oEPA
United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park NC 27711
EPA-450/3-81-010
August 1981
Air
Source Category
Survey: Oil Shale
Industry
-------
EPA-450/3-81-010
Source Category Survey;
Oil Shale Industry
Emission Standards and Engineering Division
Contract No. 68-02-3056
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air, Noise, and Radiation '
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
August 1981
-------
This report has been reviewed by the Emission Standards and Engineering
Division of the Office of Air Quality Planning and Standards, U.S.
Environmental Protection Agency, and approved for publication. Mention of
trade names or commercial products is not intended to constitute endorsement
or recommendation for use. Copies of this report are available through the
Library Services Office (MD-35), U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina 27711, or from National Technical
Information Services, 5285 Port Royal Road, Springfield, Virginia 22161.
-------
TABLE OF CONTENTS
1. INTRODUCTION 1-1
1.1 Scope 1-1
1.2 Industry Description 1-1
1.3 Emission Sources 1-2
1.4 Potential Control Technology 1-3
1.5 Review of State Regulations 1-4
2. SUMMARY 2-1
2.1 Industry Description 2-1
2.2 Study Objectives 2-1
2.3 Study Methodology 2-2
3. CONCLUSIONS 3-1
3.1 Technology Growth 3-1
3.2 Potential Problem Areas to Standards Development 3-1
3.3 Results 3-2
3.4 References 3-2
4. DESCRIPTION OF THE OIL SHALE INDUSTRY 4-1
4.1 Source Category 4-1
4.2 Basic Processes 4-2
4.2.1 Surface Retorting Operations 4-2
4.2.2 In Situ Retorting Operations 4-13
4.2.3 Spent Shale Disposal 4-18
4.3 Industry Production 4-19
4.3.1 Participating Organizations 4-19
4.3.2 Production Volumes 4-21
4.3.3 Growth Trends and Plant Projections for
Commercial Production Facilities 4-21
4.4 References 4-27
5. AIR EMISSIONS DEVELOPED IN SOURCE CATEGORY 5-1
5.1 Introduction 5-1
5.2 Availability of Data 5-2
5.2.1 Geokinetics In Situ Retorting . ' 5-3
5.2.2 Paraho Semi-Works Oil Shale Retort 5-3
5.2.3 Laramie Energy Technology Center In Situ Oil
Shale Reporting 5-4
11
-------
TABLE OF CONTENTS (Continued)
5.3 Process Emissions Review ......... . . 5-4
5.3.1 Mining . ........... 5-5
5.3.2 Processing 5-5
5.3.3 Retorting 5-8
5.3.4 Spent Shale Disposal 5-11
5.4 Emission Factors 5-11
5.5 Estimates of Nationwide Emissions ...... 5-15
5.6 Recommendations ...................... 5-22
5.7 References 5-22
6. EMISSION CONTROL TECHNOLOGY .................. 6-1
6.1 Introduction ............ 6-1
6.2 Control Approaches 6-4
6.2.1 Particulate Matter Control ............. 6-5
6.2.2 Sulfur Emissions Control ..... . . 6-9
6.2.3 Nitrogen Oxide Emissions Control ..... 6-23
6.2.4 Hydrocarbon and Carbon Monoxide Emissions
Control 6-26
6.3 Available Control Options for Emission Reduction ..... 6-31
6.4 References 6-32
-------
LIST OF FIGURES
Number Page
4-1 Potential Sources of Atmospheric Emissions, Oil Shale
Processing ........................ 4-3
4-2 Block Diagram of a Surface Oil Shale Retorting
Operation ........................ 4-4
4-3 Diagram of Paraho Process ................. 4-7
4-4 Diagram of Tosco II Process ................ 4-10
4-5 Lurgi-Ruhrgas Oil Shale Retorting Process ......... 4-11
4-6 Block Diagram of an In Situ Oil Shale Retorting
Operation ........................ 4-14
4-7 Sectional veiw of a Geokinetics Horizontal In Situ Oil
Shale Retort ....................... 4-15
4-8 Occidental Modified In Situ Process ............ 4-17
6-1 Particulate Removal Options ................ 6-6
6-2 Flue Gas Desul furi zation Process (S0£ Removal) ....... 6-11
6-3 H$ Removal Process .................... 6-16
6-4 Technologies for the Reduction of NOX in Stack Gas
Emissions ........................ 6-24
6-5 Hydrocarbon Control Technologies .............. 6-27
6-6 Carbon Monoxide Control Technologies ............ 6-28
-------
LIST OF TABLES
Dumber Page
1-1 Status of EPA Permit Delegations to States with Oil
Shale Develpoment Activity ..... 1-5
3-1 Data Usually Collected in Source Category Survey 3-3
4-1 Commercial/Research and Development Projects ... 4-20
4-2 Shale Oil Production 4-22
4-3 Predicted Shale Oil Production Levels from Western Oil
Shale Resources, 1980 to 1996 4-25
4-4 Capital Requirements, 1980 to 2000 4-26
4-5 Estimated costs as of August 1979 (Based on Lurgi
Technology) for Production of 214,000 bbl/day of Oil
Shale on Government Land 4-26
4-6 Labor Requirements, 1980 to 2000 4-26
5-1 Estimated Uncontrolled Atmospheric Emission Ranges for
Underground Mining Operations--50,000 bbl/day Oil
Shale Facility 5-6
5-2 Estimated Controlled Particulate Emissions from Crushing,
Transporation, and Storage of Raw Shale and Disposal of
Spent Shale--50,000 bbl/day Oil Shale Facility 5-7
5-3 Composition of Oil Shale Retort Off-Gases 5-10
5-4 Estimated Emissions, Oil Shale Projects .... 5-12
5-5 Estimated Uncontrolled Particulate Matter, Sulfur Oxide,
and Nitrogen Oxide Emission Factors—Oil Shale
Processing, All Emission Sources 5-13
5-6 Estimated Uncontrolled Hydrocarbon and Carbon Monoxide
Emission Factors—Oil Shale Processing, All Emission
Sources 5-14
5-7 Estimated Actual Emissions of Criteria Pollutants from
Planned Oil Shale Development Projects—1985, 1990,
and 1995 5-16
5-8 Estimated Uncontrolled Particulate Matter Emissions
from Planned Oil Shale Development Projects—1985,
1990, and 1995 5-17
-------
LIST OF TABLES
Number Page
5-9 Estimated Uncontrolled Sulfur Oxide Emissions from
Planned Oil Shale Development Projects--1985,
1990, and 1995 5-18
5-10 Estimated Uncontrolled Nitrogen Oxide Emissions
from Planned Oil Shale Development Projects--1985,
1990, and 1995 5-19
5-11 Estimated Uncontrolled Hydrocarbon Emissions from
Planned Oil Shale Development Projects--1985,
1990, and 1995 5-20
5-12 Estimated Uncontrolled Cargon Monoxide Emissions
from Planned Oil Shale Development Projects--1985,
1990, and 1995 5-21
6-1 Sources and Nature of Potential Atmosheric Emissons from
Oil Shale Extraction and Processing 6-2
6-2 Key Features of Particulate Matter Removal Systems
Applicable to Oil Shale Processes 6-7
6-3 Key Features of Flue Gas Desulfurization Systems
Applicable to Oil Shale Processes 6-12
6-4 Comparison of Sulfur Removal Systems Applicable to
Oil Shale Processes 6-17
6-5 Comparison of NOX Control Systems Applicable to
Oil Shale Processes 6-25
6-6 Key Features of Hydrocarbon Control Systems Applicable
to Oil Shale Processes 6-29
6-7 Key Features of Carbon Monoxide Systems Applicable
to Oil Shale Processes 6-30
VII
-------
1. INTRODUCTION
1.1 SCOPE
This Source Category Survey Report (SCSR) describes the existing oil
shale industry and its probable future, identifies and evaluates emission
sources, and identifies and compares available pollution control techniques.
For this report, the oil shale industry includes shale mining, shale
transportation, onsite conversion of kerogen in shale to unrefined shale oil,
off-gas processing, and onsite use of product gas or process heat for steam
generation. Onsite conversion includes hydrotreating to upgrade oil to a
pipeline product. As described in Chapter 4, some shale oil conversion
processes combine these steps.
1.2 INDUSTRY DESCRIPTION
Because no commercial-scale oil shale recovery facility is currently
operating, this report is based on pilot-plant, bench-scale, and material-
balance data scaled-up to approximate commercial operations. Accuracy of
these data will not be known for approximately 2 years, during which time
commercial-scale facilities are scheduled to begin operation. Testing and
evaluation of these facilities may yield hard data for standards development.
In the absence of hard data, this report provides a best estimate of
commercial-scale oi.l shale recovery operations.
The United States has large oil shale reserves. Estimates range around
270 billion megagrams (Mg) (298 billion tons), which could yield 2 trillion
barrels of oil. This amount would supply the United States for 168 years at
the 1978 consumption rate. About 90 percent of these reserves are
concentrated in Colorado, Utah, and Wyoming. Other States with promising
deposits are Michigan, Kentucky, Tennessee, and Oklahoma.
Oil shales are rocks that contain kerogen as a primary organic
constituent, but they may contain natural bitumin and, in some instances,
1-1
-------
small amounts of crude oil. Kerogen is extracted by heating oil shale to
about 400° C (750° F) and thermally degrading (pyrolyzing) the organic matter.
Shale oil is recovered when this gas is condensed. Preliminary treatment—
hydrogenation—upgrades the oil to a pipeline product.
Thermal decomposition is conducted in a retort, of which there are two
generic categories—surface and in situ. Basic steps for surface retorting
include mining, crushing, transporting, retorting, and spent shale disposal.
Some mining may be necessary for in situ retorting, but most retorting occurs
underground in the shale deposit, with spent shale remaining in the retort.
Surface retorts use either direct-heat or indirect-heat transfer for
pyrolysis of shale kerogen. Direct-heat units are heated by internal
combustion of recycle gases and residual carbon on spent shale. Indirect-heat
units use a gas or solid heated outside the retort. Some processes have been
designed to use a combination of direct- and indirect-heat.
There are two types of in situ retorts: true in situ (TIS) and modified
in situ (MIS). TIS involves well drilling, rock fracturing, and retorting
within rock formations. MIS involves mining and removing from formations 15
to 40 percent of the ore before rubbling and in situ retorting. Partial
removal allows more complete rubbling of remaining shale and greater oil
recovery. Shale removed from in situ retorts is processed aboveground.
1.3 EMISSION SOURCES
Based on estimates approximated from existing pilot-plant and bench-scale
data, four main emission sources are possible in the oil shale recovery
process: mining, processing, retorting, and spent shale disposal. Product
gas processing, onsite use of product gas or process heat, and upgrading of
shale oil to a pipeline product are also_potential emission sources.
Mining activities associated with aboveground oil shale retorting are
expected to be the largest in the world. Mining's potential atmospheric
pollution sources include excavation, blasting, transportation, and equipment
movement. Processing of mined oil shale includes size reduction (crushing)
for retorting and conveyer transportation of crushed shale. Primary
pollutants from mining and processing are particulate matter. In addition,
1-2
-------
gaseous pollutants from blasting and equipment usage will be significant for
commercial-scale operations.
A major source of air pollution is shale retorting, which produces sulfur
compounds, nitrogen oxide, particulate matter, hydrocarbons, carbon monoxide,
and trace elements. Except for leaks, these pollutants are not released
during the actual retorting process but during processing of oil and gas
products. As noted earlier, most available air pollution data are from
pilot-plant and semi-works facilities; no commercial-scale facilities exist.
The amount and characterization of these pollutants cannot be completely
assessed until a commercial-scale facility is complete.
Spent shale disposal is also an emission source. Particulate matter and
hydrocarbon emissions can occur during transfer, handling, and disposal.
Trace elements also have high potential of accompanying these emissions.
Combustion of retort off-gas to generate electricity or provide process
heat can result in emissions of all criteria pollutants, hazardous pollutants,
and trace elements. Of the criteria pollutants, sulfur oxides have the
highest pollution potential, because of the high predicted sulfur content of
retort off-gas. Complete characterization and quantification of hazardous
pollutant and trace element emissions will require generation of additional
emissions data.
Pollutants of primary concern in oil shale processing are particulate
matter, sulfur dioxide, nitrogen oxides, hydrocarbons, and carbon monoxide.
Subpart D, 40 CFR 60, can be interpreted as applicable to combustion of
product gas in steam-generating units of 43 megawatts (MW) or greater.
Product gas use in other industrial-type boilers will probably be covered
under New Source Performance Standards (NSPS) being developed for industrial
boilers. Additional data will help determine applicability of these standards
to use of product gas at oil shale production facilities.
1.4 POTENTIAL CONTROL TECHNOLOGY
Control technology for emissions of particulate matter, sulfur, nitrogen
oxides, hydrocarbons, and carbon monoxide is described fully in Chapter 6.
This section summarizes that presentation.
Control technology for particulate matter includes mechanical (dry) and
wet collectors. Mechanical collectors include fabric filters, electrostatic
1-3
-------
precipitators, and cyclones. Wet collectors include venturi scrubbers,
electrostatic precipitators, wet suppression, spray towers, cyclone scrubbers,
and impingement-plate scrubbers.
Two options for controlling sulfur emissions from oil shale processing
are sulfur removal from stack gas and sulfur removal from fuel. The first
method, commonly called flue gas desulfurization (FGD), depends on retort gas
sulfur species' being converted to sulfur dioxide during combustion. Because
it requires this conversion, FGD is applicable only when retort gas is
combusted. In oil shale operations, retort gas combustion is used to create
heat or steam.
Techniques for removing retort gas sulfur compounds prior to combustion
include a number of processes, outlined in Chapter 6, for direct and indirect
conversion (acid gas removal). These removal processes are not limited by
where the gas is used.
Options available for reducing potential nitrogen oxide emissions are
combustion modification, fuel-nitrogen removal, and stack gas removal of
nitrogen. Nitrogen must be converted to nitrogen oxide for stack gas removal.
Combustion system modifications may not allow oil shale facilities to meet
nitrogen oxide emissions standards, but retrofit control systems can be added
to help meet them. For off-site use of product gas, nitrogen must be removed
in a chemically reduced form prior to combustion or stack gas removal must be
accomplished at the combustion site.
There are four techniques for controlling hydrocarbon and carbon monoxide
emissions: (1) more complete process equipment sealing, (2) more complete
fuel combustion, (3) use of catalytic converters, and (4) use of thermal
oxidizers. The first of these involves inspection and maintenance of superior
process equipment seals; the second is accomplished by adjustments to the
combustion process. The last two techniques are for removing hydrocarbon from
process streams.
1.5 REVIEW OF STATE REGULATIONS
The three States with major oil shale development activity are Colorado,
Utah, and Wyoming. Several other States expect development activity in the
near future. Table 1-1 presents the status of U.S. Environmental Protection
Agency (EPA) delegations of permit regulations in Colorado, Utah, and Wyoming.
1-4
-------
TABLE 1-1. STATUS OF EPA PERMIT DELEGATIONS TO STATES WITH
OIL SHALE DEVELOPMENT ACTIVITY
Permit type
Delegation status
Colorado
Utah
Wyoming
National pollution discharge Yes No
elimination system (NPDES)
Drinking water No No
Hazardous waste No No
Construction grants Yes Yes
Dredge and fill permit
(Section 404) No No
National Emission Standards for Partial Yes
Hazardous Air Pollutants (NESHAP)
Noise No No
Radiation No No
Prevention of Significant Deterioration No No
(PSD)
Yes
No
No
Yes
No
No
No
No
Yes
1-5
-------
Each of these regulations has potential to influence further oil shale
development. Each of these three major States is presently writing specific
regulations for oil shale processing.
Several other Colorado State regulations may affect oil shale
development. Opacity regulations restrict emissions obscuring vision in
excess of 20 percent. For particulate matter, current regulations allow no
more than 0.5 lb/106 Btu input for units generating not more than 106 Btu per
hour and 0.1 lb/106 Btu input for units generating 500 x 106 Btu input per
hour or more. Sulfur dioxide regulations are specific for oil shale
operations, with no standard for operations producing less than 1,000 barrels
per day. For operations of 1,000 barrels per day or more, the standard is 0.3
lb S02/bbl processed for the sum of all sulfur dioxide emissions from a given
production facility. This standard also applies to oil refining from shale.
The sulfur dioxide standard for all new oil-fired operations is 0.8 lb S02/106
Btu input if the process is less than 250 x 106 Btu/hr and 0.3 lb S02/106 Btu
input for operations of 250 x 106 Btu/hr or greater. It is not known if the
standards for oil-fired operations would apply to facilities producing less
than 1,000 barrels per day. The nitrogen oxide regulation in Colorado is 0.30
lb NOX/106 Btu input for liquid fuels. Standards for three metals—beryllium,
mercury, and lead—may also be applicable, allowing emissions of lOg Be/24 hr,
2,300 g Hg/24 hr, and 1.5 yg Pb/m^ (averaged over a 1-month period),
respectively.
Two Utah State regulations may also affect oil shale development. Plumes
from existing facilities can have densities no darker than 20 percent opacity.
Oil-fired operations may only use oil containing 1 percent sulfur, by weight,
or less.
Wyoming's standards for sulfur dioxide emissions from oil burning
equipment limit emissions to 0.8 lb/106 Btu heat input. Emissions of nitrogen
oxide from new gas-fired equipment are limited to 0.20 lb/106 Btu.
Kentucky is presently preparing to write specific standards for
oil shale operations. The existing Kentucky particulate standard for new
process operations does not allow emissions with 20 percent or greater
opacity. For heat exchangers, sulfur dioxide emissions are limited to 3.0
lb/S02/106 Btu for sources up to 10 x 106 Btu/hr, and 0.8 lb S02/106 Btu for
1-6
-------
sources up to 250 x 106 Btu/hr or more. Nitrogen oxide standards limit
emissions to 0.3 Ib NOX/106 Btu heat input.
Michigan standards do prohibit emissions with opacities of 20 percent or
greater or with opacities of 40 percent within any 3-minute period in a
60-minute period.
Oklahoma has regulations for fuel-burning equipment prohibiting
particulate matter emissions of more than 0.6 lb/106 Btu heat input. Also for
fuel-burning equipment, sulfur dioxide emissions of 0.2 Ib S02/10^ Btu heat
input and nitrogen oxide emissions of 0.2 Ib NOX/10^ Btu heat input are not
allowed. Tennessee regulations prohibit discharge of any air contaminant with
an opacity of 20 percent or greater for more than 5 minutes in any hour. In
no instance can Tennessee facilities with capacities over 1,000 x 106 Btu/hr
emit more than 2.8 Ib S02/hr.
1-7
-------
2. SUMMARY
2.1 INDUSTRY DESCRIPTION
Currently, only pilot-plant or semi-works facilities exist for each basic
shale oil extraction process. Considerable difference of opinion exists as to
when oil extracted from shale will be competitive with other oil sources. The
inability to predict potential competitiveness accurately is caused by crude
oil's uncertain future availability and price and by uncertainties associated
with shale oil extraction technology.
The history of shale oil production is largely undocumented. It is known
that a commercial industry flourished around 1860 in Scotland but declined
before 1900 because of diminished resources and cheaper crude oil. In the
United States, the industry flourished in the late 1800s but declined as more
crude oil became available. In the 1940s, oil shale development was
subsidized by the U.S. government as a potential substitute for imported oil
during World War II. Total U.S. production from pilot-plant and semi-works
facilities has been small compared to total oil production. However, the oil
shale industry is important to the the U.S. energy future as an alternative to
imported crude oil.
2.2 STUDY OBJECTIVES
This study had several objectives, the most important of which was to
determine facilities, processes, and pollutants for which a New Source
Performance Standard (NSPS) or National Emission Standard for Hazardous Air
Pollutants (NESHAP) may be appropriate. It has been determined that no
commercial-scale oil shale production facilities exist, leaving no basis for
determining application of these standards. However, commercial-scale
facilities are scheduled to go on line in the next 2 years, depending on
numerous economic criteria and potential environmental problems. Data
obtained during construction and operation of these facilities may prove
useful for standards development.
2-1
-------
2.3 STUDY METHODOLOGY
Information used in this study was obtained from several sources,
literature searches, review and journal articles, plant visits, State
regulations, permit requests, and personal contacts with industry members. In
addition, information was already available in several EPA publications and in
draft reports of current EPA-funded studies.
2-2
-------
3. CONCLUSIONS
3.1 TECHNOLOGY GROWTH
Penetration of shale oil into the world crude oil market will be a major
force driving development schedules for facilities. Although no commercial
facilities are presently in operation and none are slated to be on-line this
year, two should go on-line in 1982. A timetable for commercial operation of
existing projects estimates a total of 8 facilities by 1985 and 12 facilities
by 1990. However, this schedule depends on the price and availability of
current crude oil sources. Cost and resource requirements for oil shale are
great, and investors require security. While potential for growth is great,
actual growth is affected by many variables and is difficult to assess.
Therefore, this timetable should be considered only an approximation. Because
the most attractive oil shale deposits are located near western Class I
Prevention of Significant Deterioration (PSD) areas, the currently allowable
PSD increment may preclude full industry development.
Because no commercial facilities are presently operating, only pilot-
plant and semi-works data were available for this study. These data must be
scaled-up to approximate operations in a commercial facility and may not
accurately predict potential emissions. In addition, certain features of oil
shale processing systems may change when scaled-up to commercial size. Thus,
without hard commercial-scale data, no solid baseline exists for standards
development.
3.2 POTENTIAL PROBLEM AREAS TO STANDARDS DEVELOPMENT
Many problem areas characterized earlier still exist. First, data are
limited on characterization of emissions, especially of hazardous air
pollutants. It is difficult to develop standards for unknown pollutants. No
commercial plants are in operation, and numerous potential problems are
associated with scaling-up existing pilot-plant and semi-works emission data.
Linear models for this scaleup may be inappropriate, and determining other
3-1
-------
functional relationships is difficult. In addition, because no commercial
facilities exist, there is no demonstrated control system for major process
streams. Without demonstrated control technology, standards development may
be burdened with demonstrating that technology can be transferred from similar
industries.
3.3 RESULTS
Potential emissions from oil shale operations and their control
techniques have been identified in previous sections and are discussed more
completely in Chapter 5. However, many data needed for standards development
are not available (see Table 3-1).
Additional monitoring of air, surface water, groundwater, solid waste
disposal piles, and oil shale residual streams at a commercial facility may be
needed to provide adequate date for impact calculations. Shale mining,
transportation, and disposal operations may be on the largest scale ever
developed and will require extensive monitoring to determine impacts fully.
Retort technology needs to be demonstrated commercially to permit characteri-
zation and quantification of emissions. Tradeoffs among air, water, and
solid waste impacts can then be better studied. Finally, applicability of
sampling and analysis methods should be verified for oil shale pollutant
streams.
3.4 REFERENCES
1. Oil Shale Briefing Book. Region VIII, U.S. Environmental Protection
Agency. Denver, Colorado. October 21-23, 1980.
3-2
-------
TABLE 3-1. DATA USUALLY COLLECTED IN SOURCE CATEGORY SURVEY
Parameter
Data status
List of facilities
Size
Production capacity
Products
Production rates
Raw materials
Feasibility of testing
Type of air pollution control system
System operation parameters
System maintenance frequency
Fugitive emissions sources
Chemical nature of pollutants
Rates of pollutant discharge
Compiled
Estimated3
Estimated
Determined
Estimated
Determined
Determined
Projected'3
Estimated
Estimated
Estimated
Estimated
Estimated
Estimated from pilot-plant data.
Projected from known parameters of existing pollution control equipment,
3-3
-------
4. DESCRIPTION OF THE OIL SHALE INDUSTRY
This chapter describes the oil shale source category, basic processes
under development, and the oil shale industry as a whole. As stated in
previous chapters, no commercial oil shale production is currently underway.
Information presented in this chapter is based on pilot plants, semi-works
plants, engineering estimates from plans for future facilities, and
commercial-sized runs of some operations.
4.1 SOURCE CATEGORY
For this Phase I Source Category Survey Report (SCSR), the oil shale
industry includes shale mining and onsite conversion of kerogen in shale to
unrefined shale oil suitable for refinery processing. For some production
methods, mining and conversion are combined. Additionally, onsite conversion
includes hydrotreating to upgrade oil to a pipeline product.
Numerous definitions are available for oil shale. In geological terms
oil shale is not a shale, but a mudrock. Two organic constituents commonly
occur in mudrocks: kerogen, which can be converted to shale oil, and natural
bitumin. Kerogen, of relatively high molecular weight, is a dark, grey-black,
amorphous organic solid present in various quantities in mudrock. Kerogen
contains from 70 to 80 percent carbon, from 7 to 11 percent hydrogen, from 10
to 15 percent oxygen, traces of nitrogen and sulfur, and traces of numerous
other elements. By definition, kerogen includes hydrocarbon compounds not
soluble in ordinary organic solvents, such as ether, acetone, benzene, or
chloroform.1 Natural bitumin, of lower molecular weight than kerogen, is
soluble in ordinary organic solvents. In Colorado oil shales, the
kerogen/natural bitumin ratio is about 9:1. Oil is recovered by heating oil
shale to 400° C (750° F) and thermally decomposing (pyrolyzing) organic
matter.^
Under favorable conditions, crude oil can sometimes occur in pore spaces
of rocks along with kerogen and natural bitumin. These rocks can yield oil by
distillation (without pyrolsis) and are more correctly termed oil shales. In
4-1
-------
this report, as in most other oil shale studies, the definition of oil shale
includes rocks containing kerogen as well as those containing crude oil and
natural bitumen.
4.2 BASIC PROCESSES
Figure 4-1 shows a generic schematic of oil shale processing. Four steps
are included in all oil shale proceses: feed preparation, retorting, product
recovery, and waste disposal. Atmospheric emissions of criteria pollutants,
hazardous pollutants, trace metals, and other materials can occur during each
of these steps. The composition and quantity of effluent streams are strongly
influenced by the process used to recover shale oil.
Oil shale feed preparation and retort technology can be divided into two
general categories: (1) mining, followed by surface retorting, and (2)
underground, or in situ, processing. Retort processes currently under
investigation can be grouped into three classes: (1) surface, (2) true in
situ (TIS), and (3) modified in situ (MIS). In surface retorting technology,
oil is recovered in an aboveground retort from shale mined by conventional
underground or open pit procedures. In TIS technology, all retorting occurs
underground in the shale deposit. MIS technology is a hybrid of surface and
TIS technologies in which 60 to 85 percent of the shale is retorted in a place
underground, with the remaining 15 to 40 percent being removed and retorted in
a surface facility.
Descriptions of processes based on surface and in situ technologies
follow. As mentioned above, processes based on MIS technologies are a
combination of surface and TIS technologies. Where appropriate, parameters
peculiar to MIS technology are included. It should be emphasized that the
following descriptions are based on research and development projects, pilot
plants, and semi-works facilities. No commercial- or full-sized facility has
been built. It is difficult to further define physical environmental
concerns, such as air and water quality, until commercial production of oil
shale begins. When current technology is scaled-up to full size, some
features may change.
4.2.1 Surface Retorting Operations
Figure 4-2 is a block diagram of oil shale operations for surface
retorts. Feed preparation processes include shale mining, crushing to size,
4-2
-------
FEED PREPARATION I RETORTING
WASTE DISPOSAL
Figure 4-1. Potential sources of atmospheric emissions, oil shale processing.
-------
Mining
of
raw shale
I
Crushing,
sizing, and
screening
Spent
shale
Retorting of
feed shale
Shale
oil
Product
gas
Upgrading and refining
Oil and gas recovery
Coking
Hydretreating
Figure 4-2. Block diagram of a surface oil shale retorting operation.
4-4
-------
and transportation. Retorting has three products: shale oil, a product gas,
and spent shale for disposal. Shale oil is upgraded to a pipeline product
onsite.
4.2.1.1 Mining. Commercial-sized, underground, room-and-pillar mining
has been used by several pilot and semi-works retorting facilities. In this
process, oil shale is mined from equal-sized openings, approximately 18 meters
(60 feet) square, leaving as much as 50 percent of the shale in place as
pillars supporting the room. Because so much usable shale is left in the
ground, this mining process may not be appropriate for thick shale deposits.
Other underground mining methods can be used effectively to remove oil
shale. Sublevel stoping involves blasting to rubble high vertical columns of
ore (stopes) and moving oil shale from stopes to rail cars with front-end
loaders. Another underground mining method is block caving, in which mine
levels are divided into panels and blocks and mined with tunnel methods.
Shale from an undercut level is carried by gravity through tunnels and into
rail cars.
Surface, or open pit, mining involves excavating overlying soil and rock
to expose the resource below. Pit wall slope is determined by stability of
the rock being mined, with depth dictated by ore grade. Open pit mining has
the advantage of allowing recovery of almost the entire resource.
4.2.1.2 Crushing, Transportation, and Storage. For each of the surface
retorting processes, the raw, mined, oil shale must be crushed to appropriate
size before transport to a retort. Additional testing of crushing equipment
may be required before the best technology is selected, because oil shale
fragments are resilient, tough, and slippery and tend to form slab-shaped
fragments when crushed in jaw, gyratory, or tooth-roll crushers. Impact-type
crushers tend less to cause formation of these slab-shaped fragments.
Current plans for large-scale demonstration plants and commercial
facilities generally call for primary crushing at the mine site, followed by
secondary crushing near the retorting site. Some retorting processes specify
a particle size small enough to require tertiary crushing operations.
According to current plans primary crushed ore will be transported to the
retorting site by truck, rail, or in covered conveyors. All commercial plans
4-5
-------
currently propose the use of covered conveyors. Dust generated by these
operations will be collected and either retorted or discarded.
Primary crushed ore can be stockpiled near the retort to provide for
surge conditions and to allow continuous operation through a shutdown of
mining activities. Large operations will probably have open stockpiles, with
ore being transferred to the retort by traveling buckets or conveyors.
Current plans call for secondary and tertiary crushers to prepare ore
for retorting. Storage of fine ores from these operations will probably be
enclosed to minimize losses and environmental hazards.
4.2.1.3 Retort Technology. In the surface retort, heat can be
transferred in one of three ways: (1) by gases generated within the retort
through combustion of carbonaceous, retorted shale and pryrolysis gases
(direct heating); (2) by gases heated outside the retort (indirect gas
heating); and (3) by hot solid particles mixed with the oil shale (indirect
heating with solids). The following subsections describe surface retorting
processes with the most potential for commercialization.
4.2.1.3.1 Paraho retorting process. The Paraho surface retorting
process operates in the direct- or indirect-heat modes. Most of the
experimental work has been done with the direct-heat mode, discussed below
(see Figure 4-3).
Raw shale is prepared for Paraho retorting by crushing to a particle size
between 1/4 and 3 inches. Raw shale finer than 1/4 inch is screened from the
retort feed to avoid a lowering of bed porosity and an increase in bed
resistance to the countercurrent gas flow within the retort. After crushing,
raw shale is fed into a hopper at the top of the retort and spread evenly on
top of the shale bed. After processing, shale js discharged from the retort
bottom. Combustion gas containing product gas and oil mist moves
countercurrently to the flow of shale and exits near the retort top. An inert
gas seal prevents loss of shale oil and product gas through the feed hopper
during processing.
Preheated by countercurrent flow.of hot combustion gas, shale is pulled
downward by gravity through a mist formation and preheating zone. The shale
then enters the retorting zone, where contact with hot combustion gases
increases shale temperature until kerogen is pyrolyzed to produce oil and gas
products. These products are entrained in the combustion gas and carried out
4-6
-------
RAW SHALE
PREHEATING AND MIST
FORMATION
PYROLYSIS
STRIPPING AND WATER
GAS SHI FT
PARTIAL COMBUSTION
MOVING GRATES
COMBUSTION >•
COOLING *•
-^- Raw Shale Oil
OIL RECOVERY UNIT
GAS/AIR -«-
MIXTURE
Product
Gas
-2/3
Recycled
Air Intake
RESIDUE
Figure 4-3. Diagram of Paraho process.
-------
of the retort. A coke-carbon residue (4.0 to 4.5 percent by weight) is left
on the shale in the retorting zone. As the shale moves into the combustion
zone, most of this coke-carbon residue burns, producing hot exhaust gases that
supply heat for retorting. At the retort bottom, an adjustable, hydraulic
grate controls the shale's downward velocity, maintaining even flow across the
retort. Spent shale is discharged from the retort at a temperature of about
200° C (400° F). Spent shale is further cooled as it is transported to the
disposal area on conveyors.
Hot off-gas leaving the retort is cooled by incoming shale to
approximately 65° C (150° F), converting oil products in the off-gas stream to
a mist, that exits the retort in the off-gas stream. This oil product is
relatively dust free, has a pour point of approximately 30° C (85° F), and can
be recovered by an oil mist separator in conjunction with an electrostatic
precipitator.
The oil-free retort off-gas (product gas) has a low heating value (LHV)
of 4.5 x 106 J/m3 (120 Btu/ft3) on a wet basis. This low value is attributed
to dilution of the product gas by combustion products and high concentrations
of ammonia and hydrogen sulfide. Retort gas in excess of that required for
recycling is available for use as plant fuel.
Approximately two-thirds of retort off-gas is cooled by recycling through
gas distributors to the lower half of the retort and mixing with air. Cooling
of gas distributors represents a substantial portion of overall plant cooling
load. Cooling air supports combustion of coke residue on shale in the
combustion zone, and the recycled off-gas serves as a diluent to allow close
temperature control and even heating. This temperature control minimizes
carbonate decomposition, shale ash sintering, and clinker formation. Little
recycle gas is burned during coke combustion, because the incoming gas stream
is preheated by the descending hot shale, cooling the shale for discharge.
Shale processed with Paraho retorts has been shown to have approximately
2 percent residual carbon by weight, with the retorting process resulting in
approximately 22 percent carbonate decomposition.3 Some shale feed is crushed
while in the retort, resulting in an increased proportion of fine particle
material in the discharged (spent) shale.
4-8
-------
4.2.1.3.2 TOSCO II retorting process. The TOSCO II retorting process
operates in the indirect-heat mode, using hot ceramic balls to heat shale (see
Figure 4-4). Because of indirect heat transfer, shale must be crushed to a
particle size less than 1/2-inch diameter to allow complete pyrolysis of
kerogen. This finely crushed raw shale is preheated to about 260° C (550° F)
with hot flue gas from the ball heater and fed into a rotating pyrolysis drum.
Ceramic balls are heated to 700° C (1,300° F) in the ball heater and fed into
the drum, which mixes the balls and shale. The hot balls heat the shale to
about 480° C (900° F), and kerogen pyrolysis occurs. Shale oil vapor is taken
from the retort accumulator to an overhead fractionator. After leaving the
drum, ceramic balls are separated from spent shale by a rotating trommel.
Ceramic balls are reheated and reused. Carbon residue deposited on ceramic
balls in the pyrolysis process is used to provide part of the energy required
to operate the ball heater; the remainder is provided by process off-gas.
Spent shale goes to a heat exchange unit to produce steam for plant use and is
then cooled to about 150° C (300° F), moisturized to between 10 to 15 percent
water by weight, and disposed of. The shale preheating system is the primary
emission source, emitting combustion products, sulfur dioxide, nitrogen
oxides, particulates, hydrocarbons, and carbon monoxide.
4.2.1.3.3 Lurgi-Ruhrgas retorting process. The Lurgi retorting process
operates in the indirect-heat mode. In this process, raw shale is reduced to
the size of less than 8 inches in the primary crushers, with secondary and
tertiary crushing further reducing shale particles to less than 1/4 inch in
diameter. Crushed, raw shale is fed through a feed hopper into a double screw
mixer (see Figure 4-5), where it is thoroughly mixed with four to eight times
as much hot spent shale taken from the collecting bin. The spent shale, which
has a temperature of 650° to 700° C (1,200° to 1,300° F) heats the raw shale
to approximately 510° to 540° C (950° to 1,000° F) within a few seconds.
Retorting and distillation occur at these temperatures, yielding product gas,
shale oil vapor, and water vapor. The circulating spent shale, which carried
the heat, and the partially retorted shale are then dropped from the screw
mixer into the surge vessel, where residual oil components are removed by
distillation.
4-9
-------
Raw Shale
Flue Gas to Atmosphere
i
Cool Balls
Spent Shale
Cooler
Figure 4-4. Diagram of Tosco II process.
-------
HEAT
EXCHANGER
STACK
FEED
RESIDUE MOISTENING BOILER
(10% WATER) WATER FEED WATER
OILY
DUST
SCRUBBING
COOLERS
TO OIL
RECOVERY
Figure 4-5. Lurgi-Ruhrgas oil shale retorting process.
-------
The mixture of spent shale and retorted shale residue is raised to the
collecting bin by a pneumatic lift pipe, into which combustion air, preheated
to 230° to 480° C (450° to 900° F), is introduced. Essentially all available
organic carbon is burned from retorted shale residue in the lift pipe. In
addition, due to high lift pipe temperature, a moderate amount of carbonate
decomposes in the spent shale. At the top of the lift pipe, hot, retorted
shale is separated from flue gases and returned to the collecting bin as the
heat carrier. Fine spent shale is carried out of the' collecting bin with the
flue gas stream; coarse-grained shale residue accumulates in the lower section
of the collecting bin and flows continuously to the mixer. Combustion air
supplied to the lift pipe is preheated by countercurrent heat exchange with
the flue gas stream.
The product stream is withdrawn at the end of the mixer and passed
through two series-connected cyclones. Dust separated in these cyclones is
returned to the recycle system. The gas stream then passes through a sequence
of three scrubbing coolers. The first scrubbing cooler is designed to operate
at a higher temperature than the others to remove residual dust from the gas
stream by washing it with circulating, condensed heavy oil. (This scrubber is
primarily part of the product recovery process; any pollution control is
secondary in its design.) The dust-laden heavy oil may be thinned with light
oil to facilitate dust separation. In the next scrubbing cooler, major oil
condensation occurs at a temperature above water dew point to produce
dust-free heavy oil, which is recovered water free. In the last scrubbing
cooler, final cooling of the gas produces gas condensate water or gas liquor,
from which middle oil is separated in an oil/water separator. Finally, the
gas is scrubbed with light oil for recovery of 03"*", C4+, or 05"*", as deemed
desirable.
After it leaves the collecting bin, lift pipe flue gas is passed through
a cyclone and routed through a heat exchanger for preheating combustion air, a
waste heat boiler, a feed water preheater, another cyclone, and a humidifier.
After humidification and cooling, residual dust may be removed from the flue
gas stream by a baghouse. Other particulate control techniques could be used
in place of the humidifier and baghouse. Spent shale residue is moisturized
4-12
-------
to approximately 10 percent water by weight, cooled to a temperature of about
95° C (200° F), and disposed of.
4.2.2 In Situ Retorting Operations
In situ retorting is the generic name given to recovery processes in
which underground shale deposits are heated in place after rock permiability
is increased by fracturing or rubbling and, in some cases, after partial
mining. Two in situ retorting processes are being developed: the "true" in
situ process (TIS), which includes only well drilling and rock fracturing, and
the "modified" in situ process, (MIS) which requires mining to develop
underground retort chambers. The extent of mining in MIS depends on the
retort design. Figure 4-6 is a block diagram for oil shale operations in
which in situ retorts are used.
4.2.2.1 True In Situ. In TIS processes, dewatering may be necessary if
the shale deposit is below the ground water table. Fracturing or rubbling the
deposit may be needed to establish adequate permeability. To remove oil and
gas, energy must added, usually in the form of heat, to create a moving fire
front, pyrolyzing kerogen as it moves through the bed. Other removal methods
under investigation include steam injection and radio frequency heating.
Geokinetics is developing a horizontal TIS retorting process in which
blast holes are drilled from the surface, through the overburden, and into the
shale bed (see Figure 4-7). These holes are loaded with explosives and fired
in specific sequence to yield highly permeable, well-rubbled.shale and a
sloped bed bottom, from which shale oil and coproducts drain to a sump for
recovery by production wells.
After rubbling, oil shale is ignited with burning charcoal at air inlet
wells drilled at one end of the retort, establishing a horizontally moving
fire front. Off-gases containing oil mist exit through output holes in the
retort's downstream end. In Geokinetics1 process, these off-gases are passed
through an aboveground, three-chamber, packed-tower mist eliminator to remove
entrained oil and water. In a commercial facility, these off-gases may be
recycled into air inlet wells.
The shale oil and water mixture collected in the sump at the retorts
bottom is pumped to an aboveground oil/water separator, along with liquid
recovered from the mist eliminator. From the separator, the aqueous layer is
4-13
-------
Drilling
of
wells
Mined Shale to
surface retort
Partial mining
(modified in situ only)
Blasting to
rubblize shale
In situ
retorting
Product
gas
Shale
oil
I
Upgrading refining
Oil and gas recovery
Coking
Hydretreating
Figure 4-6. Block diagram of an in situ oil shale retorting operation.
4-14
-------
^
Air Injection Well
Liquid Production j
Well
Retort
Off-Gases
s
Oil/Water
£•$1 Mixture
Figure 4-7. Sectional view of a Geokinetics horizontal in situ oil shale retort.
-------
sent to the evaporation pond. Crude shale oil is pumped to storage tanks
before upgrading to a pipeline product.
4.2.2.2 Modified In Situ Retorting Process. One of the more thoroughly
tested in situ retorting technologies is the MIS process developed by
Occidental Petroleum Corporation. Occidental MIS retorts are formed by
rubbling vertical sections of oil shale, in place, after approximately 23
percent of a deposit has been mined, creating a void space (see Figure 4-8).
In designs by other developers, 15 to 40 percent of the shale might be mined
before rubbling. The void space allows for a more complete recovery of
kerogen decomposition products.
Occidental type MIS retorts are designed to have three horizontal layers:
(1) an upper level, where rubbling holes are drilled and where required
process air and steam are introduced; (2) an intermediate level, where
additional rubbling holes are drilled; and (3) a production level, where
retorting products—shale oil, gas, and water—are collected.
After levels are created through room and pillar mining, shale is
fractured through "symmetric" blasting, producing a uniform distribution of
space and fractured shale laterally across the retort. Relatively small
particle size (averaging 6 inches) and homogeneous distribution of fractured
shale in the retort is desirable for efficient operation.
In operation of a MIS retort, air and steam are admitted at the top
through several openings connecting the retort air level to the top of the
rubbled shale. Steam promotes water/gas reaction and provides means of
controlling combustion zone temperature. Retort startup is accomplished
through introduction of hot, inert gas. When the temperature of broken rock
at the top of the retort is high enough, air and a flame are introduced to
initiate combustion.
An operating MIS retort contains four major zones. In the first, a
preheat zone, air/steam feed gas is preheated through contact with hot spent
shale. The heated gas then reaches the combustion zone, where oxygen is
consumed by residual carbon burning in the spent shale. Below the combustion
zone is the retorting zone, where hot combustion gases heat raw shale rubble
to about 480° C (900° F) for retorting. Here, kerogen is pyrolyzed to produce
gas, oil and oil vapor, solid residue, and residual carbon. Shale oil and
4-16
-------
Off-Gas
Air
Drill/Air Distribution
Combustion Zone
1400° - 1600°
Retort Zone
900°
Broken Oil Shale
To StacP
Oil to Storage
Figure 4-8. Occidental modified in situ process.
4-17
-------
coproducts move downward by gravity and preceed the advancing combustion front
by 6 to 10 feet. In the final zone, combustion and retorting gases are cooled
as they flow downward, condensing some of the vaporized oil and—during early
burn stages, when the rock is still cool--some water.
Liquid oil and water condensed in the final zone flow from the bottom of
operating retorts into production-level drifts. These drifts are sloped to
allow gravity flow of the oil/water stream to the primary oil/water sumps,
located adjacent to the production-level drift bulkheads at each end of a
cluster of six retorts. After initial gravity separation, water and oil
products are pumped to the surface through independent systems.
At the surface, final separation is carried out in oil-in-water and
water-in-oil processes. Raw shale oil is transferred to product storage
without further treatment. Retort process water can be treated and used as
feedwater to produce part of the steam required at the beginning of the
retorting process. Retort gases are brought to the surface by large blowers
and fed to gas treating equipment, where cooling occurs. This cooling
produces a water condensate while the retort gases absorb ammonia, carbon
dioxide, and perhaps some hydrogen sulfide. This low-Btu gas with an LHV of
2.6 x 106 J/m3 (70 Btu/ft^) may be burned directly or further treated for
ranoval of potential air pollutants, such as H2S, before combustion.
4.2.3 Spent Shale Disposal
Once oil shale is mined, crushed, and retorted, spent shale must be used
or disposed of in an environmentally acceptable manner. The composition and
size range of spent shale particles largely depend on type of retorting
process used. These properties in turn determine possible uses and method and
ease of disposal.
Although spent shale usually occupies a greater volume than raw, inplace
shale, it is desirable to place as much of the spent material as possible back
in the mine. With proper moisture content, all or part of the spent shale can
likely be returned to the mine, packed completely to the roof, and allowed to
set. In this manner, mine subsidence can be prevented and unsightly waste
piles eliminated. Unfortunately, mining logistics and material handling costs
may make this option uneconomical.
4-18
-------
Disposal of spent shale in an open pit mine is attractive. Once the open
pit is large enough to accommodate both continued operation and spent shale
backfilling, all spent shale can be returned to the pit. The pit can then be
advanced with ongoing backfilling and reclamation.
Aboveground disposal of spent shale from underground mining/surface
retorting operations—proposed by several developers--!'s a potential
alternative to returning spent shale to an underground mine. This technique
involves simply disposing of spent shale in the vicinity of the processing
facility, where is is compacted and contoured into canyons or valleys or onto
relatively flat terrain. A valley site allows for disposal of large volumes,
surfaces requiring stabilization and revegetation are relatively small, and
most of the spent material is hidden from view. If the disposal site is in a
natural drainage path, efforts must be made to reroute natural water flows and
to minimize or eliminate natural leaching of water soluble material.
Reclamation and revegetation, with appropriate planning, can be conducted
along with placement of spent shale. These activities will result in
relatively small areas of unreclaimed spent shale at any time during active
disposal.
During MIS operations, oil shale mined and removed to the surface may be
processed in aboveground retorts, thus creating spent shale requiring
disposal. Because this is a relatively low-volume process, it has been
proposed that some or all of the spent shale from the surface retorts be
slurried and injected into underground retorts in which retorting has been
completed.
4.3 INDUSTRY PRODUCTION
4.3.1 Participating Organizations
Investors in research and development efforts and pilot and semi-works
facilities include many major U.S. energy companies and several smaller
organizations. Table 4-1 contains an up-to-date compilation of companies,
development project locations, technologies under development, and contacts.
In addition, the following parties also currently have an interest in oil
shale development and have provided additional information on resources and
technology:
Laramie Energy Techology Center
4-19
-------
TABLE 4-1. COMMERICAL/RESEARCH AND DEVELOPMENT PROJECTS
Name (Owner)
Location
Technology3
Contact
R1o Blanco
(Gulf and
Standard)
Tract C-a,
Piceance Creek
Basin, Colorado
Vertical MIS and
indirect heat-
surface
John Selters
(303) 878-4052
Cathedral Bluffs
(Occidental and
Tenneco)
Tract C-b,
Piceance Creek
Basin, Colorado
White River Tract Ua/Ub.
(Phillips, Sohio, Bonanza,
and Sunedco) Utah
TOSCO Sand Wash
(The Oil Shale
Corporation)
(Equity Oil
Company)
Colony
(Exxon and
TOSCO)
Union Long Rdige
(Union Oil
Company)
(Superior Oil
Company)
Vernal, Utah
Piceance Creek
Basin, Colorado
Southern Piceance
Creek Basin,
Colorado
Southern Piceance
Creek Basin,
Colorado
Northern Piceance
Creek Basin,
Colorado
Vertical MIS
Direct and in-
direct heat
surface retort
Indirect heat
surface
In situ-steam
injection
Indirect heat
surface
Indirect heat
surface
Chuck Bray
(303) 242-8463
Jim Goodlove
(801) 363-7628
Joe Morino
(303) 831-4567
Robert Lee
(713) 656-4626
John Hopkins
(213) 486-6437
Paraho Develop- Rifle, Colorado
ment Corporation
Direct heat
surface w/mineral
recovery
Direct heat Stuart Dykstra
surface (vertical) (303) 625-2100
IGT (Institute
of Gas Tech-
nology)
(Occidental Oil
Shale, Inc.)
Appalachian Basin HYTORT
Logan Wash,
Colorado
Vertical MIS
and indirect
heat surface
Bob Wilson
Chuck Bray
(303) 242-8463
(Geokinetics,
Inc.)
U.S. Bureau of
Mines (Multi-
Mineral Corp.)
Unitah County,
Utah
Northern Piceance
Creek Basin,
Colorado
Horizontal TIS
In situ w/
mineral
recovery
Rusty Lundberg
(801) 353-4343
Charlie Sullivan
(303) 761-5853
a MIS Modified in situ.
b TIS True in situ.
4-20
-------
Exxon Coal USA
Chevron
TRW--Navy Oil Shale Reserves
Shale Oil Science and Systems, Inc.
Industrial Resources, Inc.
Science Applications, Inc.
The Shaleglon Corporation.
The list in Table 4-1 is reasonably complete. However, interest in oil shale
is growing, and the number of interested parties is steadily increasing.
4.3.2 Production Volumes
Historically, shale oil production has been largely undocumented.
Table 4-2 lists the few operations in the United States that have produced
shale oil. Where a quantity could be determined it is presented. It should
be evident that the total quantity of shale oil produced is quite small when
compared to the total U.S. or world production of oil.3
4.3.3 Growth Trends and Plant Projections for Commercial Production
Facilities
4.3.3.1 Status of Oil Shale Projects. Region VIII of the U.S.
Environmental Protection Agency (EPA) in Denver, Colorado, has prepared a time
table for commercial operations of existing oil shale projects. From this
time table, presented in Table 4-3,4 it is estimated that by 1985 there will
be 8 operating commercial oil shale production facilities, with 3 more under
construction. By 1990 it is estimated there will be 12 operating commercial
facilities, with 2 more under construction. In 1995 it is estimated that
there will be a total of 14 commercial oil shale production facilities.
4.3.3.2 Cost and Resource Requirements. Production costs and resource
requirements for shale oil cannot be known with certainty until the industry
is established. Cost estimates and labor requirements can be made by
projecting cost data from current pilot-plant operations or by transferring
cost data from similar types of plants. Tables 4-4 and 4-5 present estimates
of capital and operating costs,5 and Table 4-6 presents estimates of labor
requirements.6 Land requirements have been estimated to be from 1,100 to
1,700 acres by 1990, from 5,800 to 8,400 acres by 1995, and from 15,500 to
24,600 acres by the year 2000.5 Disposal of spent shale may require the most
4-21
-------
TABLE 4-2. SHALE OIL PRODUCTION3
Dates
Producer/location
Retort type
Oil
Production
(bbls)
-ps.
l\3
May 1947 to June 1951
Jan 1950 to July 1955
1957 to 1958
July 1959 to Dec 1966
196*2
May 1964 to Sep 1967
1966 to 1967
1971 to 1972
1966 to 1968
Bureau of Mines/
Anvil Points, Colo.
Bureau of Mines/
Anvil Points, Colo.
Union Oil Colo./
Parachute Creek, Colo.
The Oil Shale Corp and
Denver Research Inst./
Zuni Street, Denver, Colo.
Mobil/Rio Blanco Cty.,
Colo., Beaver Bluff
in situ project
Six company group (Mobil,
Humble, PanAm, Sinclair,
Continental & Phillips.)/
Anvil Points, Colo.
Colony Development
Company/Parachute
Creek, Colo.
Equity Oil Co./Rio
Blanco County, Colo.
Direct surface- 20,300
batch
Indirect surface 11,000
Direct surface 20,000
Indirect surface 7,500
MIS
(2 burns)
23
Indirect surface 25,000
Indirect surface 180,000
Experimental MIS Unknown
(Continued)
-------
TABLE 4-2. SHALE OIL PRODUCTION3 (Continued)
Dates
Producer/location
Retort type
Oil
Production
(bbls)
ro
GO
1968 to 1971
Apr 1969 to May 1970
Oct 1969 to present
1970 to 1972
1974 to Aug 1976
Dec 1975 to present
July 1975 to present
Equity and ARCO/
Rio Blanco Country, Colo.
Laramie Energy Research
Center (BuMines)/
Laramie, Wyo.
Laramie Energy Research
Center (BuMines)/
Laramie, Wo.
Shell Oil Co./Piceance
Creek Basin
Seventeen company group/
Anvil Points, Colo.
Occidental Oil Shale, Inc./
Logan Wash, Colo.
Geokinetics, Inc./
Kamp Kerogen, Utah
Experimental MIS Unknown
TIS test sites
4 & 7
Direct surface-
batch
Leaching & TIS
retorting
Direct surface
MIS
TIS
570
1,000 +
420
10,000 +
99,500 and
continuing
12,000+
1976 to 1979
1976; 1978
IGT/Chicago, 111.
Sunoco-Toll Processed/
Brea, Calif.
Anvil Points, Colo.
Direct surface
Direct surface
Direct surface
24.5
25
24
(Continued)
-------
*.
ro
TABLE 4-2. SHALE OIL PRODUCTION3 (Continued)
Dates
Producer/1ocati on
Retort type
Oil
Production
(bbls)
1977 to Sep 1978
June 1979 to present
U.S. Navy and Development
Engineering Corp./
Anvil Points, Colo.
Equity Oil Co./
Peceance Creek, Colo.
Direct surface
MIS
100,000
None at
this time
-------
TABLE 4-3. PREDICTED SHALE OIL PRODUCTION LEVELS FROM WESTERN OIL SHALE RESOURCES, 1980 TO 19964
(barrels per calendar day)
ro
en
Oil shale projects
Occidental oil shale, lease
tract C-b
Project Rio Blanco lease
tract C-a
Geokenetics, Inc.,
Uinta Basin
Equity Oil,
Piceance Basin
Naval Oil Shale Reserve,
Piceance Basin
Demonstration of above-
ground retorting (DOE-PON)
Demonstration of advanced
retort technology (DOE-PON)
Union Oil, Long Ridge,
Piceance Basin
Colony/TOSCO, Parachute
Creek, Piceance Basin
TOSCO Sand Wash,
Uinta Basin
White River Project, lease
tract Ua, Ub, Uinta Basin
Chevron 01 1 ,
Piceance Basin
Superior Oi 1 ,
Pic.eance Basin
Mobil Oil,
Piceance Basin
Carter Oil
Cities Services
Total Projects
1980
1981
1982
1983
Pilot operation, engr.
Permitting, construction
Pilot operation, engr.
Permitting, construction
Same as
above
Pilot
operation
5,000
5,000
1984
6,250
19,000
10,000
1985
30,000
45,600
15,000
1986
50,000
76,000
25,000
1987
50,000
1988
87,500
1989
140,000
1990
200,000
1991 1992 1993 1994
1995 1996
Commercial operation
Commerical operation,
Engr. permitting, construction 90,800 111,600 135,000
40,000
50,000
Commercial
operation
Plans depend upon outcome of pilot operations
Feasibility study
Module modular plant
design, construction
8,000
Research
Construction
9,500
Design,
Permitting
4,000
Construction
28,000
41,500 50,000 Commercial operation
End
project
Pilot tests, engineering, permitting
Module construction
Module oper. ,
construction
Design construction
25,900
30,000
38,400
50,000
46,200
8,000
End
8,000 project
Commercial operation
Scale up 75,000
100,000
Commercial operation
Permitting,
construction
23,100
46,200
Exact schedule will depend upon outcome of litigation 45,000 90,000
Engr. permitting, pilot
module construction
7,000
Permitting construction
15,600
6,700
Engineering, permitting construction
Engineerin
0
0
~, permitting construction
24,200
10,000
6,000
16, tOO
32,800
12,000
6,000
24,900
41,400
50,000
66,600
83,200 100,000
Commercial operation
30,600
30,000
42,500
45,000
50,000
60,00(1
Commercial operation
scale up 78,000
91,500 100,000
Commercial operation
No definite plans at this time
14 L50oJ_22L50oJ 81, 650 1 181, 300 1 304, 200 1337^90ol446,80o| 557,900] 693, 000
723400 |755,200J82_l_._Oj30 942,_400
mi^no
-------
TABLE 4-4. CAPITAL REQUIREMENTS, 1980 to 20005
(billions of 1980 dollars)
Raw shale
production
Upgrading
1980 to 1985 1986 to 1990 1991 to 1995 1996 to 2000
1.25 to 1.38 1.88 to 7.88 8.38 to 10.5 7.38 to 26.4
0.13 to 0.16 0.20 to 0.68 0.87 to 0.91 0.77 to 2.29
Total
1.38 to 2.04 2.08 to 8.56 9.25 to 11.41 8.15 to 28.69
TABLE 4-5. ESTIMATED COSTS AS OF AUGUST 1979
(BASED ON LURGI TECHNOLOGY) FOR PRODUCTION OF
214 000 bbl/DAY OF OIL SHALE ON GOVERNMENT LAND°
Capital cost9
Step %
Processing 64
Mining 27
Other 9
Subtotal
Upgrading
(Hydrotreating)
Total
Cost/bbl,
daily
capacity
$ 6,579
$ 2,776
$ 925
$10,280
$ 2,086
$12,366
Cost/bbl
$3.21
$1.35
$0.45
$5.01
$1.00
$6.01
Operating costb
% Cost/bbl
30 $1.77
54 $3.19
16 $0.94
$5.90
$3.28
$9.18
Total
Cost/bbl
$ 4.98
$ 4.54
$ 1.39
$10.91
$ 4.28
$15.19
aCapita1 cost, other—support and infrastructure.
"Operation cost, other—general and adminstrative costs.
TABLE 4-6. LABOR REQUIREMENTS, 1980 to 20005
(thousands of person years)
1980 to 1985 1986 to 1990 1991 to 1995 1996 to 2000
Home office 1.5 to 1.8 2.2 to 7.6 9.7 to 10.2 8.6 to 25.5
Field construction 7.0 to 8.8 10.5 to 36.8 46.9 to 49.0 41.3 to 123.2
Operations and 0.75 to 0.94 6.6 to 14.5 22.5 to 36.9 46.7 to 82.5
maintenance
Total
9.3 to 11.5 19.3 to 58.9 79.1 to 96.1 96.6 to 231.2
4-26
-------
land. Water requirements for aboveground retorts have been estimated to range
from 360 to 720 liters (95 to 190 gallons) per barrel of oil. Similarly, it
has been estimated that MIS processes will require 360 liters (95 gallons) of
water per barrel of oil and that TIS proceses will require 340 liters (90
gallons) water per barrel of oil-5
4.4 REFERENCES
1. Selley, R. C. An Introduction to Sedimentology. New York, Academic
Press, 1976, p. 72-75.
2. Tucker, W. F., R. D. Noble, H. G. Harris, and L. P. Jackson. Thermal
Decomposition of Kerogen: Retorting, Separation, and Characterization of
Shale Oil. In: Thirteenth Oil Shale Symposium Proceedings, Gary, J. H.
(ed.). Golden, Colorado, Colorado School of Mines. 1980. p. 122-148.
3. Bates, Edward R. and Terry L. Thoem, eds. Environmental Perspectives on
the Emerging Oil Shale industry. Industrial Environmental Research
Laboratory, U.S. Environmental Protection Agency. Cincinnati, Ohio,
Publication No. EPA-600/2-80-205a. 1981. p. 324.
4. Oil Shale Briefing Book. Region VIII, U.S. Environmental Protection
Agency. Denver, Colorado. October 21-23, 1980.
5. Alternative Fuels Monitor: Oil From Shale. Hagler, Bailly and Company,
Washington, D.C. Publication No. 80-409-2. August 1980. p. 3.0-3.9.
6. Lewis, A. E. Oil Shale: A Framework for Development. In: Thirteenth
Oil Shale Symposium Proceedings, Gary, J. H., (ed.). Golden, Colorado,
Colorado School of Mines, 1980. p. 232-237.
4-27
-------
5. AIR EMISSIONS DEVELOPED IN SOURCE CATEGORY
5.1 INTRODUCTION
This chapter identifies and evaluates emission sources at oil shale
facilities to determine need, if any, for regulation under Sections 111 and
112 of the Clean Air Act, as amended. Availability of emission test data from
various oil shale facilities, methods used to acquire these data, and data
quality were assessed to achieve this goal. Emissions of both criteria and
noncriteria pollutants were considered.
Of potential synthetic fuel industries, the oil shale industry is perhaps
closest to commercialization in the United States. Several consortia and
companies have been developing oil shale technology for some time and have
established pilot-plant-scale projects in prime areas of Colorado and Utah.
The overall commitment by these organizations indicates good prospects for
full commercialization in the 1980s.
Because no commercial facilities presently exist, the data base on oil
shale pollution problems and control is meager, derived primarily from
bench-scale and pilot-plant operations. Extrapolation, to commercial scale,
of available oil shale data may have limitations and will require
valididation. However, bench-scale and pilot-plant data can help approximate
environmental pollution problems and will indicate potential approaches for
development.
Unfortunately, uncontrolled emission data for bench-scale and pilot-plant
oil shale operations were not accessible for this study. These data—used by
oil shale developers to project controlled emissions from planned facilities
for permit applications—have instead been approximated by reconstructing and
then reversing the developers' estimation process. Specifically, developers
usually estimate controlled emissions from bench-scale, pilot-plant, or
process material balance data by applying control factors equal to emission
limitations pe'rscribed in applicable State Implementation Plans (SIPs). (See
Chapter 1 for a review of State regulations applicable to the oil shale
5-1
-------
industry.) Thus, uncontrolled emission data presented in this study have been
backed out with applicable SIP control factors from estimated controlled
emissions listed in oil shale developers' permit applications.
Because these uncontrolled emission data are approximated rather than
actual, they may be insufficient for judgments of individual processes or
regulatory actions. They are presented here as uncontrolled emission
estimates and therefore can only grossly define emission control problems the
industry may encounter as it develops. As development proceeds, it is hoped
that these emissions estimates will be refined and upgraded. The scheduled
burn of a Occidental modified in situ (MIS) retort No. 7 at Logan Wash during
November 1981 through May 1982 could provide actual uncontrolled emissions
data.
5.2 AVAILABILITY OF DATA
During this study the following computer data bases were
searched for references to environmental impacts of extraction-acid processing
of oil shale:
National Technical Information Service (NTIS)
Compendix
APILIT
Chemical Abstracts
Enviroline
Energyline.
In each data base, data were sought under the following listings:
Shale oil Oil refining
Synthetic fuel • Particulates
Retorting • Sulfur compounds
Oil recovery • Oxides of nitrogen
Mining • Carbon monoxide
Crushing • Hydrocarbons (VOCs)
Screening • Trace metals
Retorting • Polycyclic organic material (POM)
Oil recovery • Arsenic.
5-2
-------
Several references were identified as containing emission data relative
to oil shale retorting.1»2,3,4,5,6,7 studies on retorts described in the
following subsections were evaluated for scientific validity and engineering
significance.
5.2.1 Geokinetics In Situ Retorting
Potential pollution sources of Geokinetics Retort No. 17 were
characterized by Monsanto Research Corporation (MRC).5 Particulate matter and
trace element sampling was performed with a modified U.S. Environmental
Protection Agency (EPA) Method 5. Particulate matter emissions in the
incinerator exhaust were 4.2 ton/yr (0.43 kg/hr). The sampling system probe
had a stainless steel liner that may have been corroded by the sampled gases,
biasing the total mass values. Analysis of incinerator outlet samples
indicated presence of tin, lead, and arsenic. The impinger media collection
efficiency is not completely documented and may not be high enough to prevent
negative bias of data on volatile trace elements, which are of environmental
concern. There are no data on emitted particulate matter sizing or
composition. These parameters are necessary to properly characterize
particulates.
5.2.2 Paraho Semi-Works Oil Shale Retort
Battelle Pacific Northwest Laboratory completed mass balances for 31
trace elements from the Paraho semi-works retort operated in the direct-heat
mode.^ The relative distribution of elements among products and effluents was
determined with accuracy and high precision in raw shale, retorted shale,
product oil, product water, and product gas. Data show 1 percent or greater
mass fractions of arsenic, cobalt, mercury, nitrogen, nickel, sulfur, and
selenium are released during retorting and distributed to the product shale
oil, retort water, or product off-gas. Fractions of these seven elements
ranged from 1 percent for cobalt and nickel to 50 percent for mercury and
nitrogen. Comparison of elemental distribution in various products indicates
that several retorting techniques exhibit common general patterns with respect
to redistribution of inorganic species. No sampling for particulate sizing or
its characterization was performed in this study.
TRW conducted an environmental testing program at the Paraho Shale Oil
demonstration plant.1 This program emphased measurements of recycle gas from
the Paraho retort and combustion products from a thermal oxidizer fueled by
5-3
-------
recycle gas and auxiliary fuel. Measurement included particulate matter, As,
and Hg. The impinger catch was not analyzed for Se and other volatile trace
elements, although TRW reports stibine (SbH3) at concentrations below the
detection limit.
5.2.3 Laramie Energy Technology Center In Situ Oil Shale Retorting
MRC evaluated particulate control efficiency of a 150-ton oil shale
retort at the Laramie Energy Technology Center.8 Because of small retort duct
size, single-point sampling was used to determine particulate emission rates
with an EPA-approved method. Particle size distribution was measured with
Anderson Mark III cascade impactors. A preimpactor was used to separate
coarse particles. Glass fiber collection substrates were used because the
particulate matter was oily. Sampling duration was 10 minutes at the inlet
and 20 minutes at the outlet. Outlet sampling time was too short because of
the low concentration of particulates in the outlet, and good size
distribution data were not be obtained. Therefore, only inlet data are
reported. Inlet data show that more than half the partculates (by weight)
have a diameter less than 5 ym, with about 10 percent having a diameter less
than 1 ym. Size distribution appeared bimodal, with fractions larger than 20
Mm (approximately 35 percent) and between 1 and 2 ym predominating.
Method 5 sampling indicated the retorting off-gases contained particulate
matter that can condense between 120°C (250° F) and about 20°C (70° F). The
inlet particulate concentration was found to be highly variable, ranging from
125 to 387 mg/m3. A venturi scrubber consistently achieved an average outlet
concentration of 35 mg/m3 despite the three-fold variation in inlet
concentrations. Data show an average scrubber collection efficiency of 86
percent. No attempts are reported to characterize the particulate matter in
terms of chemical composition.
5.3 PROCESS EMISSIONS REVIEW
Although oil shale deposits occur throughout the world, U.S. deposits are
among the richest, most extensive, and best explored. Oil shale is commonly
defined as a fine-grained, sedimentary rock containing kerogen, an organic
matter that yields oil during pyrolysis. Two methods for producing oil from
oil shale are under active investigation: surface retorting and in situ
5-4
-------
retorting. In both methods, sources of air pollutant emissions include
mining, processing, retorting, and processed shale disposal processes.
5.3.1 Mining
Mining activities in the oil shale industry are expected to be among
the largest in the world. Potential exists for atmospheric pollution in all
phases of mining—excavation, blasting, crushing, transfer, and equipment
operation. Although open-pit mining has been suggested as a surface mining
technique applicable to oil shale extraction, no developer currently has plans
to employ it.4 Consequently, only underground mining operation data are
presented. Table 5-1 shows atmospheric emission estimates (control system not
reported) for underground mining operations required to support a
50,000-bbl/day shale oil facility. These estimates are based on limited
information and only provide ranges within which atmospheric emissions from
mining might fall.
5.3.2 Processing
Fugitive dust from processing raw shale for retorting is a significant
source of particulate matter emissions. All surface retorting operations
require size reduction of mined shale, and some surface retorts require
secondary crushing. Transportation and disposal of processed shale also
contribute to particulate loading in ambient air. Table 5-2 shows estimate
controlled emissions for primary and secondary crushing and for transportation
and storage. While degree of control is not specified in Table 5-2, it is
reasonable to assume that control systems for stone quarrying and processing
are also applicable for raw oil shale processing. Control efficiencies for
these systems typically range from 75 to 99 percent for primary and secondary
crushing operations.9
Controlling fugitive emissions from raw shale storage and transportation
normally consists of wetting or covering, from which 80 percent control
efficiency is estimated.10 Assuming 80 percent capture efficiency at the
crushers and applying applicable SIP emission factors to controlled emission
data results in the following estimates of uncontrolled particulate emissions
from primary and secondary crushing, storage, and transportation of mined
shale (normalized to a 50,000-bbl/day shale oil operation):
5-5
-------
ui
i
en
TABLE 5-1. ESTIMATED UNCONTROLLED ATMOSPHERIC EMISSION RANGES FOR UNDERGROUND MINING
OPERATIONS—SO,000-bbl/DAY SHALE OIL FACILITY11
Mining
operation
Excavation
(mining)
Blasting
Ground vehicles
Total
Particulate matter
0.01 to 0.92
0.03 to 19.15
0.01 to 0.15
0.08e to 20.22
Atmospheric emissions (Mg/day)a
Sulfur dioxide Nitrogen oxide
0.08C 2.95C
Not reported 0.36 to 0.77
0.004 to 0.005 0.007 to 2.99
0.004f to 0.089 0.0076 to 3.769
,b
Hydrocarbons
Not reported^
Not reported
0.01 to 0.59
O.Oie to 0.59f
Carbon monoxide
Not reported^
0.359 to 0.768
0.03 to 5.18
0.0396 to 5.18d
aColumns may not total because ranges are from different programs.
^Degree of control unknown; assumed to be uncontrolled.
C0nly value reported.
^Emissions from excavation were not reported.
Emissions from blasting were not reported.
^Consists of only ground vehicle emissions.
9Consists of only excavation emissions.
-------
TABLE 5-2. ESTIMATED CONTROLLED PARTICULATE EMISSIONS FROM CRUSHING,
TRANSPORTATION, AND STORAGE OF RAW SHALE AND DISPOSAL OF SPENT SHALE—
50,000-bbl/DAY OIL SHALE FACILITY^
Operation
Atmospheric emissions,
Mg/day (ton/day)a«b
Primary and secondary crushing
Storage and transportation0
Total
0.292 to 1.030
0.043 to 0.192
0.335 to 1.175
(0.322 to 1.135)
(0.047 to 0.212)
(0.369 to 1.295)
aColumns may not total because ranges are from different programs.
^Degree of contol not reported.
Clnc1udes spent shale disposal.
5-7
-------
Primary and secondary crushing, 0.468 to 0.515 Mg/day (0.516 to
0.568 ton/day)
Storage and transportation, 0.072 to 0.181 Mg/day (0.079 to 0.200
ton/day).
5.3.3 Retorting
Processing and disposal of shale oil and off-gases produced during
retorting is a major air pollution problem for the oil shale industry. For
the purposes of this study, retorting emissions include those from retorting,
from subsequent treatment of shale oil and offgases, and from onsite use and
dispoal of off-gases.
Covering all retorting technologies, the following are ranges of
estimated controlled emissions from oil shale retorting in a 50,000-bbl/day
facility;13
Range of estimated
Pollutant controlled emissions
Mg/day ton/day
Particulate matter 0.13 to 7.81 0.14 to 8.60
Sulfur oxide 0.20 to 19.00 0.22 to 20.94
Nitrogen oxide 6.02 to 64.16 6.63 to 70.70
Hydrocarbons 0.27 to 28.25 0.30 to 31.1-3
Carbon monoxide 0.43 to 1.91 0.47 to 2.11
No degree of control was reported, nor any explanation given for orders of
magnitude differences in some ranges.
Except for sulfur oxides, data are insufficient for estimating
uncontrolled retorting emissions. During retorting, sulfur can be released to
the atmosphere in several ways. Raw shale contains sulfur, both organically
(approximately 33 percent) and inorganically bonded. During pyrolysis and/or
partial oxidation, the organic fraction undergoes reaction, with about 40
percent released as hydrogen sulfide and other gaseous sulfur compounds such
as sulfur dioxide, carbon disulfide, carbonyl sulfide, and, possibly,
thiocyanates--all of environmental concern. The rest of the organic sulfur
remains in the shale oil as heavier sulfur-containing compounds. For ease of
comparison and because sufficient data characterizing effluent streams are not
5-8
-------
available for each sulfur compound, emissions are estimated as sulfur dioxide
equivalents. Based on a yield of 60 to 125 £/Mg (15 to 30 gal/ton) of
shale,14 uncontrolled sulfur oxide emissions from retorting are estimated to
at 120 and 240 Mg/day for a 50,000-bbl/day facility.
Nitrogen oxides can result from burning or pyrolyzing of fuel containing
nitrogen and can be produced from elemental nitrogen in the oxidizing medium.
Nitrogen oxides formation rate depends on fuel nitrogen content and combustion
conditions. Raw oil shale is nitrogen rich and may be a significant nitrogen
oxides source.
Pyrolyzing atmosphere is low in oxygen, so significant amounts of
hydrocarbons are present in the gas stream. Similarly, carbon monoxide is
formed from incomplete combustion. To date, attempts to characterize
hydrocarbons in oil shale retort emissions have been limited.
Retorting operations also emit particulates, with amounts depending on
type of retort. Trace elements may be included in particulate matter and may
be emitted both as vapors and as solids, possibly as submicron-sized aerosols.
Limited research indicates arsenic, mercury, iron, chromium, and zinc as
possible trace-element emissions.1'15'16
Trace element emissions from oil shale retorting could be problematic and
warrant more research, as do sample preservation, sample preparation, and
analysis methodology. Experience indicates that analytical parameters such as
precision, accuracy, sensitivity, and specificity are highly dependent on
sample matrix. Therefore, analytical methods should be evaluated for these
parameters to increase the data validity and usefulness. Trace element
emissions may also depend on pyrolysis conditions. Work related to
size-dependent sampling and chemical characterization of particle size classes
needs to be performed, although the literature reports only one investigation
of size dependent sampling.5
Table 5-3 contains reported composition of shale oil retort off-gases for
five technologies.^ While compositions shown in Table 5-3 are based on
limited data, they serve as a screen for selecting sulfur removal technolgies
to consider for application to the oil shale industry.
5-9
-------
TABLE 5-3. COMPOSITION OF OIL SHALE RETORT OFF-GASES3
cn
i
Retort typea
Paraho direct heated surface
Occidental, MIS
Geokinetics, TIS
Union Oil, indirect-heat
surface
TOSCO II, indirect-heat
surface
Composition (Average Volume %)
Cl+
5.22
3.76
2.43
51.19
51.19
C02
22.81
32.26
23.48
16.62
20.38
CO
2.50
0.89
8.03
4.85
3.40
H2
4.74
7.65
7.47
23.34
20.20
H2S
0.30
0.10
0.13
3.82
4.12
Other
Keduced
Sulfur
b
40 ppmc
40 ppm6
726 ppm
170 ppm
NH3
0.70
d
0.06
d
f
N2
63.8
56.41
57.4
0.11
9
02
0.9
0.08
1.13
d
9
S02
17 ppm
0.15
d
125 ppm
g
NOX
168 ppm
0.03
d
d
g
Comments
Mean values observed
during 1977 and 1978
Gas produced at midpoint
of Retort 6 run
Average composition,
Retort 18
Estimate composition; not
based on active burns.
Average composition
produced by TOSCO II
retort
aHIS = modified in situ; TIS = true in situ.
bNo CS2, RSN, COS detected. Organic sulfur compounds 250 ppm.
CCOS only range 1-40 ppm. No data on other reduced sulfur species.
dNo data.
eCOS only. No data on other reduced sulfur species.
^Partitioned into water phase. Does not appear in gas.
9None reported.
-------
5.3.4 Spent Shale Disposal
Disposing of large quantities of spent shale presents a problem, except
in the true in situ (TIS) process. Transfer, handling, and disposal could
cause problems of particulate entrainment and/or hydrocarbon vaporization from
hot shale. Some trace elements also might be involved in such emissions.
Sufficient information regarding emissions from spent shale disposal could not
be identified.
5.4 EMISSION FACTORS
As discussed in Chapter 4, seven separate proposals exist to construct
commercial oil shale retorting plants with the intent to develop a commercial
project. Table 5-4 contains brief descriptions of these projects, estimated
emissions, and planned control systems. These emission rates are gross
estimates based on pilot-plant and bench-scale emissions data and material
balances.
Data in Table 5-4 can be used to estimate uncontrolled emissions from
shale oil processing. These estimates are shown in Tables 5-5 and 5-6
normalized to 1,000 barrels of shale oil. The range of estimated emission
factors can be summarized as follows:
Uncontrolled emission factor,
Pollutant kg/103 bbl (1b/103 bbl) shale oil
Particulate matter 61 to 242 (134 to 534)
Sulfur oxide 550 to 6,600 (1,212 to 14,553)
Nitrogen oxide 93 (205)
Hydrocarbons 60 to 3,980 (132 to 8,775)
Carbon monoxide 280 to 1,420 (617 to 3,131)
These data reflect emission ranges reported for the seven proposed
commerical facilities and are presented to illustrate ranges that could be
experienced. These ranges are based on estimated emissions and could be
greater because of high uncertainty for data upon which these ranges are
based. Emission factors for a specific facility must be determined based on
technology, production rate, and control system used. Because of data
5-11
-------
TABLE 5-4. ESTIMATED EMISSIONS, OIL SHALE PROJECTS18
Developer
Rio Blanco
10-year MOP
Commercial
Development
Cathedral
Bluffs
White River
Phase II
Phase III
Colony
Development
Union Oil"
Superior Oil
Occidental
TOTAL"
Planned
capacity,
bbl/day
b
76,000d
57,000
6,0009
100,000
47,000
9.0001
11,586
1
Retort
technology
Modified in situ
Modified in situ
Modified in situf
Combination of
direct- and indi-
rect-heat surface
retort
Indirect-heat
surface retort
Indirect-heat
surface retort
Direct-heat
surface retort
Modified in situ
Particulate matter
kg/103 bbt
shale oil Mg/day
0.3
68 5.1
14 0.8
120 0.7
99 9.9
53 2.5
51 0.5
71J 0.8J
0.1
2.00
Sulfur oxide
kg/103 bbl
shale oil Mg/day
1.9
66 5.0
33 1.9
15 0.1
33 3.3
66 3.1
98 0.9
326 3.8
0.3™
20.2
Controlled emissions
Nitrogen oxide
kg/103 bbl
shale oil Mg/day
9.7
339 25.8
112 6.4
197 1.2
294 29.4
361 16.9
120 1.1
162 1.9
0.6
91.8
a
Hydrocarbons
kg/103 bbl
shale oil Mg/day
0.3C
24 2.5e
3 0.2
2 <0.1
12 1.2
63 3.1
52 0.5
19k 0.2k
1.7
9.7
Carbon monoxide
kg/103 bbl
shale oil Mg/day
Hot reported
Not reported
16 0.9
24 0.1
34 3.4
14 0.7
71 0.6
44 0.5
39.3
45.4
'
Control systems
Incineration and Na?C03 scrubber
Sulfinol 112$ removal for surface
retort gas. St retford I^S
removal in situ gas
St ret ford HpS removal
Not reported
Not reported
Gas treatment to remove
H;>S and CO; gas removal
by diethanolamine
absorption; CLAUS plant
with a Wellman-Lord
tail gas cleanup
Venturi scrubber,
Stretford H2S Removal
Nat reported
Stretford unit on slip-
stream of retort off-gas
"•includes emissions from all mining and processing activities unless otherwise indicated.
blncludes three retorts, largest of which will have 750 bbl/day capacity.
clncludes 0.3 Mg/day from tank vapor losses.
dShale from drift and retort development will be processed in a TOSCO II indirect-heat surface retort.
Rio Blanco is also studying the Lurgi-Rubirgas.
elncludes 0.7 Mg/day from tank vapor losses.
^Raw shale produced during mine development (estimated at 41,000 ton/day) will be disposed of without retorting.
SEstimated from data in Reference 1, p. A-21.
hTest project.
''Experimental retort. Commercial modification projected at 100,000 bbl/day.
Jlncludes emissions from nacholite and alumina recovery processes.
*Nonmethane hydrocarbons.
^No data given; research and development installation.
m41 My/day H;,S also estimated.
"Totals do not include White River Phase I emissions.
-------
TABLE 5-5. ESTIMATED UNCONTROLLED PARTICULATE MATTER, SULFUR OXIDE, AND NITROGEN OXIDE
EMISSION FACTORS—OIL SHALE PROCESSING, ALL EMISSIONS SOURCES
Developer
Rio Blanco
Cathedral Bluffs
White River,
Phase 111
Colony
Union Oil
Superior Oil
Participate
matter3
Uncontrol led
emissions,
kg/103 bbl
shale oil
104 to 242
INS
301
61
INS
INS
Sulfur oxide
Controlled,
emissions,
kg/103 bbl
shale oil
66
33
33
66
98
326
Control system
Type
SulHnol Oil
Stretford
Not reported
Claus plus
Wellman Lord
Stretford
Not reported
Efficiency
(percent)
96 to 99b
94b
INS
97.5 to 98. 5d
94 b
INS
Uncontrolled
emission
factors,
kg/103 bbl
of shale oil
1,650 to 6,600
550
INS
2,640 to 4,400
1,633
INS
Nitrogen oxide
Controlled
emissions,
kg/103 bbl
of
shale oil
339
112
294
361
120
162
Control system
Type
Not reported
Ammonia
remov a 1
Not reported
Not reported
Not reported
Not reported
Efficiency
(percent)
INS
93C
INS
INS
INS
INS
Uncontrolled
emission
factors,
kg/103 bbl
shale oil
INS
1,600
INS
INS
INS
INS
Ul
I—"
CO
INS = Insufficient data.
Reference 15.
''Estimated from data—Reference 16.
Reference 17, p. 25.
on a Claus efficiency of 65 to 85 percent and Wellman Lord 90 percent.
-------
cn
i—>
-p.
TABLE 5-6. ESTIMATED UNCONTROLLED HYDROCARBON AND CARBON MONOXIDE
EMISSION FACTORS—OIL SHALE PROCESSING, ALL EMISSION SOURCES
Developer
Rio Blanco
Cathedral Bluffs
White River,
Phase III
Colony
Union Oil
Superior Oil
Hyrdocarbons
Controlled
emission factors,
kg/103 bbl
shale oil
24
3
12
63
52
199
Control
efficiency3
95
95
95
95
95
95
Uncontrolled
emission
factors,
kg/103 bbl
shale oil
486
60
240
1,260
1,040
3,980
Carbon monoxide
Controlled
emission factors,
kg/103 bbl
shale oil
Not reported
16
34
14
71
44
Control
efficiency3
95
9o
95
95
95
95
Uncontrolled
emission
factors,
kg/103 bbl
shale oil
INS
320
680
280
1,420
880
INS = Insufficient data.
3Assumed to be an after burner.
-------
limitations, extrapolation to commercial scale emission rates may not yield
accurate values.
5.5 ESTIMATES OF NATIONWIDE EMISSIONS
The oil shale industry is one of the few synfuel industries currently
showing rapid development. Although commercialization is planned within the
next few years, only seven firms have filed the Detail Development Plan and
other related documents required for commercialization. Based on data from
these firms, nationwide emissions from oil shale industries can be estimated.
As previously mentioned, emissions data upon which these estimates are made
are from limited pilot-plant and bench-scale operations. While individual
data have high uncertainty, resulting estimates indicate the nature and extent
of air pollution problems associated with oil shale processing. For the
estimates, air emissions from various process streams of some proposed oil
shale plants were not included because they lacked information on current
status. When such data are available, these estimates should be revised.
Based on the program development schedule shown in Table 4-3 (see
Chapter 4) and on estimated emissions shown in Tables 5-5 and 5-6, estimated
nationwide actual emissions of criteria pollutants for 1985, 1990, and 1995
are shown in Table 5-7. Similar estimates for noncriteria pollutants,
including trace metals, cannot be made until more emission data are available.
Emissions shown in Table 5-7 are based on estimated production data provided
by industry and represent emissions after the control systems currently
planned for installation.
Estimated uncontrolled emissions for 1985, 1990, and 1995 are shown in
Tables 5-8 through 5-12 for particulate matter, sulfur oxide, nitrogen oxide,
hydrocarbons, and carbon monoxide, respectively. These data are rough
estimates and should be refined as more emission data become available.
Nitrogen oxide emission estimates are especially questionable in that the
industrywide estimate is based on data from only one planned facility.
It should be noted that emission estimates are based on projected
production levels made in the late 1970s. There has been slippage in target
dates. However, estimated emissions provide a time series of how emissions
5-15
-------
TABLE 5-7. ESTIMATED ACTUAL EMISSIONS OF CRITERIA POLLUTANTS FROM PLANNED OIL SHALE
DEVELOPMENT PROJECTS—1985, 1990, AND 1995
Oeveloper
Projects for which estimated
emissions data were available
lUo fllanco
Cathedral muffs
Whllp River
l.nlony
Union Oil
Superior Oil
Subtotal
Project foi which estimated
emissions data were not available
Occidental1'
Geofcrnet ics0
Naval Oil Reserve0
IOSCO, \l-br
Chpvronr
Mohllr
Carter Oi|C
Subtotal11
total
Projected
production.
l.hl shale
oil per
calendar
day*
15,000
30,000
__
30,100
30,000
6,700
150,100
__
15,000
__
—
15.600
„_
__
30,600
100,700
1905
Emissions, Mg
Parti-
al! ate Sulfur Nitrogen Hydro- Carbon
matter oxide oxide carbons monoxide
1,117 1.001 5,560 391 b
I53 361 1,226 33 175
_-
713 925 5,060 833 196
550 1,073 1,311 569 771
171 797 396 16 100
2,715 4,210 13,561 1,075 1,253
560 061 2,765 302 255
3,305 5,101 16,329 2,257 1,500
Projected
production,
bhl shale
oil per
calendar
daya
76,000
200,000
16,300
50,000
12,000
301,200
__
50,000
20,000
16,200
66,600
50,000
60,000
300,000
605,000
1 990
Emissions, Mg
Parti-
culatc Sulfur Nitrogen Hydro- Carhon
matter oxide oxide carbons monoxide
1,006 1,031 9,101 666 b
1,022 2.409 0,176 219 1.160
891 1,113 6,500 1.062 236
931 1,709 2.190 949 1,296
311 1,120 710 03 193
5,011 0,570 27,060 2,979 2,093
3,919 6,7)0 21,192 2,332 2,265
8,993 15,200 10,260 5, 31 1 5,158
Projected
product ion.
hbl shale
oil per
calendar
daya
135,000
200,000
90,000
16,200
100,000
12,000
503,200
__
50,000
50,000
16,200
100,000
91,500
60,000
397,700
900,900
1995
emissions, My
Parti-
cipate Sulfur Nitrogen Hydro- Carbon
matter oxide oxide carbons monoxide
1,806 1,031 9,101 666 b
1,023 2,109 8,176 219 1,160
3,252 1,081 9,657 391 I.I17
091 1,113 6,500 1,062 216
1,062 3,577 1,300 1,090 2,512
311 1,120 710 03 191
9,227 11,112 30,915 1,322 5,1(16
6,292 7,803 26,537 2,917 3.6IO
15,519 19,217 65,452 7,269 0,971
^Hcfcrencp 19.
''No data reported-
cNo emission
-------
TABLE 5-8. ESTIMATED UNCONTROLLED PARTICULATE MATTER EMISSIONS
FROM PLANNED OIL SHALE DEVELOPMENT PROJECTS--1985, 1990, 1995
en
i
Project
Projects for which estimated
emissions data were available
Rio Blanco
White River
Colony
Subtotal
Projects for which estimated
emissions data were not
available
Cathedral Bluffs
Union Oil
Superior Oil
Occidental11
Geokenetics
Naval Oil Reserve
TOSCO, U-b
Chevron
Mobil
Carter Oil
Subtotal
TOTAL
Production,
bbl/
calendar
daya
45,000
—
38,400
83,400
30,000
30,000
6,700
—
15,000
—
—
15,600
--
—
97,300
180,700
1985
Emission
factor,
kg/103 ijoi
173b
61
Ann"*1
emissions,
Mg
2,840
855
3,695
4,310
8.005
Production,
bbl/
calendar
day3
76,000
—
46,200
122,200
200,000
50,000
12,000
—
50,000
28,000
46,200
66,600
50,000
60,000
562,800
685,000
1990
Emission
factor,
kg/103 bbl
173C
61
Annual
emission,
Hg
4,800
1,030
5,830
26,850
32,600
Production,
bbl/
calendar
daya
135,000
90,000
46,200
271,200
200,000
100,000
12,000
--
50,000
50,000
46,200
100,000
91,500
60,000
709,700
980,900
1995
Emission
factor,
kg/103 bbl
173C
301
61
Annual
emissions,
Mg
8,520
9,890
1,030
19,440
50,870
70,310
^Reference 19.
Emissions estimated on assumption that average emission factors are the same as those for which emission data are available.
cAverage of 104 and 242 kg/103 bbl.
dNo data reported.
-------
TABLE 5-9. ESTIMATED UNCONTROLLED SULFUR OXIDE EMISSIONS
FROM PLANNED OIL SHALE DEVELOPMENT PROJECTS—1985, 1990, 1995
en
i—>
Co
Project
Projects for which estimated
emissions data were available
Rio Blanco
Cathedral Bluffs
Colony
Union Oil
Subtotal
Projects for which estimated
emissions data were not
available
White River
Superior Oil
Occidental
Geokenetics
Naval Oil Reserve
TOSCO, U-b
Chevron
Mobil
Carter Oil
Subtotal6
TOTAL
1985
Production,
bbl/
calendar
day3
45,000
30,000
38,400
30,000
143,400
6,700
—
15,000
—
—
15,600
—
—
37,300
180,700
Emission
factor,
kg/103 bbl
4,125b
550
3.52QC
1,633
Annual
emissions,
Mg
67,750
6,025
49,335
17,880
140,990
36,675
177,665
1990
Production,
bbl/
calendar
daya
76,000
200,000
46,200
50,000
372,200
12,000
—
50,000
28^000
46,200
66,600
50,000
60,000
312,800
685,000
Emission
factor,
kg/10J bbl
4,125^
550
3.52QC
1,633
Annual
emissions,
Mg
114,430
40,150
59,360
29,800
243,740
204,840
448,580
1995
Production,
bbl/
calendar
day3
135,000
200,000
46,200
100,000
481,200
90,000
12,000
—
50,000
50,000
46,200
100,000
91,500
60,000
499,700
980,900
Emission
factor,
kg/103 bbl
4,125t>
550
2.52QC
1,633
Annual
emissions,
Mg
203,260
40,150
59,360
59,605
362,375
376,305
738,680
Reference 19.
bAverage of 1,650 and 6,600 kg/103 bbl.
cAverage of 2,640 and 4,400 kg/103 bbl.
^No data reported.
Emissions estimated on assumption that average emission factors are the same as those for w"hich emission data are available.
-------
TABLE 5-10. ESTIMATED UNCONTROLLED NITROGEN OXIDE EMISSIONS
FROM PLANNED OIL SHALE DEVELOPMENT PROJECTS—1985, 1990, 1995
en
I
Project
Projects for which estimated
emissions data were available
Cathedral Bluffs
Subtotal
Projects for which estimated
emissions data were not
available
Kio Blanco
White River
Colony
Union Oil
Superior Oil
Occidental11
Geokenetlcs
Naval Oil Reserve
rosco, u-b
Chevron
Mobil
Carter Oil
Subtotal0
fUIAL
Production,
bbl/
calendar
day3
30,000
30,000
45,000
—
38,400
30,000
6,700
--
15,000
—
—
15,600
--
--
150,700
180,700
1985
Emission
factor,
kg/103 bbl
93
Annual
emissions,
My
1,020
1,020
5,125
6,145
Production,
bbl/
calendar
day3
200,000
200,000
76,000
--
46,200
50,000
12,000
-
50,000
28,000
46,200
66,600
50,000
60,000
485.000
685,000
1990
Emission
factor,
kg/103 bbl
93
Annual
emissions,
Mg
6,790
6,790
16,465
23,255
Production,
bbl/
calendar
day9
200,000
200,000
135,000
90,000
46,200
100,000
12,000
--
50,000
50,000
46,200
100,000
91,500
60,000
/80,900
900,900
1^0
Emission
factor,
kg/103 bbl
93
Annual
emissions,
Mg
6,790
6,790
26,510
33,300
dl(eference 19.
bflo data reported.
clmissioiib estimated on assumption that average emission factors die I he same as those fur which emission ddt.j are available.
-------
TABLE 5-11. ESTIMATED UNCONTROLLED HYDROCARBON EMISSIONS FROM PLANNED
OIL SHALE DEVELOPMENT PROJECTS—1985, 1990, 1995
Project
Projects for which estimated
emissions data were
available
Rio Blanco
Cathedral Bluffs
White River
Colony
Union Oil
Superior Oil
Subtotal
Projects for which estimated
emissions data were not
available
Occidental1*
Geokenetics
Naval Oil Reserve
TOSCO, U-b
Chevron
Mobil
Carter Oil
Subtotal
TOTAL
1985
Production,
bbl /calendar
daya
45,000
30,000
—
38,400
30,000
6,700
150,100
15,000
—
—
15,600
—
--
30,600
180,700
Emission
factor,
kg/103bbl
480
60
1,260
1,040
3,980
Annual
emissions,
My
7,885
655
17,660
11,390
9,735
47,325
9,650
56,975
1990
Production,
bbl /calendar
day3
76,000
200,000
—
46,200
50,000
12,000
384,200
50,000
28,000
46,200
66,600
50,000
60,000
300,800
685,000
Emission
factor,
kg/103bbl
480
60
1,260
1,040
3,980
Annual
emissions,
Mg
13,315
4,380
21,245
19,980
17,430
76,350
59,775
136,125
1995
Production,
bbl/calendar
day3
135,000
200,000
90,000
46,200
100,000
12,000
583,200
50,000
50,000
46,200
100,000
91,500
60,000
397,700
980,900
Emission
factor,
kg/103bbl
480
60
240
1,260
1,040
3,980
Annual
emissions,
Mg
23,650
4,380
7,885
21,245
37,900
17,430
112,550
76,750
189,300
PO
O
Reference 19.
DNo data reported
cEmissions estimated on assumption that average emission factors are the same .is those for which emission data are available.
-------
TABLE 5-12. ESTIMATED UNCONTROLLED CARBON MONOXIDE EMISSIONS FROM PLANNED
OIL SHALE DEVELOPMENT PROJECTS—1985, 1990, 1995
en
i
rv>
Project
Projects for which estimated
emissions data were
available
Cathedral Bluffs
White River
Colony
Union Oil
Superior Oil
Subtotal
Projects for which estimated
emissions data were not
available
Rio Blanco
Occidental15
Geokenetics
Naval Oil Reserve
TOSCO, U-b
Chevron
Mobil
Carter Oil
Subtotal0
TOTAL
Production,
bbl/calendar
daya
30,000
—
38,400
30,000
6,700
105,100
45,000
--
15,000
--
--
15,600
--
—
75,600
180,700
1985
Emission
factor,
kg/103bbl
320
—
280
1,420
880
Annual
emissions,
Mg
3,505
—
3,925
15,550
2,150
25,130
18,075
43,205
Production,
bbl/calendar
day3
200,000
—
46,200
50,000
12,000
308,200
76,000
—
50,000
28,000
46,200
66,600
50,000
60,000
376,800
685,000
1990
Emission
factor,
kg/103bbl
320
--
280
1,420
880
Annual
emissions,
Mg
23,360
—
4,720
25,915
3,855
57,850
70,725
128,575
Production,
bbl/calendar
day3
200,000
90,000
46,200
100,000
12,000
448,200
135,000
—
50,000
50,000
46,200
100,000
91,500
60,000
532,700
980,900
1995
Emission
factor,
kg/103bbl
320
680
280
1,420
880
Annual
emissions,
Mg
23,360
23,340
4 , 720
51,830
3,855
107,105
127,300
234,405
^Reference 13.
''No data reported.
Emissions estimated on assumption that average emission factors are the same as those for which emission data are available.
-------
will increase as shale oil projects are commercialized. It should also be
noted that limitations on development by Prevention of Significant
Deterioration (PSD) requirements were not in projected production levels. It
is conceivable that PSD-allowable increments could be exhausted before
production levels used in the emission estimates are achieved.
5.6 RECOMMENDATIONS
As noted in preceding sections, emission data for the oil shale industry
are limited. The following actions should be taken to improve the data base
to the level required for New Source Performance Standard (NSPS) development:
Evaluation of basis for existing data, mode of acquisition, data
quality, and data completeness.
Filling of data gaps, as revealed by the evaluation.
Characterization of emission streams and fugitive emissions
resulting from each of the various surface and in situ retorting
processes. Work may include acquiring data on size-dependent mass
emissions (fine particles) as well as chemical characterization of
such samples.
5.7 REFERENCES
1. Cotter, J. E., D. J. Power!!, and C. Habenicht. Sampling and Analysis
for Retort and Combustion Gases at the Paraho Shale Oil Demonstration
Plant. U.S. Environmental Protection Agency. Cincinnati, Ohio.
Publication No. EPA-600/7-78-065. 1978.
2. Field Testing to Determine the Presence or Absence of Sulfur Dioxide
Emissions from Old In Situ Oil Shale Field-Sites. Science Applications,
Inc. East Brunswick, New Jersey. July 1, 1980.
3. Lovell, R. J., S. W. Pylewski, and C. A. Peterson. Control of Sulfur
Emissions from Oil Shale Retorts. IT Enviroscience. Knoxville,
Tennessee. July 1980. p. II-8 - 11-32.
4. Bates, Edward R., and Terry L. Thoem (eds.). Environmental Perspective
on the Emerging Oil Shale Industry. Volume 1. U.S. Environmental
Protection Agency. Cincinnati, Ohio. Publication No. EPA-600/2-80-205a.
March 1980. p. 3-2.
5-22
-------
5. Rinaldi, Gerald M., Jean L. Delaney, and William H. Hendley.
Environmental Characterization of Geokinetics1 In Situ Oil Shale
Retorting Technology. U.S. Environmental Protection Agency. Cincinnati,
Ohio. June 1981.
6. Rinaldi, Gerald M. and Robert C. Thornau. Venturi Scrubbing for Control
of Particulate Emissions from Oil Shale Retorting. Monsanto Research
Corporation. Dayton, Ohio. 1980.
7. Fruchter, Jonathan S., Connie L. Wilkerson, John C. Evans, and Ronald W.
Sanders. Elemental Partitioning in an Aboveground Oil Shale Retort Pilot
Plant. Environmental Science and Technology. 14:1374-1381.
8. Rinaldi, Gerald M. Particulate Control and Emission Characterization at
a Pilot-Scale Oil Shale Retort. Monsanto Research Corporation. Dayton,
Ohio. March 1981.
9. Supplement No. 10 for Compilation of Air Pollution Emission Factors,
Third Edition (Including Supplements 1-7). U.S. Environmental Protection
Agency. Research Triangle Park, North Carolina. Publication No. AP-42.
February 1980. p. 8.20-1.
10. Reference 4, p. 3-3.
11. Reference 4, p. 3-4, 3-6, and 3-7.
12. Reference 4, p. 3-9.
13. Reference 4, p. 3-10 through 3-14.
14. Reference 4, p. 1-5.
15. Fruchter, J. S., J. C. Law, M. R. Peterson, P. W. Ryan, and M. E. Turner.
High Precision Trace Element and Organic Constituent Analysis of Oil
Shale and Solvent-Refined Coal Materials. (Presented at American
Chemical Society Symposium on Analytical Chemistry of Tar Sands and Oil
Shale. New Orleans. 1977.)
5-23
-------
16. Fox, J. P-, J. J. Duvall, K. K. Mason, R. D. Mclaughlin, T. C. Bartlee,
and R. E. Poulson. Mercury Emissions from Simulated In Situ Oil Shale
Retort. (Presented at DOE and School of Mines llth Oil Shale Symposium.
Golden, Colorado. 1978.)
17. Reference 3, p. 1-1.
18. Bates, E. R., and T. L. Thoem. Environmental Perspective on the Emerging
Oil Shale Industry. Volume 2. U.S. Environmental Protection Agency.
Cincinnati, Ohio. Publication No. EPA-600/2-80-205b. 1980. p.
A-13 - A-43.
5-24
-------
6. EMISSION CONTROL TECHNOLOGY
6.1 INTRODUCTION
Oil shale processing involves numerous activities with emissions of
environmental concern. To reduce emissions from an oil shale processing
facility, appropriate pollution controls must be applied to processing steps
at the potential emission source. The purpose of this chapter is to identify
potential sources of pollutants and to identify and compare available
pollution control techniques.
Based on the discussion in Section 4 of various oil shale processing
options, Table 6-1 is a list of potential emissions as a function of
processing activity. As shown, there are multiple sources of criteria
pollutants in oil shale processing. The total potential emissions of a given
pollutant are quite large because much raw shale is handled and processed to
produce a barrel of shale oil and because sulfur and nitrogen concentrations
in oil shale are relatively high compared to carbon concentration. While raw
shale may contain up to 3 percent sulfur, typical shale from the Green River
formation in Colorado, Utah, and Wyoming contains about 0.7 percent sulfur, of
which one-third is organic.*»2 During pyrolysis only a portion of the organic
sulfur undergoes reaction; about 40 percent is released as sulfur species,
primarily as hydrogen sulfide in shale oil gas. Thus, only about 12 percent
of sulfur in raw shale evolves as a potential gaseous pollutant; most remains
in shale oil and spent shale. This observation is also in agreement with data
from the Paraho semi-works retort.3
The potential sulfur oxide emissions from use of the retort gas is
estimated between 120 and 240 Mg/day (132 to 264 ton/day) for a 50,000 bbl/day
facility (see Subsection 5.3.3).
In recent years various oil shale process developers, the U.S.
Environmental Protection Agency (EPA), and the U.S. Department of Energy (DOE)
6-1
-------
TABLE 6-1. SOURCES AND NATURE OF POTENTIAL ATMOSPHERIC EMISSIONS
FROM OIL SHALE EXTRACTION AND PROCESSING
Process and
activity
Potential criteria3
pollutants
Potential noncriteria
pollutants
Blasting
Mine equipment (fuel use)
Preparation of retort
feed5
Retorting
Spent shale discharge0
Upgradingd
Sulfur removal, retort
off-gases
Product storage
Equipment leakage
pumps, valves, etc.
PM, CO, NOX, HC Hg, Pb salts, silica
PM, CO, NOX, S02, HC
PM Silica
PM, CO, NOX, S02, HC
PM, HC, CO, NOX, S02
PM, CO, NOX, S02, HC
PM, CO, NOX, S02, HC
HC
HC
Trace elements and
organics
H2SS NH3, volatile
compounds, trace metals
(Ni, CO, Fe, Mo)
CS2, COS
a PM = Particulate matter; HC = Hydrocarbons.
5 Primary and secondary crushing and transport of raw shale.
c Includes all activities through final disposal.
d Includes all activities after discharge of oil from retorts.
6-2
-------
have sought to characterize effluent streams from various in situ and surface
retorts. For several reasons, however, few of these data may be of use to
specify pollutant control devices:
Many data have been collected on process development retorts used to
collect process data and demonstrate technology. Retorting
processes have not operated at commercial-scale, and retort
performance has not been optimized with respect to maximizing oil
production or minimizing pollutant generation. In most cases, data
from in situ operations have been collected over only portions of
the burn. In addition, most tests have been for special purposes,
focusing on one or only a few of the gas stream components. Whole
process data have been obtained for retort technologies, but they
have in general been collected in isolation from gas stream tests.
Analytical problems are numerous, and analysis techniques are in
various stages of development. Problems include lack of appropriate
standards for analyzing retorting products and difficulties in
taking samples, in assuring samples represent the process, and in
evaluating and/or quantifying interference among gas stream
pollutants.
The composition of retort effluents depends largely upon operating
conditions and feed material composition. Because of wide
variation in oil shale composition, retorting processes, and retort
operations, samples taken for retorting operations and analyzed may
be representative only of that sample.^ Measurement and testing of
off-gases from in situ retorts must be made over the entire burn to
account for variations in elemental constituents within the deposit
and possible short-term retention of organics in the retort.
Very little work has been done on treating retort effluents with
control devices. Most small-scale, pilot-plant product gases are
flared without control. Rio Blanco has an installed flue gas
desulfurization unit at the C-a Tract site, but few measurements
other than for sulfur concentrations have been made on it.5
Uncertainties in the scale-up of retorting processes make selecting
control options difficult and tenuous at best. It has been shown that gases
6-3
-------
produced in direct-fired retorts are significantly different from gases
normally encountered in applications of desulfurization technology.6 High C02
levels and the high CC^/^S ratios in these gases make many desulfurization
technologies impractical. Since gases are produced in huge volumes at near
atmospheric pressures, many other desulfurization process may not be
economically applied. In addition, data for gas compositions are from
pilot-plant and bench-scale operations. When processes are scaled-up,
concentrations of gas components and trace elements may vary. However, as
noted repeatedly by the literature, a number of control processes are
available that have been commpercially proven in applications similar to
potential applications in oil shale processing.7»8>9,10,11,12
Criteria pollutants—particulate matter, sulfur dioxide, nitrogen oxides,
hydrocarbons, and carbon monoxide—will be of primary concern in oil shale
processing, but certain noncriteria pollutants may also be of interest.
However, paucity of hard data on characterization of emissions from oil shale
processing, for reasons described above, does not permit identification or
quantification of trace elements. Oil shale is generally retorted in surface
retorts at temperatures from 430° C (810° F) to 540° C (1,000° F). At these
temperatures, only elements with higher vapor pressure are volatilized, e.g.,
antimony, arsenic, boron, cadmium, lead, mercury, and selenium. These
elements are reported to be in shale oil retort water and off-gas.13 Another
study suggests that mercury and arsenic constitute potential emission
problems.14 Temperature control problems encountered during in situ
processing may result in excursions above 540° C (1,000° F), which could
result in volatilization of some of the lower vapor pressure trace elements
found in oil shale.
Subsequent subsections discuss sources of potential pollutants from oil
shale processing and applicable control techniques.
6.2 CONTROL APPROACHES
As noted above, the literature contains several excellent discussions of
pollutant control devices for oil shale processing. The material presented
below borrows heavily from the draft volume 1 of the Pollution Control
Guidance Document for Oil Shale.7 This material is supplemented with material
from other sources as indicated.
6-4
-------
6.2.1 Particulate Matter Control
6.2.1.1 Particulate Matter Sources. Sources of participate matter
emissions from oil shale operations are discussed in Chapter 5. Particulate
matter is produced during mining, processing, handling, and storage of raw and
spent shale. In addition, considerable quantities of fine particulate matter
are generated during retorting because of increased friability caused by
heating shale.
6.2.1.2 Particulate Matter Control Options. Options for particulate
control are shown in Figure 6-1. A description of each option and their
advantages and disadvantages are given in Table 6-2. Particulate emission
control at oil shale processing sites could include the following measures:9
For surface mining:
Prewatering and wetting for dust control.
Treating mining area with dust palliatives such as oil
emulsions, polymers, and soil stabilizers.
Restricting construction and mining vehicle activity.
For underground mining:
Application of water and wetting agents during drilling.
Muck pile of blasted shale wetted before and during rock
loading.
Conventional road wetting and chemical stabilization
techniques use for haulage roads.
For shale preparation:
Primary and secondary crushers enclosed with fabric filter
dust collector baghouse.
Primary and secondary crusher units equipped with water
sprays or dust collection systems followed by wet
scrubbers.
Fully enclosed belts and dust collection followed by
wet scrubbers at transfer points.
6-5
-------
PARTICULATE
REMOVAL
EQUIPMENT
MECHANICAL
(DRY)
COLLECTORS
FABRIC
FILTER
ELECTROSTATIC
PRECIPITATOR
CYCLONE
WET
COLLECTORS
VENTURI
SCRUBBER
ELECTROSTATIC
PRECIPITATOR
WET
SUPPRESSION
SPRAY
TOWER
CYCLONE
SCRUBBER
IMPINGEMENT-
PLATE SCRUBBER
Figure 6-1. Particulate removal options.
6-6
-------
TABLE 6-2. KEY FEATURES OF PARTICIPATE MATTER REMOVAL SYSTEMS APPLICABLE TO OIL SHALE PROCESSES7
cr>
i
Mechanical
(dry)
collectors
Fabric filter
Electrostatic
precipitator
Cyclone
Venturi
scrubber
Wet suppression
Removal3
efficiency
Operating principle (%)
The dust-laden gas passes through 99.7-99.9
woven fabric or felt material
which filters out the dust,
allowing the gas to pass on. The
filters can be cleaned by
mechanical shaking or by reverse
jet compressed air flow.
Particles suspended in a gas are 99-99.9
exposed to gas ions in an
electro-static field. These
particles then became charged and
migrate under the action of the
field to collector plates.
The dust- laden gas enters a 50-90
cylindrical or conical chamber
tangential ly at one or more points
and leaves through a central
openings. The dust particles,
because of their inertia, will
tend to move toward the outside
separator wall from which they are
led into a receiver.
Gas and liquid are passed 95-99
cocurrently through a Venturi
throat at 200 to 800 Ft. /sec.
Fugitive dust generated in the 95-99
crushing and handling of the oil
shale is sprayed with a foam
suppressant made from a water/ ~80')
surfactant mixture.
Temperature Pressure
limitations drop
(°F) (IN. HO) Advantages
500 5 High removal
efficiency
and low
operating
cost.
850 1 High removal
efficiency
and a very
low pressure
drop.
10,000 1-5 Low capital and
operating
cost. Very
good as a gas
precleaner
before a more
efficient
removal
device.
40-700 1-50 High removal
efficiency.
40-200 — Low capital and
operating
cost and a
high removal
efficiency.
Disadvantages
The fabric is
usual ly sensitive
to the gas
humidity,
velocity, and
temperature.
High relative energy
consumption.
Sensitivie to
varying conditions
and particle
properties.
Low removal
efficiency. Not
effective on
particle size
below 10.
High pressure drop
and, therefore,
high energy
requi rements.
Not applicable to
stack gases (used
for conveyor
transfer points.
and crushing and
grinding
operations).
' Based on performance in industries other than oil shale. fl
" Efficiency of water sprays without wetting agents is about 80 percent for particle diameter greater than 5u.°
(Continued)
-------
TABLE 6-2. KEY FEATURES OF PARTICIPATE MATTER REMOVAL SYSTEMS APPLICABLE TO OIL SHALE PROCESSES7 (Continued)
CO
Mechanical
(dry)
collectors
Impingement-
plate
scrubber
Removal Temperature
efficiency limitations
Operating principle (%) (°F)
A perforated tray with an 80-99 40-700
impinge-ment baffle above each
perforation. The high gas velocity
through the perforations atomizes
the liquid on the tray into
droplets which collect the dust by
impaction. This operating
principle is similar to that of a
venturi scrubber.
Pressure
drop
(IN. HO) Advantages
1-20 High removal
efficiency.
Disadvantages
High removal
efficiency
requires high
pressure drop and,
therefore, high
energy
requirements.
Cyclone
scrubber
Spray tower
Liquid is sprayed into a spinning gas 50-75 40-700
stream and removes dust by inertial
impaction.
Liquid droplets produced by spray 50-80 40-700
nozzles settle through rising gas
stream and remove dust by
impaction.
2 Low pressure
drop and low
operating
cost.
0.5 Low pressure
drop and low
operating
cost.
Low removal
efficiency.
Low removal
efficiency.
a Based on performance in industries other than oil shale.
b Efficiency of water sprays without wetting agents is about 80 percent for particle diameter greater than 5u.°
-------
Dust collected from baghouse slurries recycled to the
retort shale moisturizer.
Conveyor transfer points equipped with dust suppression
systems.
For shale retorting and refining:
Purified gas used to minimize particulate emission.
High energy venturi scrubber used to remove entrained
shale dust in flue gas and vapors from shale moisturizing
system.
Vent gas from feed hoppers and spent shale moisturizers
collected and scrubbed to remove dust.
For spent shale disposal:
Processed shale dumped, spread, and compacted in disposal
areas to form a stable disposal pile.
Processes shale kept at a moisture content of 11 to 19
percent by adding water to aid compaction and
stabilization.
Since particulate control techniques are physical rather than chemical,
no problems are foreseen in applying them in other areas of oil shale
processing.
6.2.2 Sulfur Emissions Control
6.2.2.1 Sources of Sulfur Emissions. The primary source of sulfur
emissions from shale processing sites, if uncontrolled, would be in the form
of sulfur dioxide. Sulfur dioxide is the principal sulfur specie produced by
the combustion of sulfur-containing compounds such as hydrogen sulfide,
carbonyl sulfide, carbon disulfide, mercaptains, and thiophene. These
compounds are produced in the reducing environment of the retort. Sulfur
species of higher molecular weight are also formed, but these tend to collect
in product oil. Thus, using product oil or retort gas to produce process
heat, steam, and power may create sulfur dioxide emissions. Because of their
potential effect on human health and welfare and on vegetation, sulfur dioxide
emissions are controlled by Federal and State regulations.
6-9
-------
6.2.2.2 Sulfur Emissions Control Options. Sulfur compounds in retort
off-gases are an air pollution problem when the gas is used in a combustion
unit to generate process heat, steam, or electricity or is flared to the
atmosphere. Two general options exist for controlling sulfur emissions under
these circumstances: stack gas sulfur removal (flue gas desulfurization)
after combustion and sulfur removal prior to combustion or flares. In the
first option, sulfur species contained primarily in the retort gas are
converted to sulfur dioxide by ordinary combustion of fuel gas. The resulting
flue gas is scrubbed to remove sulfur dioxide. Processes commonly used or
under development for flue gas desulfurization are outlined in Figure 6-2, and
a brief description of the characteristics of each is given in Table 6-3. The
second sulfur control option, where sulfur (primarily hydrogen sulfide)
compounds are removed from the retort gas prior to combustion, can potentially
be performed by several processes. These processes are outlined in Figure
6-3. A brief description of the characteristics of these systems and their
advantages and disadvantages are given in Table 6-4.
Transferring flue gas desulfurization technology to the developing oil
shale industry may present some difficulties. Because retort gas will be
combusted prior to flue gas desulfurization, only a few major compounds will
be present in these systems. These compounds should be qualitatively similar
to components contained in flue gas produced in coal-fired boilers. Some
adjustments may be needed in the processes to account for quantitative
differences in the two flue gases and might entail a testing effort on a
pilot-plant scale. However, Rio Blanco has used a sodium carbonate scrubber
at Tract C-a to scrub flue gas produced during the burn of Retort Zero.5
Transferring hydrogen sulfide removal technology to reduce sulfur
emissions from oil shale processing facilities may also present some
difficulties, especially if the retort gases contain significant amounts of
sulfur species other than hydrogen sulfide. One process, sulfiban, has been
demonstrated to remove both hydrogen sulfide and organic sulfur compounds in
coke oven by-product plants, but it has not been demonstrated in oil shale
facilities. Another potential problem area could be trace components in
retort gas; these components could disrupt the chemistry of the hydrogen
sulfide removal processes. For example, Union Oil Company has used the
6-10
-------
en
FLUE GAS
DESULFURIZATION
PROCESSES
(SO2 REMOVAL)
WET
SCRUBBING
REGENERABLE
PROCESSES
NONREGENERABLE
PROCESSES
WELLMAN-LORD
MAGNESIUM OXIDE
x- LIMESTONE
LIME
DOUBLE ALKALI
SODIUM CARBONATE
DOWA ALUMINUM SULFATE
SPENT SHALE
CHIYODA 121
DRY
SCRUBBING
NONREGENERABLE
PROCESSES
LIME
SODIUM CARBONATE
SPENT SHALE
Fioure 6-2. Flue qas desulfurization processes (SOo removal).
-------
TABLE 6-3. KEY FEATURES OF FLUE GAS DESULFURIZATION SYSTEMS
APPLICABLE TO OIL SHALE PROCESSES
01
I
ro
Wet scrubbing
process
Regenerable
Wellman-Lord
Magnesium oxide
Nonregenerable
Limestone
Lime
Process description
Absorbs SC>2 with a sodium sulfite/
bisulfite solution. A bleed
stream of the spend solution is
sent to evaporators where S02 and
water are driven off and the
solution is regenerated.
Absorbs SOj with a magnesiim oxide
slurry. A bleed stream of the
spent slurry is dried and
calcined to regenerate the
magnesium oxide and produce a
dilute S02 stream (10% S02).
Absorbs S02 with a limestone
slurry. A bleed stream of the
slurry is partially dewatered and
disposed of in a landfill.
Absorbs SO? with a lime slurry. A
bleed stream of the slurry is
partially dewatered and disposed
of in a landfill.
Product/
Haste
Concentrated
S02 stream
(up to 90%
S02 and 10%
1120) suit-
able for
sulfur or
sulfuric
acid manu-
facture.
Produces a
dilute S02
stream (10%
S02) which
is suitable
for produc-
tion of sul-
furic acid.
A slurry of
hydrated
calcium
sulfite/
sulfate
solids.
A slurry of
nydrated
- calcium sul-
fite/sulfate
solids.
Performance
Capable of
reducing the
outlet flue
gas S02 con-
centration
to 50 ppm.
Capable of
reducing the
outlet flue
gas SOo con-
centration
to 50 ppm.
Capable of
reducing the
outlet flue
gas S02 con-
centration
to 50 ppm.
Capable of
reducing the
outlet flue
gas S02 con-
centration
to 50 ppm.
Development
status
Seven commer-
cial unit
are in oper-
ation.
Three demon-
stration
plants have
been tested
(each about
100 MW
s i ze) . Two
commercial
units are
under con-
struction.
Many commer-
cial units
i n opera-
tion.
Many commer-
cial units
in opera-
tion.
Advantages
Produces a
concentrated
SOj stream
which can be
used to make
saleable sul-
fur or sul-
furic acid.
Produces an S02
stream suit-
able for
manufacture
of sulfuric
acid.
Low capital and
operating
cost. Simple
and proven
process with
conventional
process
equipment.
Very similar to
the limestone
process and
can poten-
tially give
greater SO?
removal effi-
ciency than
1 i rues tone.
Disadvantages
Requires fuel for
solution evap-
orators.
Requires fuel for
the MgS03/MgS04
dryer and
calciner.
Has a low opera-
bility factor
due to scalling,
erosion, and
corrosion.
Lime costs are
rising rapidly
because of
higher energy
costs.
(Continued)
-------
TABLE 6-3. KEY FEATURES OF FLUE GAS DESULFURIZATION SYSTEMS
APPLICABLE TO OIL SHALE PROCESSES (Continued)
CT>
I
Wet scrubbing
process
Nonregenerable
Double alkali
Sodium carbonate
Dowa aluminum
sulfate
Process description
Absorbs SO? with a 'dilute or
concentrated sodium sulfite
solution. The spent solution is
regenerated by lime addition.
The precipitated calcium sulfite/
sulfate solids are partially
dwatered and disposed of in a
landfill.
Absorbs S02 with a sodium carbonate
solution. A bleed stream of the
spent solution is partially
dewatered and disposed of in a
landfill.
Absorbs SO? with an acidic clear
solution of basic aluminum
sulfate. The spent solution is
forced oxidized to aluminum
sulfate. Limestone is added to
the solution to regenerate basic
aluminum sulfate and produce
gypsum which is partially
dewatered and disposed of in a
landfill.
Product/
Waste
A slurry of
hydrated
calcium
sulfite/
sulfate
solids.
Sodium
sulfite/
sulfate
sludge.
A gypsum
{hydrated
calcium
sulfate)
slurry.
Performance
Capable of
reducing the
outlet flue
gas 503 con-
centration
to 50 ppm.
Has been
demonstrated
to reduce
SO? concent-
ration to
below 50 ppm
on pilot
plant scale.
Capable of
reducing the
outlet flue
gas SO? con-
centration
to 50 ppm.
Capable of
reducing the
outlet flue
gas SO? con-
centration
to 50 ppm.
Development
status Advantages
Three comner- Low in capital
cial units and operating
in oepration. cost like the
1 imestone
system but
the use of a
clear scrub-
bing solution
reduces
scalling
erosion, and
corrosion in
the scrubbing
loop.
Four commer- Low capital
cial units cost. A very
in opera- simple and
tion. reliable
process.
Uses the same
basic process
design as the
double alkal i
process, and
therefore.
has the same
advantages;
the process
uses a clear
scrubbing
solution
which reduces
seal ing,
erosion, and
corrosion in
the scrubbing
loop.
Di sadvantages
Requires soda ash
(Na2COj) makeup
in addition to
1 ime for precip-
itation. Soda
ash is an
expensive raw
material. The
sludge contains
soluble and
leachable sodium
salts.
Soda ash is an
expensive raw
material. Pro-
duces a sludge
which is very
difficult to
dewater and
dispose of.
(Continued)
-------
TABLE 6-3. KEY FEATURES OF FLUE GAS DESULFURIZATION SYSTEMS
APPLICABLE TO OIL SHALE PROCESSES (Continued)
cr>
Wet scrubbing
process Process description
Nonregenerable
Snont ch:'; Absorbs S0;> with a spent shale
slurry. A bleed stream of the
slurry is partially dewatered and
disposed of in a landfill.
Chiyoda CT-121 The flue gas is first quenched to
its saturation temperature and
then sparged into a limestone
slurry generating a jet bubbling
froth layer. The SO? in the flue
gas is absorbed by trie limestone
slurry in the jet bubbling layer.
The calcium sulfite formed by
this reaction is oxidized to
calcium sulfate (gypsum) by the
introduction of air into the jet
bubbling layer. A bleed stream
of the waste slurry can be
dewatered and land-filled as a
recoverable resource or given
away to local cement, fertilizer,
or wall board industries.
Lime Flue gas is contacted with an
atomized lime slurry in a spray
dryer scrubber. The lime absorbs
the S02, is dried, and then
collected in a baghouse or
electrostatic precipitator (ESP).
Product/
Waste
Spent shale
sludge.
A gypsum
(hydrated
calcium
sulfate)
slurry.
Dry calcium
sulfite/
sulfate.
Performance
Probably
capable of
reducing the
outlet flue
gas S02
centration
to about 50
ppm.
Capable of
reducing the
outlet flue
gas SO? con-
centration
to 50 ppm.
Capable of
reducing the
outlet flue
gas S02
concentra-
tion to
between 100
to 150 ppm.
Development
status
The process is
only con-
ceptual at
this time
and has not
been tested
on a pilot
plant scale.
The process
has been
tested on a
demonstra-
tion size
scale.
The process
has been
tested on a
demonstra-
tion size
scale.
Three com-
mercial size
units are
currently
under
construc-
tion.
Advantages
Low capital and
oper^Ling
cost. Also,
an abundant
supply of
spent shale
is available
at the plant
site.
Absorbs S02 and
oxidizes cal-
cium sulfite
to gypsum in
one reator
vessel.
Since the flue
gas is not
saturated,
si ightly less
makeup water
is needed and
less stack
gas reheat is
needed.
Disadvantages
Has not yet been
tested even on a
pilot plant
scale.
Has only been
tested on a
demonstration
size scale.
This system is
usually only
economically
feasible where
low sulfur fuel
is burned
because of the
low reagent
utilization
rate. Very high
removal effi-
ciencies are
also not usually
possible because
of the low
reagent utiliza-
tion rate.
(Continued)
-------
TABLE 6-3. KEY FEATURES OF FLUE GAS DESULFURIZATION SYSTEMS
APPLICABLE TO OIL SHALE PROCESSES (Continued)
Wet scrubbing
process
Process
description
Product^
Waste
Performance
Developnent
status
Advantages
Disadvantages
Nonregenerable
Sodium
carbonate
Spent shale
cr>
*—•
e_n
Flue gas is contacted with an
atomized solution of aqueous
sodium carbonate 1n a spray dryer
scrubber. The sodium carbonate
absorbs the SO?, is dried, and
then collected in a baghouse or
electrostatic precipitator (ESP.)
Flue gas is contacted with an
atomized spent shale slurry in a
spray dryer scrubber. The
alkaline minerals in the spent
shale (primarily calcium
carbonate) absorbs the 502, is
dried, and theri collected in a
bagiiouse or electrostatic
precipitator (ESP).
Dry sodium
sulflte/
sulfate.
Dry spent
shale.
Capable of
reducing the
outlet flue
gas SO?
concentra-
tion to
between 75
to 100 ppm.
Probably
capable of
reducing the
outlet flue
gas SO? con-
centration
to between
100 to 150
ppn.
The process
has been
tested on a
demonstra-
tion size
scale.
The process is
only con-
ceptual at
this time
and has not
been tested
on a pilot
plant scale,
but the
Lurgi oil
shale
retorting
process lift
pipe and
flue gas
treating
equipment
closely re-
sembles this
system.
Same as for
1 ime dry
scrubbing
process.
Same as for the
1 line dry
scrubbing
process.
Also, an
abundant
supply of
spent shale
1s available
at ihe plant
site.
Same as for the
1 ime dry scrub-
bing process.
Al so, soda ash
is an expensive
raw material.
Same as for the
1 ime dry scrub-
biny process.
-------
CTl
H2S
REMOVAL
—
—
DIRECT
CONVERSION
INDIRECT
CONVERSION
(ACID GAS
REMOVAL)
GAS PHASE
PROCESS
LIQUID-
PHASE
PROCESS
DRY BED
PROCESS
LIQUID
PHASE
SOLVENTS
DRY BED
PROCESSES
STRETFORD
GIAMMARCO-VETROCOKE-SULFUR
TAKAHAX
FERROX
-
—
—
CHEMICAL
SOLVENTS
PHYSICAL
SOLVENTS
ADSORPTION
ON A SOLID
CHEMICAL
•
f SELEXOL
RECTISOL
PURISOL
ALKAZID
AMISOL
SULFINOL
FLUOR SOLVENT
MOLECULAR SLEEVE
CARBON BED
ALKANOL-
AMINES
ALKALINE
SALTS
AQUEOUS
AMMONIA
/•SULFIBAN
MEA
DEA
MDEA
\ ADIP/DIPA
DGA
SNPA-DEA
- ECONAMINE
{BENFIELD
CATCARB
ALKACID
{DIAMOX
CARL STILL
Figure 6-3. H2S removal process.
-------
TABLE 6-4. COMPARISON OF SULFUR REMOVAL SYSTEMS APPLICABLE TO OIL SHALE PROCESSES?
CTl
I
Control
technique Process
Direct CLAUS
conversion
Direct STRETFORD
conversion
Direct G1AMMARCO-
conversion VETROCOKE
Direct TAKAHAX
conversion
Process Components
principle removed
Partial oxidation of H2$ + other
H2S to SO? and sulfur
subsequent compounds.
reaction 2H;>S +
SO? - S + ZH^O in
gas phase.
H2$ absorption and H^S
liquid- phase
oxidation H^S + 0?
•» S + H^O in an
alkaline solution
of i vanadium
salt.
H£S absorption and H^S
1 iquid-phase oxi- COS
dation H?S + 02 » C$2
S + H;>0 in a solu-
tion of arsenic
salt.
H2$ absorption and H2$
liquid-phase oxi-
dation HjS +i02 »
S + H?0 in an
alkaline solution
of naphthoquinone
compounds.
Performance Selectivity
951 H2$ Side reactions
331 (others). with 003 and
1 ight hydro-
carbons
result in
stable sul
fur compounds
emitted from
the process.
< 100 ppm C02 absorbed 1n
the process
reduces sul-
fur removal
efficiency
causing sign-
ificant in-
creases in
absorber
height
require-
ments.
99.991 High selectiv-
ity for H2S.
99.991 High selectiv-
ity for H2S.
Commercial
availability
Continuously
improved
designs
available.
Process
currently
available for
disposal of
waste streams
from
Stretford
units.
Available for
desulfuriza-
tion of
coke-oven and
synthens
gases and
natural gas.
100+ units
operating in
Japan.
Advantages
-Provides
extremely
good quality
elemental
sulfur.
-Process
suitable for
desulfuriza-
tion of a
variety of
gas streams.
-Capable of
produci ng
purified gas
con taining
less than 1
ppm H2S even
at tenper
atures up to
300 F.
Capable of
producing
treated gas
containing no
detectable
H2S even at
high inlet
concentra-
tions.
Disadvantages
-Often not
adequate to
control
sulfur
compound air
pollution.
-HGN in feed
produces a
non-
regenerable
compound with
high
pol lution
potential.
-Hazardous
nature of
arsenic
solution.
Sulfur precip-
itation is of
very fine
grain and
amenable to
removal vi."
f loution
techniques.
(Continued)
-------
TABLE 6-4. COMPARISON OF SULFUR REMOVAL SYSTEMS APPLICABLE TO OIL SHALE PROCESSES7 (Continued)
CO
Control
technique Process
Direct FERROX
conversion
Direct HA1NES
conversion
Indirect
conversion SULFIBAN
Indirect MEA
conversion
Indirect MDEA
conversion
Process Components
principle removed
H2$ absorption and HjS
liquid-phase oxida-
tion H2S + 02 * S +
HjO in a solution
of NaC02 and FeOH.
Molecular sieves H2$
remove H2S and H20
water. H2S is
stripped from the
bed and reacted
with SO? to form
elemental.
Absorption into an H2S
alkanolamine RSH
solution.
H2S and C02 absorbed H2S
by a regenerable C02
reaction with
monoethanolamine
at ambient
temperatures.
Selective absorption
of H2S by a regen-
erable reaction
with Methyldie-
thanolamine.
Performance Selectivity
85-991 Good selectiv-
ity for H2$.
< 0.25 grains
H2S per 100 SCF
< lograins H2S Good for H2S
per 100 SCF RSH.
Preferred sol-
vent for gas
streams with
low concentra
tions of H2S
and C02 and
essentially
no minor
contaminants
(e.g.. COS,
CS2).
Commercial
availabi 1 ity
Few ferrox
plants are
still in
operat 1 on.
Pilot plants in
operation in
Canada.
Extended
operation of
ful l-scjle
plant unknown.
Demonstrated on
coke oven ay-
products
plants.
Used almost
exclusively
for years to
remove H2S
and C02 from
natural and
certain
synthesis
gases.
Advantages
Harked improve-
ments over
dry-box
purification
due to
reduced
instal lation
and labor
costs.
Removes both
H2S and RSH
reliably.
-MEA T Used pre-
dominantly in
the gas
sweetening
industry.
-C02 and CS2
form
products.
Di sadvantages
Sul fur from the
ferrox
process is
not suitable
for most uses
and chemical
replacement
costs are
high.
Zeol ite adsorp-
tion beds may
become fouled
impai ri ng
regenera-
tion.
-Non H2S selec-
tive (i.e.
COj also
absorbed).
-Reacts
i rreversi bly
with COS,
CS2.
(Continued)
-------
TABLE 6-4. COMPARISON OF SULFUR REMOVAL SYSTEMS APPLICABLE TO OIL SHALE PROCESSES? (Continued)
Control
technique Process
Indirect ADIP/DIPA
conversion
Indirect DGA/
conversion Economlne
Indirect ALKAZIO
conversion
Process Components
principle removed
Selective absorption HpS
of H?S by a regen- CO?
erable reaction
with Dilsopropy-
lami ne.
Absorption of H^S by H^S
a regenerable CO
reaction with
Diglycola-
Diglycolamine.
Process uses various H2S
proprietary COp
absorption
characteristics of
ammonia with total
(0.7 trtl NH3)
1 iquid recycle.
Performance Selectivity
Used commer-
cially as a
selective H2S
solvent for
Claus plant
tail gas
purifica-
tion.
< 0.25 grains
H2S/100 SCF
Capable of se-
lective
removal of
H2S when
correct
absorption
solution is
used.
Commercial
availability
Sour gas pro-
cessing in
its opera-
tion.
Although oper-
ated abroad
since the
1930's no
commercial
instal lations
are known in
the USA.
Advantages
-Substantial
amounts of
COS removed
without
detrimental
effects.
-Low regenera-
tion steam
requirements.
-DGA similar to
MEA with
lower vapor
pressure.
-Lower circula-
tion rates
and consump-
tion than
MEA.
-Solutions are
relatively
noncorrosive.
-Solution tai-
lored to re-
quirements
for H2S sel-
ectivity and
to minimize
effect of
contaminants.
Disadvantages
-DGA costs are
high.
-High corrosi-
vity.
-Losses due to
reaction with
C02, COS, CS2
are high.
-Reclaiming
requires
vacuum dis-
tillation.
(Continued)
-------
TABLE 6-4. COMPARISON OF SULFUR REMOVAL SYSTEMS APPLICABLE TO OIL SHALE PROCESSES? (Continued)
CTi
ro
o
Control
technique Process
Indirect DIAMOX
conversion
Indirect CARL STILL
conversion
Indirect SELEXOL
conversion
Indirect FLUOR
conversion SOLVENT
Process Components
principle removed
Selective H2S removal H2S
process using
absorption
characteristics of
ammonia with total
(0.7 wt; NH3) liquid
recycle.
Selective H2S removal Hj>S
process using
ammonia for
absorption (2.0 wtl
NH3> with total
liquid recycle.
Uses an anhydrous HpS
organic solvent CO?
dimethyl ether of RSH
polyethylene glycol COS
which physically
dissolves acid gases
and is stripped by
reducing pressure
without adding
heat.
Uses an anhydrous C02
organic solvent H2S
proprylene carbonate
which physically
dissolves acid
gases.
Commercial
Performance Selectivity availability
Can achieve 8 Selectively Recently
grains. removes H2S. developed and
H2S/100 SCF commercial-
ized in
Japan.
Can achieve 50 Selectively Commercial
grains. removes H2S. process now
H2S/100 SCF in operation
in USA.
< 1 ppm. H2S very Few plants in
soluble in operation for
selexol natural gas
solvent. treatment and
for synthesis
and coal-
derived gas
purifica-
tion.
Plants in
operation for
C02 only
gases and
combination
C02. H2S
gases.
Advantages
-Acid gas
produced is
suitable
Claus feed or
sulfuric acid
plant feed.
-Low pressure
process.
-Low pressure
process.
-Good Claus
plant feed.
-Non-toxic
solvent.
-Low operating
costs.
Di sadvantages
Purge stream of
ammonia
1 iquor
produced.
-H2S selectivity
less than
DIAMOX.
-Concentrated
NH3 solutions
highly
corrosive.
-Requires high
partial
pressure of
acid gas.
-Solvent intend-
ed primarily
for removal
of C02.
(Continued)
-------
TABLE 6-4. COMPARISON OF SULFUR REMOVAL SYSTEMS APPLICABLE TO OIL SHALE PROCESSES7 (Continued)
en
ro
Control
technique Process
Indirect MOLECULAR
conversion SIEVE
Indirect CARBON BED
conversion
Indirect KATASULF
conversion
Process
principle
Use of molecular
sieves to adsorb
sulfur compounds.
Activated carbon
beds used to
catalytically
oxidizes H2S to
elemental sulfur
at airSient
temperatures.
Sulfur removed by
solvent washing.
Air and preheated
gas w/h2S catalyzed
to fore S02, which
is absorbed in an
aqueous ammonium
sulfite-bisulf ite
solution.
Components
removed
H20
C62
H,S
s62
NH2
COS, RSH
H2S
H2S
NH3
Performance
Very effective.
Concentrations
greater than
approximately
400 grains
per 100 SCF
difficult to
treat satis-
factory
without
recycling
purified gas
or by cooling
the bed.
< 4 ppm H2S
Commercial
Selectivity availability
-Not widely used
for removing
H2S from gas
streams.
Not appl led on
a large
commercial
scale.
Large commer-
cial units in
operation.
Advantages
-Extended useful
life (3-5
years) of
adsorbent
possible with
properly
designed
molecular
sieve.
-Very pure
sulfur
obtained.
-Complete H;>S
removal.
-Produces a
saleable
ammoni urn
sulfate.
Disadvantages
-Preferably used
on high
pressure
streams.
-Regeneration
gas disposal.
-Carbon deacti-
vated
rapidly.
-Purification
required to
remove tar
and ammonia.
-Compl icated
sulfur
extration
procedure.
-1500 ppm/H2S
limit in
feed.
Carbon-steel
corrosion
problems
exist with
some forms of
the process.
-------
TABLE 6-4. COMPARISON OF SULFUR REMOVAL SYSTEMS APPLICABLE TO OIL SHALE PROCESSES7 (Continued)
i
ro
ro
Control
technique Process
Indirect PUR I SOL
conversion
Indirect SULFINOL
conversion
Indirect AMISOL
conversion
Indirect RECTISOL
conversion
Process
principle
Uses an anhydrous
organic solvent
N-methyl-2-
pyrolidine which
physically
dissolves acid
gases.
Uses a mixture of
chemical (DIPA)
and physical
solvent
(sulfolane) and
water.
Uses a mixture of a
chemical (MEA/DEA)
and a physical
solvent
(Methanol).
Uses physical
absorbtion in
methanol at low
temperature.
Components
removed
H2S
C02
RSH
COS
H2S
COS
RSH
C02
All sulfurs
C02
H,S
c&2
COS, CS2
RSH
HCN
HC'S
Commercial
Performance Selectivity availability
< 3 ppm H2S Exceptionally Four commercial
high solubil- installations
ity. in operation
as of 1979.
96-99% Wide applica-
tion in the
treatment of
natural , re-
finery, and
synthesis
gases.
< 0.1 ppm Only semi-
< 5 ppm commercial
plants in
operation.
No detectable Considerably Large indus-
H2S possible. higher solu- trial plant in
bility of H2S operation.
over CO?.
Advantages
Highly H2S
selective.
-Removes COS,
RSH.
-Capacity is
high at
partial
pressure of
H2S.
-Capable of
removing all
sulfur.
-Heat input low
because temp-
erature main-
tained by
flashing.
-Removes al 1
undesirable
components in
single step.
Disadvantages
-Optimum opera-
tion under
high
pressure.
-Solution
absorbs heavy
HC's
requiring
flash tank
separation.
-Complex
operation.
-High solvent
losses.
-Best suited
for higher
pressures.
-Low temperature
process.
(Continued)
-------
treating the off-gas from a laboratory-sized retort8 and has found sulfur
produced by the processes to be contaminated by charred hydrocarbons, which
lower the resale value of the recovered sulfur. Union also expressed an
interest in the chemistry of the Stretford solution, indicating that they were
not entirely satisfied with the performance of the standard materials.
6.2.3 Nitrogen Oxide Emissions Control
6.2.3.1 Nitrogen Oxide Sources. Oxides of nitrogen (NOX) are a natural
product of the combustion of conventional fuels and may be a significant air
pollution emission from oil shale processing. The major source of potential
NOX emissions during oil shale processing will be from the combustion of
nitrogen-containing fuels, in which high yields of nitrogen to NOX will be
achieved, or from fixation of molecular nitrogen from combustion air in
high-temperature combustion processes. NOX emissions contribute to secondary
chemical reactions in the atmosphere, resulting in formation of photochemical
oxidants, and are in themselves undesirable from a physiological point of
view.8 Conditions in or near the flame in industrial combustion units are
such that the nitrogen in the combustion air is converted to NOX. In
addition, oxidation of chemically bound nitrogen in shale oil off-gases, e.g.,
NH3, also results in NOX formation.
6.2.3.2 Control Options for NOY Control. Nitrogen compounds in retort
off-gas do not in themselves present an air pollution problem. However,
problems do arise with these gases when used in a combustion unit to generate
process heat, steam, or electricity or when flared to the atmosphere. As
shown in Figure 6-4, the options available for reducing the potential NOX
emissions from an oil shale retorting facility are combustion modification,
fuel-nitrogen removal, and stack gas removal of NOX. Table 6-5 describes
characteristics, advantages, and disadvantages of NOX control options
applicable to oil shale processing.
Because the oil shale industry is still in the pilot-plant phase, it is
still in a position to design furnaces with low NOX emissions into their
commercial-scale units.8 This may be more cost effective than retrofit
control devices. Combustion system modifications may not by themselves meet
the required control of NOX emissions, in which case appropriate retrofit
control systems could be added to the shale retorting, facility to meet
emission requirements.
6-23
-------
REDUCED FUEL-
BASED NITROGEN
FUEL-NITROGEN
REMOVAL
COMBUSTION
MODIFICATIONS
OFF-
STOICHIOMETRIC
COMBUSTION
STAGED
COMBUSTION
REDUCED
EXCESS O2
STACK GAS
REMOVAL
OFNOX
DRY
ABSORPTION
ON A SOLID
CATALYTIC
REDUCTION
TONO2
SELECTIVE
WITH NH3
REDUCTION TO
N, WI.TH NH,
NONSELECTIVE
WITH
REDUCING GAS
Figure 6-4. Technologies for the reduction of NOX in stack gas emissions.
6-24
-------
I
ro
en
TABLE 6-5. COMPARISON OF NOX CONTROL SYSTEMS APPLICABLE TO OIL SHALE PROCESSES
Control
method
Fuel
nitrogen
removal
Combustion
modifica-
tions
Stack gas
removal
of NOX
Stack gas
removal
of NOx
Process
NH3 Scrubbing
Two-Stage
Combustion
(either
low-
emission
burners or
engineered
cor^bustion
box).
Low-Excess
Air
Selective
Catalytic
Reduction
(SCR)
Thermal
OeNOx
Process description
Absorption of NH3 by
counter-current scrubbing
with water.
Air is introduced in two
zones. Zone 1)
combustion occurs under
reducing conditions. Zone
2) additional air added
to complete combustion.
Reduce excess air available
to reduce reaction
Kinetics of N-radial 1 0?
reaction.
NOx reduced by NH3 over a
catalyst (all processes
similar using various
proprietary catalysts).
NY? injected in a 1300-1800
F flame zone where NO +
NH3 * N? + H;>0.
Performance
Up to 1001 of NHj
removal possible by
changing water;
rate, composition.
and temperature.
40-601 of thermal
NOx reduction.
Less reduction for
fuel-nitrogen.
10-201 NOx reduction.
901 NOX removal.
701 NOX removal.
Development
status
Commercially proven.
Burners and boiler
designs commercially
avai lable.
4 processes in
commercial scale
operation.
20 processes
available.
Demonstrated
commercially.
Advantages
Removes source of NOx
before formed.
Byproduct NH3 produced
Burner system
inexpensive in
relation to total
cost.
Require only
operational changes.
-Commercially
demonstrated.
-NO byproduct recovery
required.
-Low capital cost.
Oi sadvantages
-Does not reduce NOx
emissions formed by
thermal fixation of
oxygen in combustion
air.
-Reducing zone can
cause boiler tube
damage.
-Boiler more difficult
to operate, possible
increase 1n CO/HC
emissions.
Particulates and SO^
can cause catalyst
plugging and
poisoning.
-Requires large amounts
of NH3-
-Narrow operating
range.
-------
In addition, due to the high conversion rate for ammonia to NOX, NH3
removal before combustion may be a reasonable control option. The volume of
fuel requiring treatment at this stage is much smaller than the eventual
volume of flue gas. Also, process equipment used for cooling and NH3
absorption should produce a light oil product. The value of this product may
be sufficient to offset much of the cost of the NH3 removal facilities.
6.2.4 Hydrocarbon and Carbon Monoxide Emissions Control
6.2.4.1 Sources of Hydrocarbon and Carbon Monoxide Emissions.
Hydrocarbons may be emitted to the atmosphere at oil shale processing
facilities as a result of incomplete retort gas combustion or as fugitive
emissions from leaks in processing facilities or oil storage equipment.
Carbon monoxide is usually formed by incomplete combustion of fuels. Normally
excess oxygen is supplied to a combustion process to ensure that all of fuel
carbon is converted to carbon dioxide. When an oxygen shortage occurs in the
combustion process, some carbon is only partially oxidized to carbon
monoxide.
6.2.4.2 Control Options for Hydrocarbon and Carbon Monoxide Emissions.
Alternatives controlling potential hydrocarbon and carbon monoxide emissions
from oil shale processing facilities are shown in Figures 6-5 and 6-6,
respectively. Tables 6-6 and 6-7 show advantages and disadvantages of
hydrocarbon and carbon monoxide control options aplplicable to oil shale
processes.
Perhaps the easiest method to control carbon monoxide and hydrocarbon
emissions is complete fuel combustion by assuring the presence of sufficient
oxygen during combustion, converting pollutants to carbon dioxide and water..
Due to mine safety regulations, catalytic converters are required for all
diesel equipment used in mining operations.
Vapor recovery processes for hydrocarbon emission controls could be used
in situations where recovered hydrocarbons have high market value and where
hydrocarbon concentration is high enough to make its recovery economically
feasible.
Fugitive hydrocarbon emissions have two principal sources: leaks and
evaporation from open surfaces. Unlike fugitive dust, which arises in a
diffuse pattern over an area, many fugitive hydrocarbon losses occur from
6-26
-------
HYDROCARBON
CONTROL
TECHNOLOGIES
ADDITIONAL SEALING
ON PROCESS
EQUIPMENT
COMPLETE FUEL
COMBUSTION
CATALYTIC
CONVERTERS
THERMAL
OXIDIZERS
Figure 6-5. Hydrocarbon control technologies.
6-27
-------
CARBON MONOXIDE
CONTROL
TECHNOLOGIES
COMPLETE FUEL
COMBUSTION
CATALYTIC
CONVERTERS
THERMAL OXIDIZERS
Figure 6-6. Carbon monoxide control technologies.
6-23
-------
C71
I
ro
uo
TABLE 6-6. KEY FEATURES OF HYDROCARBON CONTROL SYSTEMS APPLICABLE TO OIL SHALE PROCESSES7
Hydrocarbon
control
techniques
Additional
sealing
on
process
equip-
ment
Complete
fuel
combus-
tion
Operating principle
Includes double seals on pumps and other
rotating machinery, closed loop sampling,
caps on open ended valves, and periodic
monitoring of equipment to find
hydrocarbon leaks quickly.
Combustion process is operated with excess
air to insure complete oxidation of all
hydrocarbons to CO? and H?0.
Performance
About 6M-65J
reduc-tion of
fugitive hydrocarbon
emissions is
possible with this
level of control.
Can convert close to
1001 of all hydro-
carbons in the fuel
to CO? and H?0.
Advantages
Requires a small capital and operating cost
and will probably more than pay for this
cost due to the value of the hydrocarbons
which are prevented from being emitted.
Eliminates the need for downstream
equipment to complete the conversion of CO
to CO?.
Disadvantages
Should be implemented
during new plant con-
struction. Requires
more capital investment
to retrofit the controls
of an existing plant.
Can increase NO^ for
motion.
Catalytic Hot exhaust gas is passed over a catalyst
convert- where the unburned hydrocarbons are
ers reacted with the excess air in the
exhaust gas and are converted to CO? and
H?0.
Thermal Waste gas streams containing unburned
oxidiz- hydrocarbons are burned with excess air
ers and additional fuel if needed to
completely oxidize all hydrocarbons to
CO? and H?0.
Can convert up to 80%
of the hydrocarbons
in diesel exhaust
gas streams to CO?
and H?0, for other
fuel burning
processes up to 99%
conversion is
possible.
Can convert close to
1001 of all hydro-
carbons in the gas
stream to CO? and
H?0.
Does not require any fuel and has no moving
parts so that routine maintenance is
minimal.
The catalyst, which is
expensive, must be
replaced periodically.
Will insure complete oxidation of hydro-
carbons.
Can have a high energy
requirement when sup-
plemental fuel is used.
-------
TABLE 6-7. KEY FEATURES OF CARBON MONOXIDE CONTROL SYSTEMS APPLICABLE TO OIL SHALE PROCESSES7
Hydrocarbon
control
techniques
Compl ete
fuel
combus-
tion
Catalytic
convert-
ers
Operating principle
Combustion process is operated with excess
air to insure complete oxidation of all
hydrocarbons to CO? and H?0.
Hot exhaust gas is passec over a catalyst
where the unburned hydrocarbons are
reacted with the excess air in the
exhaust gas and are converted to CO? and
H20.
Performance
Can convert close to
100% of all hydro-
carbons in the fuel
to CO? and H?0.
Can convert up to 801
of the hydrocarbons
in diesel exhaust
gas streams to CO?
and H?0, for other
fuel Burning
processes up to 99J
conversion is
possible.
Advantages
Eliminates the need for downstream
equipment to complete the conversion of CO
to CO?.
Does not require any fuel and has no moving
parts so that routine maintenance is
minimal.
Disadvantages
Can increase NOx for
motion.
The catalyst, which is
expensive, must be
replaced periodically.
Thermal Waste gas streams containing unburned
oxidiz- hydrocarbons are burned with excess air
ers and additional fuel if needed to
completely oxidize all hydrocarbons to
CO? and H?0.
Can convert close to
100J of all hydro-
carbons in the gas
stream to CO? and
H?0.
Will insure complete oxidation of hydro-
carbons.
Can have a high energy
requirement when sup-
plemental fuel is used.
-------
specific points, such as valves, flanges, drains, pump seals, compressor
seals, and drains. Figitive emission controls are primarily based on good
plant design and maintenance procedures rather than on equipment. Plant
design items to help reduce fugitive emissions include the following:
Confinement, diversion, and flaring
Dual seals on pumps and other moving equipment
Sparing of critical pumps, compressors, and valves
Use of double-sealed floating roof storage tanks.
Probably the most important item in preventing fugitive emissions is good
preventative maintenance, which includes using outages and normal downtimes
for repairs and testing potential fugitive emission sources on a systematic
basis.8
6.3 AVAILABLE CONTROL OPTIONS FOR EMISSION REDUCTION
Presently there are no commercial-scale oil shale processing facilities
on stream, although a number of facilities are planned or just beginning
commercial development of processing sites. The processes being developed
have not been fully characterized as to type and quantities of pollutants
likely generated by commercial operations that optimize shale production and
environmental tradeoffs.
Present strategies for controlling potential pollutant emissions are in
the conceptual stage. However, there are a number of efficient control
technologies available that could find application. In fact, high removal
levels are possible for criteria pollutants. Details of these processes are
given in Subsection 6.2.
Although controlling potential pollutant emissions from oil shale
processing facilities may be feasible with present control technology, answers
must be supplied to questions that have not been raised nor anticipated at
present. Also, as pointed out in Section 6.2, interactions among the control
techniques used at a single site may be beneficial or detrimental to the
overall process. The design of control options must take into account these
complexities, as well as the specifics of the retorting process, use of
natural resources, and economics.
6-31
-------
6.4 REFERENCES
1. Poulson, R. E., 0. W. Smith, N. B. Young, W. A. Robb, and T. J. Spedding.
Minor Elements in Oil Shale and Oil Shale Products. LERC, RI 77-1,
1977.
2. Stanfreed, K. E., et al. Properties of Colorado Oil Shale. U.S.
Bureau of Mines. Report of Investigation 4825. 1951.
3. Fruchter, J. S., C. L. Wilkerson, J. C. Evans, and R. W. Sanders.
Analysis of Paraho Oil Shale Produce and Effluents: An Example of the
Multi-technique Approach. In: Proceedings of the EPA Oil Shale
Sampling, Analysis, and Quality Assurance Symposium. Denver, Colorado.
March 1979.
4. Heistand, R. N., L. Morris, and R. A. Atwood. Quality Assurance in
Sampling and Analysis of Oil Shale Retorting Operations. In:
Proceedings of the EPA Oil Shale Sampling, Analysis and Quality Assurance
Symposium. Denver, Colorado. March 1979.
5. Trip Report. Rio Blanco Oil Shale Co. January 28, 1981.
6. Lovell, R. J., S. W. Pylewski, and C. A. Peterson. Control of Sulfur
Emissions from Oil Shale Retorts. IT Enviroscience. Knoxville,
Tennessee. July 1980. p. II-8 - 11-32.
7. Pollution Control Guidance Document for Oil Shale: Volume I. Prepared
for the U.S. Environmental Protection Agency by Denver Research
Institute, under Cooperative Agreement No. CR 807294010. February 1981.
8. Bates, E. R., and R. L. Thoem (eds). Pollution Control Guidance for Oil
Shale Development. Draft report compiled for the U.S. Environmental
Protection Agency by Jacobs Environmental. July 1979.
9. Nowacki, P. Health Hazards and Pollution Control in Synthetic Liquid
Fuel Conversion. Noyes Data Corporation. Park Ridge, New Jersey. 1980.
10. Pollution Control Guidance Document for Low-Btu Coal Gasification. Draft
report prepared for the U.S. Environmental Protection Agency by TRW,
Inc. 1981.
6-32
-------
11. Modern Pollution Control Technology. Volume I: Air Pollution Control.
Research and Education Association. New York. 1978.
12. Witmer, F. E. Environmental Control Options for Synfuel Processes. In
Fifth Symposium on Environmental Aspects of Fuel Conversion Technology,
St. Louis, Missouri. September 1980.
13. Shendrikar, A. D., and J. B. Faudel. Distribution of Trace Metals
During Oil Shale Retorting. Environmental Science and Technology.
12:332. 1978.
14. TRW, Inc. Trace Elements Associated with Oil Shale and Its Processing.
U.S. Environmental Protection Agency. Cincinnati, Ohio. 1977.
6-33
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1 REPORT NO.
EPA 450/3-81-010
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Phase I Source Category Survey Report for the Oil
Shale Industry
5. REPORT DATE
August 1981
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S1
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
10. PROGRAM ELEMENT NO.
Office of Air Quality Planning and Standards
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
11. CONTRACT/GRANT NO.
12. SPONSORING AGENCY NAME AND ADDRESS
13. TYPE OF REPORT AND PERIOD COVERED
DAA for Air Quality Planning and Standards
Office of Air, Noise, and Radiation
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
This document contains information used as the basis for deciding if New Source
Performance Standards or National Emissions Standards for Hazardous Air Pollutants are
necessary for the oil sha^e industry. This document includes-an industry description,
an analysis of potential emissions, and a compilation of potential emission control
techniques.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATl Meld/Group
Air Pollution
Pollution Control
Oil Shale
Sulfur Oxides
Nitrogen Oxides
Particulates
Trace Metals
Air Pollution Control
'.8. D'STRIBUT.QN STATEMEN1
Unlimited
EPA
19. SECURITY CLASS iTIns Report/
Unclassified
21. NO. OF PAGES
110
20. SECURITY CLASS (This pagei
Unclassified
22. PRICE
• "JS EDITION IS OBSOLETE
------- |