United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
Research and Development
EPA-600/S7-82-016 August 1982
Project Summary
Control of Sulfur
Emissions from Oil
Shale Retorts
R. J. Lovell, S. W. Dylewski, and C. A. Peterson
The objectives of this study were to
determine the most applicable tech-
nology for control of sulfur emissions
from oil shale processing facilities and
then to develop a design for a mobile
slipstream pilot plant that could be
used to test and demonstrate that
technology.
The work conducted included an in-
depth evaluation of available gas
characterization data from all major oil
shale development operations in the
United States. Data gaps and incon-
sistencies were identified and corrected
where possible through working with
the developers or researchers in the
field. From the gas characterization
data, duty requirements were defined
for the sulfur removal systems. Based
on this information, Stretford gas
sweeting technology was recom-
mended, and the design of a 1OOO
CFM pilot plant was completed.
This Project Summary was devel-
oped by EPA's Industrial Environ-
mental Research Laboratory. Cincin-
nati, OH. to announce key findings of
the research project that is fully
documented in a separate report of the
same title (see Project Report ordering
information at back).
Introduction
The future beneficial use of the
nation's extensive oilshale resources
depends not only on the development of
suitable process economics but also on
the development of suitable environ-
mental controls. Even though the sulfur
content of the oil that would be
produced is comparatively low, sulfur
emissions from large-scale production
of shale oil could be enormous. Oilshale
contains up to 2% sulfur. A typical shale
in the Green River Formation in Colorado
contains about 0.7% sulfur. When the
shale is retorted, somewhere between
16 and 30% of the sulfur is liberated to
the gas stream, and the majority
remains with the spent shale. The
emissions from a 400,000-barrel/day
oilshale industry could be as high as
760 to 1400 tons per day if controls
were not applied. If conventional flue-
gas scrubbing systems were used to
control the emissions (the average
reduction is about 90%), the controlled
emissions would be 76 to 140 tons/day.
However, if the sulfur could be removed
before the gas is burned (the average
reduction here is about 98%), the con-
trolled emissions would be in the order
of 15 to 28 tons/day.
The viability of the oilshale industry
hinges on a sulfur-removal process
compatible with environmental con-
cerns. Although there are no federal
standards for emissions for the oilshale
industry at this time, the State of
Colorado has enacted legislation that
limits emissions to less than 0.3 Ib of
sulfur dioxide per barrel of oil produced
and an equal amount per barrel of oil
refined. To meet this standard, at least
95% of the sulfur in the. gas would have
to be removed.
The area of air pollution compliance
that is of the greatest concern to
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industry and government is the Preven-
tion of Significant Deterioration (PSD)
requirements of the Federal Clean Air
Act. This concept was enacted to
prevent the addition of specified pollut-
ants above a prescribed baseline value
in specified air regions. Colorado
adopted a more stringent plan which
limits the maximum level of sulfur
dioxide in the airto an annual average of
10/ug/m3. Thus the maximum quantity
of shale oil that can be produced will be
limited by the effectiveness of the sulfur
emission control system used.
Gases produced by direct-fired retorts,
either above ground or in-situ, are
different enough from gases normally
encountered in application of desulfur-
ization technology that the technology
cannot just be transferred. Gases from
direct-fired retorts contain large amounts
of inert components and have a high
ratio of carbon dioxide (CO2) to hydrogen
sulfide (H2S); they also contain large
amounts of ammonia and unsaturated
hydrocarbons such as acetylene, eth-
ylene, propylene, butylene, and buta-
diene. The gases are saturated with
water and contain some oxygen and
trace amounts of sulfur species other
than H2S.
The large amounts of C02 in the gases
and the high C02 to H2S ratios make it
impractical to employ many of the
desulfurization technologies. Since the
gases are produced in huge volumes at
near-atmospheric pressures, many
other desulfurization processes cannot
be economically applied. The applicable
processes may perform only marginally
because C02 is present in large quanti-
ties. Oxygen and unsaturated hydrocar-
bons may be present in the gases, or the
gas may contain a large quantity of
organic sulfur.
Oilshale developers are involved in
many significant pilot-scale activities to
devise retorting process technology.
They have indicated their willingness to
cooperate with the U.S. Environmental
Protection Agency (EPA) on projects for
sulfur control technology evaluation. To
capitalize on this opportunity and to
explore the possibility that sulfur
emission control will be more of a
problem than was originally thought,
EPA contracted with IT Enviroscience,
Inc., to investigate the various commer-
cial sulfur-removal technologies and to
propose a pilot-plant design based on
the most cost-effective process for
removing gaseous sulfur compounds
from oilshale retort gases.
The objectives of this study were to
determine the most applicable control
2
technology for control of sulfur emis-
sions from oil shale processing facilities
and then to develop a design for mobile
slip-stream pilot plant that could be
used to test and demonstrate that
technology.
Approach
The work included an in-depth evalu-
ation of available gas characterization
data from all major oilshale develop-
ment operations in the United States.
Data gaps and inconsistencies were
identified and corrected where possible
through working with the developers or
researchers in the field. From the gas
characterization data, duty requirements
were defined for the sulfur removal
systems. It was found that oilshale
retorting processes fall into two broad
categories; direct-fired-retort process
and indirect-heated-retort processes,
each category having distinct duty
requirements.
The overriding factor separating the
two categories of retorting processes
and determining which desulfurization
technology to apply is the C02 to H2S
ratio of the gas produced from the retort.
Those from direct-fired retorts have C02
to H2S ratios ranging from 76 to over
165, thus requiring that the process
selectively remove H2S in the presence
of large amounts of C02. Indirect-
heated retorts produce gases with
C02to H2S ratios in the range of 4.3 to 5,
which would allow a nonselective
process to be used.
During this study, it was determined
that the greatest immediate concern is
control of sulfur emissions from direct-
fired oilshale retorting processes and
that the pilot-plant design should be
applicable to these retorting methods.
Since application of desulfurization
technology to gases from direct-fired-
retorting processes is more limiting, the
screening of available process technol-
ogies was based on the duty require-
ments for those gases.
Recommended Available H2S
Control Technology
The class of processes that remove
H2S and CO2 from fuel gases is gener-
ically called acid-gas removal or gas-
sweeting. Acid gas or other gaseous
impurities are removed from gas streams
either by direct chemical conversion to a
compound more easily separated from
the gas stream, by absorption into
liquid, or by adsorption onto a solid.
Because large volumes of gas must be
processed in a typical oilshale plant,
desulfurization technology will be
applied only to high-capacity, liquid-
phase processes. Since CO2 is absorbed
to some extent by all liquid-phase
processes, the high C02 to H2S ratio of
the gas limits the choice to those
processes that selectively absorb sulfur
compounds in the presence of large
amounts of C02.
Of the processes that remove H2S by
directly converting it to elemental
sulfur, the Stretford process is the most
effective. Of the indirect processes that
remove H2S by separating it as a
concentrated acid-gas stream, the
following processes were most effective:
The Selectamine and the Adip processes,
which use MDEA as the absorbent, the
Benfield, the Selexol, and the Diamox
processes. The Benfield and Selexol
processes require the gas to be at high
pressure and thus were eliminated,
since the compression of the gas for
desulfurization cannot be economically
justified.
Except for the Diamox process, all the
candidate processes can remove H2S
down to about 10 ppmv. However,
organic sulfur compounds, principally
COS, which exist in only trace amounts
in the gas, are not significantly removed
by the various processes. The presence
of those compounds may reduce the
overall effectiveness to 98%.
The Stretford process is most cost-
effective for desulfurization gases
from direct-fired oilshale retorts. In the
model case used to evaluate the
processes the total estimated cost of
sulfur removed by the Stretford process
is about $0.50 per barrel of oil produced,
less than half that projected for the best
of the other processes evaluated.
The Claus process recovers sulfur
from the acid gas produced by indirect
sulfur-removal. Because of the large
quantity of CO2 in the gas, the- best
indirect processes can only marginally
produce an acid gas rich enough in H2S
for the Claus process. Thus, to apply the
Claus process, multiple stages of
selective absorption would be required
to handle the gas produced by many of
the direct-fired retorts.
The Stretford direct process, on the
other hand, is only minimally affected by
the quantity of C02 in the gas and
therefore is adaptable to the full range
of gases produced by direct-fired
retorts.
Design of Pilot Plant
The pilot-plant design is based on the
current state-of-the-art technology for
commercial application of the Stretford
process. The maximum design capacity
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of the unit is 1000 scf m of feed gas and
14.6 Ib of sulfur per hour. The plant
should be capable of reducing the H2S
content of the gas to 10 ppmv or less,
and CO2 to H2S ratios as high as 200:1
should be possible.
The pilot plant is sized primarily to
remove H2S from oilshale gas produced
by direct-fired retorts. However, use of
an ejector-venturi gas-scrubbing system
affords wide gas turndown capability for
the system. The pilot plant can thereby
operate on a slip stream from any of the
currently proposed direct or indirect oil
shale retorting processes in the United
States.
To function properly, the feed gas to
the pilot plant must be 120°F or less,
with most of the ammonia removed. A
gas cooling column has been incorpor-
ated into the pilot design for cooling and
removing the ammonia from the feed
gas.
The estimated cost of the pilot plant
with all equipment, instruments, and
controls, assembled on skid mountings
as a complete and operable unit, is as
follows:
Range
With Cooler Without Cooler
High
Average
Low
$520,000
400,000
308,000
$338,000
260,000
200,000
Conclusions
The Stretford direct gas desulfurization
process may be the only currently
available commercial process capable
of effectively removing H2S from gases
produced by direct-fired retorts. Appli-
cation of the Stretford process to the
treatment of these gases would extend
the technology of the Stretford process
into areas in which no experience is
available. Many questions need to be
answered before the process can be
applied with confidence to a full-scale
commercial shaleoil production facility.
The principal areas of concern for
Stretford technology are as follows:
1. absorption of C02 versus gas
characteristics,
2. capacity of the solution for absorb-
ing sulfur versus gas characteris-
tics,
3. rate of by-product thiosulfate
formation versus gas characteris-
tics,
4. disposition of COS and other
organic sulfur compounds in the
feed gas, and
5. effects of unsaturated hydrocar-
bons in the feed gas on process
operation, life of the Stretford
chemicals, and quality of the
sulfur produced.
Unless the Stretford process can be
demonstrated as an effective and
reliable process for treatment of direct-
fired oilshale gases, industry may have
to resort to combusting the gas first and
then using less effective flue-gas
desulfurization techniques. Because of
the stringent PSD requirements, any
increase in sulfur emissions could
result in reduction of the potential
production capacity of the shaleoil
industry.
R. J. Lovell, S. W. Dylewski, and C. A. Peterson are with IT Enviroscience.
Knoxville, TN 37923.
Robert C. Thurnau is the EPA Project Officer (see below).
The complete report, entitled "Control of Sulfur Emissions from Oil Shale
Retorts, "(Order No. PB 82-231 945; Cost: $16.50, subject to change) will be
available only from:
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
Telephone: 703-487-4650
The EPA Project Officer can be contacted at:
Industrial Environmental Research Laboratory
U.S. Environmental Protection Agency
Cincinnati, OH 45268
> U 8. GOVERNMENT PRINTING OFFICE: 1W2-559-017/0804
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