vertical separation
OVERBURDEN
Upper Mining Level
Drillholes for
ives and
injection
""""""/ explosives and
^ air i
Lower Mining Level .J^A^
Scheme No. 2: 50' vertical separation
Figure 39. Two Level Mining for Commercial Size Retort.
89
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Table 10. Commercial Production of Shale Oil Based on Occidental Modified
In-Situ Process
Basis:
Retort Size = 36.6 m x 36.6 m x 76.2 m (120 ft x 120 ft x 250 ft)
Mined Void Volume = 36.6 m x 36.6 m x 15.2 m (120 ft x 120 ft x 50 ft)
Wall Thickness = 6.1 m (20 ft)
Retort Burn Rate = 1.372 cm/hr (0.54 in/hr)
Total Commercial Production = 7,950 m3/day (50,000 BPD)
Average Fischer Assay of Shale (gpt) 15 20 25
Specific Gravity of Shale* 2.425 2.330 2.245
Quantity of Shale Mined (tonnes/day) 51,424 38,568 30,854
Oil Production Per Retort (m3/day) 34.74 44.51 53.61
No. of Retorts Required 229 179 149
Area Affected by Retorting (m2) 417,000 326,000 271,300
*Average specific gravity of oil shale samples from Anvil Points area.
Synthetic Fuels Data Handbook, Cameron Engineers, Inc., 1975, p 10.
RETORTING AND UPGRADING
In the Occidental modified in-situ process, retorting is initiated by
heating the top of the rubblized shale column with the flame formed from com-
pressed air and an external heat source, such as propane or natural gas.
After several hours, the external heat source is removed and the compressed
air flow is maintained, utilizing the carbonaceous residue in the retorted
shale as fuel to sustain air combustion. In this vertical retorting process,
the hot gases from the combustion zone move downwards to pyrolyze the kerogen
in the shale below that zone, producing gases, water vapor, and shale oil mist
which condense in the trenches at the bottom of the rubblized column (Figure
40). The oil production precedes the advancing combustion front by 9 to 12 m
(30 to 40 ft). The crude shale oil and byproduct water are collected in a
sump and pumped to storage. The off-gas is composed of gases from shale py-
rolysis, carbon dioxide and water vapor from the combustion of carbonaceous
residue and carbon dioxide from the decomposition of inorganic carbonate
(primarily dolomite and calcite). Part of this off-gas is recirculated to
control the oxygen level in the incoming air and the retorting temperature.
The off-gas has a heating value of approximately 2.56 MJ/Nmr(65 Btu/SCF), and
the.part of the.off-gas not recycled will be burned in a turbine for electric
power generation after hydrogen sulfide removal by the Stretford process.
Occidental has indicated that turbines manufactured by Brown-Boveri of Swit-
zerland will be investigated for this application.
90
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AIR & RECYCLE GAS
r
GAS
— RETORTING AND VAPORIZATION
Figure 40. Flame Front Movement in the Occidental Modified In-Situ Process
91
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According to Occidental's estimate, only 20 to 25% of the electric power
produced from the low-Btu gas is required for operating the modified in-situ
process. Occidental has not disclosed any information on the design of a
surface oil and gas treatment plant. The minimum treatment required for the
crude shale oil produced from the retorting process will include phase separa-
tion of the oil from the byproduct water and the stabilization of the oil pro-
duct. The waste-water effluent from the phase separator may be used for
steam generation after appropriate treatment.
The crude shale oil produced from the Occidental process has a specific
gravity of 0.904 (API gravity of 25°), a pour point of 21°C (70°F), a sulfur
content of 0.71 weight percent and a nitrogen content of 1.50 weight percent.
The crude shale oil is also reportedly free of solids and may be used directly
as boiler fuel. Occidental has claimed that tests conducted with the crude
shale oil show that its direct use as boiler fuel would meet the current NOX
standards. This implies that less than 20% of the fuel nitrogen contained in
the crude shale oil is converted to NOX during the combustion process. For
most other fuels, the conversion of chemically bound nitrogen to NOX under
normal boiler operating conditions is significantly higher and amounts to 50%.
At the present time the validity of the NOX tests with Occidental in-situ
crude shale oil must be considered to be questionable.
ENVIRONMENTAL STUDIES AND ACTIVITIES
During the in-situ experiments, Occidental contracted Claremont Engi-
neering to conduct ambient monitoring of gaseous criteria pollutants and stack
monitoring of selected pollutants in the retort off-gas, such as S02* CO, and
H2S. The daily averages of the measured values of the pollutants have been
reported to the State of Colorado on a quarterly basis. The retort off-gas
is of special concern because of the large quantity of gas involved which
.eventually must be vented to the atmosphere after burning in a turbine to
generate electric power or through simple incineration. The economic practi-
cability of removing hydrogen sulfide from the retort off-gas prior to combus-
tion, especially if electric power generation with the low-Btu gas proves to
be infeasible, remains to be ascertained. In a previous study conducted by
TRW, the quantity of vent gas released to the atmosphere was estimated to be
625Nm3/sec (1,400,000 SCFM) or 856 m3/sec (1,810,000 ACFM) at 95CC (200°
F), and comparable in magnitude and composition with the stack gas emitted
from a 500 MW oil-fired electric power plant.
The volume of retort water produced from the Occidental process is appro-
ximately 1 m3 per m3 of shale oil. This quantity of water is similar to in-
situ shale processing water requirements. It is not known whether Occidental
has investigated the treatment of the retort water for use in oil shale devel-
opment.
A second water problem of concern is the contamination of naturally
occuring groundwater intercepted in the underground development of an oil
shale zone. At Occidental's present site, there is little or no water flow
(less than 2.3 m3/hr or 10 gpm) due to the geology of the area. At the center
of the basin, however, Occidental indicates that mining schemes will be de-
signed to keep the aquifers isolated from the target oil shale zone below,
92
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and that cement linings of the shafts will allow access to the oil shale zone
through the aquifers. In areas where there is a saline water below and with-
in the target oil shale zone, Occidental believes that in most cases, it is
possible to either seal off the area or to pump the water to the surface and
reinject it in the same formation downdip. A closely related area of concern,
the potential for underground leaching of the spent shale, is not considered
by Occidental to be a significant problem. Occidental envisions that leaching
of the retorted shale will be severely limited due to the large size of the
shale pieces, and the movement of the water will be slow and probably be con-
fined to the spent chimneys. The water quality in Roan Creek, Logan Wash and
Dry Gulch is currently monitored by Occidental.
The rock that is mined will be dumped into the canyons near the
oil shale mine. A permit for increase in mined waste disposal pile from
382,000 m3 (500,000 cubic yards) to 6,500,000 m3 (8.5 million cubic yards)
was granted to Occidental by Garfield County Commissioners on January
12, 1976. The approval of this special permit provides Occidental with suffi-
cient mined rock (low grade shale) disposal capacity to expand into the large
demonstration phase. The permit was granted on the basis that the raw shale
pile would not be found to degrade the water quality of the area. A second
stipulation of the permit is that upon completion of the raw shale pile,
Occidental will restore the vegetative cover to a condition similar and com-
patible with comparable natural talus slopes in the vicinity.
Occidental has developed a list of 48 activities for which environmental
effects and permits must be considered, and has assembled a team of seven
people to gather environmental baseline data. The environmental studies con-
ducted include a meteorological study, fauna and flora studies, completed
paleontological and archaeological studies, ambient air and retort vent gas
monitoring studies, water quality monitoring studies, and others. The EIA
for the Occidental pipeline pi an was scheduled to be released in December 1976.
OIL SHALE RETORTING PRODUCTS AND UTILITIES REQUIREMENTS
For a commercial size development with 229 retorts operating simultane-
ously, each 36.6 m x 36.6 m x 76.2 m (120 ft x 120 ft x 250 ft) and contain-
ing oil shale with an average Fischer assay of 15 gpt, the Occidental modi-
fied in-situ process will generate the following products:
Shale Oil: 7,950 m3 (50,000 bbl) per calendar day
Sulfur: 373 tonnes (411 tons) per calendar day
Mined Rock: 51,424 tonnes (56,685 tons) per calendar day
Wastewater: 331 m3/hr (1,458 gpm)
The quantity of sulfur produced is estimated by assuming that the raw shale
contains 0.2 weight % organic sulfur, and that all the organic sulfur not
found in the crude shale oil (0.71 weight % sulfur) is collected in the Stret-
ford process when hydrogen sulfide is removed from the retort off-gas.
93
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The total water consumption rate for the Occidental operation is esti-
mated to be 1 m3 per m3 of crude shale oil produced, or 331 m3/hr (1,458 gpm),
including dust control and site irrigation. The power required for the opera-
tion of the Occidental process is only 20 to 25% of the electric power pro-
duced from the retort off-gas, if power generation by the burning of the low-
Btu gas in a turbine proves to be feasible. The fuel requirements for the
process will be supplied by the combustion of the carbonaceous residue left
in the retorted shale.
94
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LETC/DOE IN-SITU OIL SHALE RESEARCH PROGRAM
C. H. Prien
The Laramie Petroleum Research Center, U.S. Bureau of Mines initiated
research on liquid fuels from oil shale as a result of the Synthetic Fuels
Act of 1944. For 15 years this research was primarily concerned with oil
shale physical and chemical characteristics, and the properties of the shale
oil resulting from surface retorting processes.
In 1959 some R&D effort was introduced on in-situ shale oil recovery.
The in-situ investigations became a primary objective of the Center's oil
shale research, beginning in 1965, and continued as a principal activity
when these laboratories became the Laramie Energy Research Center of the
Energy Research and Development Administration. (LERC/ERDA) in 1975. This
Center is now the Laramie Energy Technology Center of the Department of Energy
(LETC/DOE).
In March 1975 a federal Interagency Oil Shale Planning Panel of experts
in various oil shale disciplines issued a report on "Accelerated Oil Shale In-
Situ Research - A National Program." This study has formed the basis for sub-
sequent federal in-situ research planning in the agencies involved, including
(LETC/DOE). It is the purpose of this present overview report to more fully
describe the past and present in-situ oil shale research program at the
Laramie Energy Technology Center,* and its anticipated goals for the near future.
BACKGROUND
In-situ processing of oil. shale was probably first attempted in the mid-
1940' s by the Estonians, who ignited a bed of Baltic Kukersite oil shale in
place, and removed the distillation products by suitably located take-off
mains. During the same period (1944) the Swedes began operation of the
Ljungstrom method, which heated an underground shale bed at Kvarntorp by means
of electrical resistance heaters. These investigations were discontinued in
the early 1950's.
During World War II underground pyrolysis of the Wurttemburg shales of
Germany was attempted on a semi-works basis, partially with German Navy sup-
port. A modified in-situ horizontal retorting process involving first rubbliz-
ing the shale in place was employed. Yields were poor however, seldom exceed-
ing 30% of Fischer assay.
*In addition to the LERC/DOE programs described in this report, DOE is also
conducting oil shale research at its Lawrence Livermore Laboratory (LLL) and
Sandia Laboratories.
95
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In-situ research on the western U.S. oil shales was initiated by private
industry. The Sinclair Oil and Gas Company conducted field studies in the
rather shallow oil shales (up to 300 ft deep) on the southern rim (Haystack
Mountain) of Colorado's Piceance Creek Basin, in 1953-54. A 31° API gravity,
2oc (350F) pour point oil was produced. In 1965 Sinclair continued field ex-
periments in the deep shales of the northern Piceance Creek Basin, but has
never published any results from these later efforts. However, the results
are believed to have been disappointing.
Between 1965 and 1967 Equity Oil conducted field experiments in a natu-
rally-fractured shale zone some 305 meters (1,000 ft) deep in the center of
the Piceance Creek Basin, using circulating hot methane gas. A minus 29°C
(minus 20°F) pour point oil was produced, but methane loss was excessive. In
1968 Atlantic Richfield reactivated the venture. In 1970 a change was made
to steam as the heat transfer medium, and well-spacings were reduced. The
project was terminated in 1971.
Within the past 10 years, in-situ field experiments have also been con-
ducted in the Piceance Basin by Mobil Oil (in shallow-depth shales), by Humble
Oil (in lower zone shales), and beginning in 1970 by Shell Oil Company, using
hot miscible fluids containing H£S and/or other solubilizing agents. No re-
sults from any of these efforts have been published (as of December 1976).
Beginning in 1964 CER Geonuclear and a consortium of private companies
proposed in-situ nuclear rubblization of shale and subsequent retorting at a
Piceance Creek Basin, Colorado site (Project Bronco). A similar experiment
was suggested for the Utah oil shales (Operation Utah). Public opposition to
.these proposed nuclear experiments, however, forced their abandonment in 1968.
In 1972 Occidental Oil Shale, Inc. (as Garrett Research and Development
Co.) began investigation of its modified vertical in-situ process at a site
near Debeque, Colorado, on the southern rim of the Piceance Creek Basin. The
process involves underground mining of 20% of shale or barren rock to create
void space, followed by chemical explosive rubblization and batch retorting.
Underground room No. 4, a commercial-size retort some 37 meters (120 ft)
square by 85 meters (280 ft) high, was ignited in mid-December 1975. A fifth
retort of similar dimensions was prepared (see Occidental Process
overview report).
Occidental was selected by ERDA (now DOE) for joint support of a
demonstration in-situ plant under the Federal Non-Nuclear Energy Act of 1974,
beginning in FY 1977. ERDA-shared support under this same Act was forth com-
ing for (a) Geokinetics, Inc. which had begun field tests of its modified
horizontal in-situ process in the Uinta Basin, some 15 miles south of the
federal lease tracts Ua, Ub; and (b) Talley-FRAC Corporation of Mesa, Arizona.
In 1975 Western Oil Shale Corporation (WESTCO) and a ten-company consor-
tium proposed a modified vertical in-situ project involving three underground
retorts at a site in the Uinta Basin in shales near Bonanza, Utah.
96
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A project planning phase was completed as of late 1976.
LERC/DOE IN-SITU FIELD RESEARCH PROGRAM
The potential application of nuclear explosions to in-situ energy re-
source recovery under the AEC Plowshare program was the primary motivation for
increased federal government interest in in-situ oil shale retorting, begin-
ning in the early 1960's. A 9 tonne (10 ton) batch shale retort using large
pieces for simulated in-situ experimentation was put in operation at the
Laramie Petroleum Research Center, Bureau of Mines (LPRC/USBM)t in 1965, and
was followed by a 136 tonne (150 ton) retort in 1969. These batch retorts
still continue to be used for evaluation of in-situ engineering parameters.
Initial Field Testing Program
In late 1965 LPRC/USBM began a series of field experiments concerned with
in-situ fracturing and retorting of oil shale at a location midway between
Rock Springs, Wyoming and Green River, Wyoming (Section 15, T 18 N, R 106 W).
Some nine different sites had been used as of 1976 as shown in Figure 41. The
oil shales are those of the Tipton formation, at depths as much as 46 meters
(150 ft) below the surface.
The types of research conducted at the first eight sites is summarized
in Table 11. As noted, these have included fracturing tests involving electro-
linking, hydraulic, and explosive techniques, and several true in-situ retort-
ing and steam injection experiments. Work at most of these 8 sites has now
been abandoned, butwork conducted at site 9 is more fully described below.
Table 11. Types of Research at LERC Rock Springs, Wyoming Sites*
Steam
Fracturing Research In-Situ Injection
Site Electrolinking Hydraulic Explosive Experiment Experiment
1
2
3
4
5
6
7
8
X
X
-
X
-
-
-
X
X
-
X
X
X
X
X
X
X
X
X
X
X
X
X
-
-
-
-
X
-
-
X
-
-
X
-
-
-
-
-
9 - XXX
*Adapted from Burwell, E. L., et al, USBM Report of Investigations 7783 (1973)
t LPRC/USBM became LERC/ERDA in January 1975, and later became LETC/DOE.
97
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IO
00
SCALE, lid
Figure 41. LERC In-Situ Sites, Sect. 15, T 18 N, R 106 VI, Rock Springs, Wyo.
(from Jackson, L. P., et al, Colorado School of Mines Quarterly 70_, 105-134, October 1975)
-------
Much of the work at the first 8 sites was done primarily to establish
test conditions, but the results from sites 4 and 7 are worthy of further
note.* At site 4 electrolinking and hydraulic fracturing were used to produce
a bed of broken shale 6.1 meters (20 ft) thick and 7.6 meters (25 ft) square
with less than 30 meters (100 ft) of overburden. A five spot well pattern was
drilled. Following ignition some 400 barrels of oil were obtained over a re-
torting period of 42 days.
Site 7 was a 10-day test involving ignition of a 6.7 meter (22 ft) thick
shale bed 21-27 meters (70-90 ft) below the surface. The shale was broken by
pelletized-explosive well bore shooting and hydraulic fracturing. Some 400
gallons of oil were collected from the 5-spot well pattern during the 10 days
of in-situ retorting before the experiment was discontinued.
From the results at sites 4 and 7, the Bureau concluded that a combustion
zone can be established and propagated in an in-situ fractured oil shale body
at shallow depths without substantial loss of permeability. However, yields
of retorted oil were poor, in part due to readsorption into the formation.
The oil itself had a lower pour point (-1°C or 30°F) and a higher volatility
than shale oil from surface retorting.
1972-76 Fracturing and Oil Recovery Field Program
The current series of Laramie field experiments on fracturing and in-situ
oil recovery have been underway since 1972 at the Rock Springs, Wyoming field
sites. In one experiment on a 0.4 hectare (one acre) site, fracturing was
attempted by using about 182 kg (400 Ibs) of pelletized TNT in each of 53
well bores. Simultaneous detonations were carried out in two to four wells
at a time. A system of horizontal fractures was formed at a depth of 38
meters (125 ft).
The bed was ignited and combustion was continued for several months.
Oxygen utilization was high and C02 production substantial, but essentially
no oil was produced due to insufficient exposed fracture surface area.
A new test site (No. 9) was prepared in order to further examine fractur-
ing techniques, in-situ oil recovery, and fluid migration before, during, and
after combustion and retorting. A 9-spot drill pattern was used involving
two concentric rings of 4 wells each at 11-15 meters (35-50 ft) from a central
injection well. Some 10 additional observation wells were drilled for hydro-
logic monitoring. The oil shale to be fractured and retorted was a 12 meter
(40 ft) thick bed in the Tipton formation at a depth of approximately 41
meters (135 ft). The well pattern is shown in Figure 42.
The bed was prepared by three hydraulic fracturing treatments followed
by two treatments with liquid explosives. Three major horizontal fractures
were created of sufficient permeability to permit water flow between all walls.
An attempt to enlarge the lower horizontal fracture, using hot water extrac-
tion and air, proved unsuccessful.
*Burwell. E. L.. et al. In-Sftu Retorting of Oil Shale. Results of Two Field
Experiments, USBM Report of Investigations #7783 (1973).
99
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N
oJ
Site 9
• - Pottern veil
o - Observation well
No scale
°H
Figure 42. Well Pattern for In-Situ Site 9
No. 1 - Injection Well
Nos. 2-8 - Production Wells
Letters - Observation Well
(from Jackson, L. P., et al, Colorado School of Mines Quarterly 70, 105-
134, October 1975)
100
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Ignition was started on April 5, 1976, and propane injection continued
until April 21, after which air alone was injected at rates of up to 5.7 - 6.4
cu meters/min (200-225 CFM) and pressures of 3.5-8.0 kg/sq cm gauge (50-115
psig). Down-hole temperatures of 870°C to 1370°C (1600 to 2500°F) in the pro-
duction wells and monitor wells indicated that combustion was successful, and
that the burn and retorting zones were proceeding toward the production wells.
Gas recovery was 4.65 x 106 cubic meters (165 x 106 cu ft) during the
first 35 days. The gas had a net heating value of 267-356 kcal/cu meter (30-
40 Btu/cu ft). About one-half barrel of shale oil per day was being produced,
half of which was naphtha and light gas oil and the remainder light distil-
late, heavy gas oil, and residuum. In the first 35 days of operation some 2650
ltrs.(700 gal) of oil with a gravity of 26° API and a pour point of 4°C (40°F)
were produced. Yields were poor. As of September 1976 the burn was still
proceeding although retorting conditions in the bed had not yet been optimized.
Exploratory Drilling Program
A field program of exploratory drilling of a series of coreholes, bore-
holes, and black trona brine wells has been initiated in the Northern Green
River Basin of Wyoming (See Figure 43). One objective is to evaluate the ex-
tent, richness, and geology of the Tipton, Wilkins Peak, and Laney Shale mem-
bers of the Green River formation in the Basin. Another goal is to locate a
suitable shallow deposit of shale in the Laney member on White Mountain for a
subsequent modified horizontal in-situ field test.
Environmental Aspects of In-Situ Shale Processing
Laramie has initiated a number of research programs to investigate the envi-
ronmental changes associated with in-situ oil shale processing. Among these
are the following.
Fluid Migration Field Studies. In 1974 a long-term program was begun to
examine underground fluids migration prior, during, and after in-situ process-
ing of shale. As part of this study, water and brine samples are taken at
monthly intervals from the wells and coreholes in the above-mentioned explora-
tory drilling program in the Northern Green River Basin. These, together with
the White Mountain well(s), provide data prior to in-situ processing.
The 10 hydrologic observation wells which are part of the current in-situ
test at Rock Springs Site 9 furnish data during actual in-situ shale oil
recovery. They also permit further study of the underground fluids after
in-situ processing is completed in order to detect any possible in-place pol-
lution effects.
Because of the large number of inorganic and organic constituents which
could be measured, it is necessary in all of these fluid migration studies to
limit the number of parameters to be monitored to those which are considered
to be (a) particularly significant, and (b) adaptable to routine analytical
techniques. In this connection, efforts at LET.C/University of Wyoming to sep-
arate and utilize the organic and inorganic components from the aforementioned
101
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ffi ll.ck.Wili. W.ll
WK.i. M«.*l.,n C«r>k(lt
4 I * M
lASf MA» riOM tUUIMIl II 7171
Figure 43. Location of LERC Field Studies, Sweetwater County, Wyo.
(base map from USBM Rept. Invest. 7172 (1968); location map from
Cameron Engineers, Synthetic Fuels Quarterly Report 12, No. 1, 2-10
March 1975)
102
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black trona water wells in the Northern Green River Basin are providing a
valuable analytical experience since this water may be thought of as partially
analogous to waste-fluids from in-situ processing.
Supporting Environmental In-Situ Research. A planning effort was con-
ducted to determine a comprehensive approach to the management of oil shale
retort water. The potential toxic constituents in retort water were iden-
tified and their biological degradation examined. Trace elements analyses
were also conducted.
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ERDA In-Situ Demonstration Projects
In February 1976 ERDA invited proposals for " research, development, and
demonstration of alternative methods for in-situ recovery of shale oil" under
a cost-share program. The Program Opportunity Notice (PON) specified five
possible types of in-situ processing, viz, true in-situ, vertical modified in-
situ with mining, horizontal modified in-situ with mining, horizontal modified
in-situ with fracturing, modified in-situ with solution mining.
Nine industrial firms responded with projects, from which four
were selected for cost-share funding under the Federal Non-nuclear Energy Re-
search and Demonstration Act of 1974. The four firms we re: Geokinetics, Inc.
(horizontal modified in-situ); Occidental Oil Shale, Inc. (vertical modified
in-situ); Equity Oil Co. (true in-situ with fracturing); and Talley-Frac Cor-
poration (explosive fracturing). DOE's Laramie Energy Technology Center assists
in technically monitoring these in-situ projects as they proceed, and in pro-
viding associated laboratory support.
1ETC/DOE SUPPORTING LABORATORY RESEARCH
The technical staff at LETC/DOE is continuously engaged in laboratory
research programs to provide fundamental engineering and scientific data in
support of the in-situ field programs, as described below.
Ten Ton and One Hundred Fifty Ton Batch Retorts
Mention has already been made of the previous use of the 10-ton and 150-
ton batch retorts for examining the engineering variables associated with in-
situ processing. These large-scale batch studies are continuing. Further
tests are in progress to examine the effects of shale size and richness on oil
recovery yields.
The 150-ton retort is being employed to further elucidate earlier observed
temperature anomalies in large oil shale blocks. Large granite blocks are
being simultaneously loaded with the shale. A study is also being conducted
in the large batch retort of the mechanism of retorting in atmospheres of vary-
ing oxygen content.
Gasification of Oil Shale
The gasification of shale has been investigated in an adiabatically-shield-
ed high pressure bench-scale retort since 1973. Over 120 runs had been com-
pleted by 1976, in the presence of varying amounts of CO?, 02. No and steam
and pressures up to 39 kg/sq cm gauge (550 psig), using 46 to 220 liters/tonne
(11 to 53 gal/ton) oil shale. The resulting off-gas has varied in heating
value from 445 to 11,570 kcal/cu meter (50 to 1300 Btu/cu ft).
The horizontal retorting and gasification runs have now been completed,
and vertical retorting and gasification studies have been initiated. Work is
also being completed on a large retort or about 0.45 tonne (0.5 ton) capacity
in which better heat and material balances can be obtained during gasification
than are possible with the present bench-scale unit.
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Controlled State Retorting
A 7.6 cm (3 in) diameter batch, vertical, controlled state retort (CSR),
electrically heated by 24 individually-programmed heating elements, is being
used to examine various retorting variables. The conditions are similar to
those encountered in the underground rubblized chimney of a modified vertical
in-situ retort with its down-flow of hot gases and lower, cool, unreacted
shale zone.
The data to date indicates a noticeable decrease in yield of lower boil-
ing shale oil fractions at higher oxygen contents in the retorting atmosphere.
The research is being continued and includes a program of planned kinetic
studies.
Pressure Retorting
A 129 liters/tonne (31 gal/ton) shale has been studied in a vertical
batch retorting process in which pressures from 0 to 105 kg/sq cm gauge (0 to
1500 psig) could be attained at varying heating rates and retort gas veloci-
ties. The retorting temperature was approximately 510°C (950°F). Increasing
pressure resulted in a decrease in Fischer assay oil yield from 90% (at atmo-
spheric) to 70% (at 1,500 psig), increased gasyprodu9tion and carbon deposi-
tion on the retorted shale, and a lower boiling shale oil. When a hydrogen
sweep gas was used, oil yields increased at higher pressures to greater than
100% of Fischer assay.
Retorting Using Carbon Monoxide and Water
The pyrolysis of oil shale is being examined in the presence of CO and
H20 in a bench-scale reactor at 300°C-450°C (57QOF to 840°F), CO charge pres-
sures of 70 kg/sq cm gauge (1,000 psig), and heating times of 0.25 to 1 hour.
Higher kerogen conversions to soluble products were obtained at lower tempera-
tures with CO/H20 than by dry thermal pyrolysis. The water-soluble minerals
produced resulted in retorting residues less susceptible to subsequent leach-
ing.
Miscellaneous In-Situ Related Laboratory Programs
Improved analytical techniques applicable to the current laboratory and
field in-situ programs continue to be developed. The conversion of in-situ
shale oils to useful gaseous and liquid products and their adaption to latest
refining technology is being examined. A study has been initiated on the
storage stability of hydrogenated shale fuels. Research is proceeding on the
oxidative removal of nitrogen compounds from various shale oil fractions, and
on solvent extraction of shale oils to produce cuts more amenable to hydro-
genation.
105
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SUGGESTED RECENT LITERATURE REFERENCES
1. Ramsey, J. W., "Implementation of the Energy Reserach and Development
Administration Accelerated Oil Shale In-Situ Research Program," preprint
81st National Meeting, AIChE, Kansas City, Mo., April 11-14, 1976.
2. Carpenter, H. C., "Preliminary Results of Five Oil Shale Conversion Experi-
ments," preprint, 9th Oil Shale Symposium, Colorado School of Mines, Golden
Colo., April 29-30, 1976.
3. Burwell, E. L., et al, "In-Situ Retorting of Oil Shale - Results of Two
Field Experiments," USBM Report of Investigations 7783 (1973).
4. Harak, A. E., et al, "Oil Shale Retorting in a 150-Ton Batch-Type Pilot
Plant," USBM Report of Investigations 7997 (1974).
5. Miller, J. S., "Fracturing Oil Shale with Explosives for In-Situ Oil Re-
covery," USBM Report of Investigations 7874 (1974).
6. "Accelerated Oil Shale In-Situ Research - A National Program," Interagency
Oil Shale Planning Panel, Washington, D.C., March 1975.
106
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-79-075
3. RECIPIENT'S ACCESSIOI»NO.
4. TITLE AND SUBTITLE
TECHNOLOGICAL OVERVIEW REPORTS FOR EIGHT
SHALE OIL RECOVERY PROCESSES
5. REPORT DATE
March 1979 (issuing date)
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
C. C. Shih and J. E. Cotter;
C. H. Prien* and T. D. Nevens*
8. PERFORMING ORGANIZATION REPORT NO
9. PERFORMING ORGANIZATION NAME AND ADDRESS
TRW Environmental Engineering Division
One Space Park
Redondo Beach, California 90278
10. PROGRAM ELEMENT NO.
EHE 623
11. CONTRACT/GRANT NO.
68-02-1881
12. SPONSORING AGENCY NAME AND ADDRESS
Industrial Environmental Research Laboratory
Office of Research and Development
U. S. Environmental Protection Agency
Cincinnati, Ohio 45268
13. TYPE OF REPORT AND PERIOD COVERED
Overview-Past to Dec. 1976
14. SPONSORING AGENCY CODE
EPA/600/12
15. SUPPLEMENTARY NOTES
*
Prien and Nevens are with Denver Research Institute, University Park, Denver,
Colorado 80210 (subcontractor) .
16. ABSTRACT
This report has been prepared to assist research workers by providing up-to-date
descriptions of processes at the forefront of oil shale development. The purpose of
the document is to supply background information for evaluation of environmental
impacts and pollution control technologies in connection with oil shale development.
All of the^reported shale oil processes have been tested on a sufficient pilot scale
(0.1-0.5 m /day oil production) to permit an evaluation of their operating character-
istics and yields. Six surface retorting processes selected for characterization
were: (1) Union Oil Retort B, (2) Paraho, (3) TOSCO II, (4) Lurgi Ruhrgas, (5)
Superior Oil, and (6) USBM Gas Combustion. In addition, two in-situ retorting activ-
ities were selected: (1) the Occidental modified in-situ retort, and (2) the true
in-situ development programs of Laramie Energy Technology Center (DOE).
Each overview report contains available information on oil shale processing.
General process descriptions, shale preparation requirements, equipment types, opera-
ting conditions, process products and by-products, physical and chemical characteris-
tics, energy and water requirements, process stream characteristics, processed shale
disposal requirements, and site-specific environmental aspects are included.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. cos AT I Field/Group
Oil Shale
Shale Oil
Processing
Roasting
Combustion Control
Plant equipment
Apparatus
Techniques
Unit operations
Retorting
Organic properties
Chemical thermodynamics
07A
f!r>1 nyadn
fit-ah
07C
07D
18. DISTRIBUTION STATEMENT
RELEASE TO PUBLIC
19. SECURITY CLASS (ThisReport)
UNCLASSIFIED
21. NO. OF PAGES
115
20. SECU
(This page)
22. PRICE
EPA Form 2220-1 (9-73)
107
U. S. GOVERNMENT PRINTING OFFICE: 1i7'i — 657-060/1650
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