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Fundamentals of Partial Upgrading of Bitumen Murray R Gray Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.9b01622 • Publication Date (Web): 18 Jul 2019 Downloaded from pubs.acs.org on July 20, 2019
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Fundamentals of Partial Upgrading of Bitumen Murray R Gray*
Alberta Innovates, Suite 2540, 801 6th Avenue SW, Calgary, Alberta, Canada T2P 3W2
KEYWORDS : Bitumen, upgrading, thermal cracking, asphaltenes, deasphalting
ABSTRACT
In the past, transportation of heavy and bitumen to downstream refineries has been
accomplished by either adding a diluent or converting the vacuum residue to produce a
synthetic crude oil. In Canada, partial upgrading of bitumen to enhance its transportation
to downstream refineries is becoming more attractive as production increases from both
in situ and mining operations. Similar opportunities exist for inland production elsewhere
in the world. This review discusses the relationship between the key properties for
*
Corresponding author: Murray Gray at
[email protected] ACS Paragon Plus Environment
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transport, which are viscosity and density, and the composition of a crude oil. The
potential process pathways to achieve low-cost reduction in viscosity and density are
discussed, particularly thermal cracking and partial deasphalting. Thermal cracking is
effective for reducing the viscosity, but it is limited by the stability of the processed
asphaltenes in the product blend. While thermal cracking has a long history in refining,
the lower levels of asphaltene removal to achieve partial upgrading require removal of
solid asphaltenes, rather than the viscous liquids produced in current refinery
deasphalting plants. The benefits of combinations of reaction and separation approaches
are discussed, particularly combinations of thermal cracking, addition of reduced amounts
of diluent, and partial deasphalting.
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1. Introduction
Bitumen and heavy oil resources are widely distributed, with significant production
from Canada and Venezuela, as well as Angola, Brazil, Chad, China, Columbia,
Ecuador, Indonesia, Iraq, Mexico, Russia, Saudi Arabia, and United States. When this
production is located well inland, transportation to refineries is a challenge due to the
high viscosity of the oil. Pipeline transportation can be accomplished by diluting the oil
with light hydrocarbons, such as naphtha or natural gas condensate, by emulsifying the oil, or by heating the pipeline1, 2. Even when the product reaches the coast, the viscosity
of extra-heavy oils and bitumens may be too high for convenient transportation by ship
and diluent may still be required.
The oilsands production from Western Canada has grown rapidly over the past two decades to over 4.5 x 105 m3/d (2.8 million barrels per day) in 2017. Bitumen from the
oilsands is too viscous for pipeline transport, therefore, dilution with up to 30% solvent
or upgrading to a synthetic crude oil (SCO) have been the strategies used to deliver this
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material to refineries for processing, mainly in Canada and the United States. Typical
properties of bitumen, diluted bitumen, and synthetic crude oil are given in Table 1.
Maximum viscosity is limited by the hydraulic capacity of the pipeline, governed by the
maximum operating pressure and the frictional pressure drop. The temperature of the
pipeline changes seasonally, so the ground temperature is posted regularly to govern
blending limits. The density of the liquid affects the power required by the pumps for a
given flow and pressure. Operation with higher density, as for water, is feasible with
larger pump motors. The Western Canadian bitumens and heavy oils give a maximum density of circa 940 kg/m3 when blended with diluent to meet the viscosity limit at
maximum summer temperatures. The rest of the year, more diluent is required to give
the same viscosity at lower ground temperatures, giving a density below the maximum specification of 940 kg/m3. This density specification reflects, therefore, the observed
correlation between density and viscosity for typical unprocessed crude oils. The
specification on olefin content was added in 2002 to prevent the addition of cracked by-
products from petrochemical plants to the diluent pool in Alberta. Olefinic hydrocarbons
are not harmful to pipeline operation or infrastructure, but this specification serves to
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prevent any blending of cracked products with adjacent batches of crude oil shipped
through the pipeline networks. The olefin specification does not apply if the shipper
adds buffer volumes of uncracked crude oil before and after their shipment, to prevent
any cross contamination.
As bitumen production has increased, the fraction of bitumen production that is
shipped as diluted bitumen has also increased, leading to large volumes of diluent
(naphtha or natural gas condensate) entering Canada to enable bitumen transport. This
large volume of diluted bitumen has contributed to saturation of the available pipeline
capacity. In Venezuela, diluent is used to transport extra-heavy crude oil to coastal upgraders where SCO is produced for export2. When production capacity exceeds the
ability of the upgraders to process the crude oil, diluent is required for export by ship,
which may require importation of diluent from offshore sources or some processing of the oil3.
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Table 1. Pipeline Specifications and Representative Alberta Bitumen Products
Property
Specification
Athabasca
Diluted bitumen Synthetic crude
bitumen
from
in
situ oil (SCO)3
production2 Viscosity
maximum 350
5000 to
209 cSt at
centistokes
300,000 cSt at
15oC
(cSt) at
25 °C
8 cSt at 15oC
pipeline temperature Density, kg/m3
< 940
1015
922.1+5.1
863.3+4.4
Gravity °API
>19
7.9
21.8+0.8
32.3+0.8
Bottom solids
< 0.5 vol%
0-2%
< 0.1%
0
< 1 wt%
0
0
0
and water Olefin content4
1. Data from Gray4 2. Access Western Blend (AWB), a heavy, high TAN dilbit produced by Devon Energy Canada and MEG Energy Corp, five-year average 5. 3. Syncrude Sweet Premium, a light sweet synthetic crude produced from the Syncrude Canada, five-year average 5. 4. Olefin content is specified as weight equivalent of 1-decene, based on the 1H-NMR signal for olefinic protons6 Full upgrading to SCO gives a product of higher value than diluted bitumen, but it
requires very significant investment in facilities. Partial upgrading was defined by Keesom
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and Gieseman7 as any combination of bitumen processing steps and reduced diluent
addition to meet the specifications for pipeline transport is defined in Table 1. By reducing
or eliminating the amount of diluent, partial upgrading reduces the load on available
pipelines and shipping, but with lower capital and operating expenses relative to SCO
production. Partial upgrading technologies offer the potential for improved netbacks to
producers relative to diluted bitumen or extra heavy oil. Unlike available refinery
technologies, which focus on maximizing the conversion of vacuum residue to distillate
products, partial upgrading is focused on the density and transport properties of a blended
product that is handled as a crude oil for shipment to refineries. This review examines the
chemical basis of the density and transport properties of bitumen, and the potential
process pathways to achieve the goals of partial upgrading. Although the focus of the
analysis is Canadian bitumens, the same trends in fluid properties with processing will
apply to Venezuelan extra-heavy oils and other landlocked bitumen and heavy oil
resources.
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2. Bitumen Composition
Bitumens and heavy oils are naturally-occurring petroleum materials that are
characterized by high density and high viscosity. Bitumen has a density of 1,000 kg/m3
or higher, which corresponds to a gravity of 10 °API or less. Heavy oil is commonly defined
as petroleum material with density between 922 and 1,000 kg/m3, with a viscosity too
high for pipeline transportation at ambient temperature. A comparison of a variety of crude
oils is shown in Figure 1 together with the typical limit for pipeline transportation.
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to indicate heavy petroleum material, but in every case the same comments will also
apply to heavy oils.
Petroleum is an extremely complex mixture of hundreds of thousands or millions of
chemical components containing the elements carbon, hydrogen, sulfur, oxygen, nitrogen, vanadium, and nickel4. An increase in density is correlated with an increase in carbon, sulfur, and nitrogen 8, and with an increase in the size of molecules. Bitumens
are richer in these elements and in larger molecules than lighter crude oils. In addition
to elemental analysis and density, petroleum materials are characterized by their boiling
fractions, by solubility, and by specific assays for chemical functional groups or reaction
properties. Typical data for Athabasca bitumen is listed in Table 2. Other bitumens from
Western Canada have similar properties. Oxygen concentrations can be significant,
particularly in the asphaltene fraction, but the difficulty in measuring oxygen content
directly limits the quality of the data available. Due to the abundance of sulfur and
nitrogen in bitumen, the low concentration of hydrogen, and the large size of many
molecules in bitumen, approximately half of the bitumen will not distill even at a
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maximum temperature of 350°C under vacuum. This vacuum residue has normal boiling
points at atmospheric pressure ranging from 524 C to over 720 C. When this fraction is
subjected to temperatures over 350°C, it reacts to form smaller molecules and solid
insoluble material called “coke.” The tendency of bitumen to form coke is measured
under standardized reaction conditions as either the Conradson Carbon Residue (CCR)
or the Micro-Carbon Residue (MCR), reported as weight percent of sample. These two methods give equivalent results 9. The weight percent MCR indicates the amount of
difficult to process, carbon rich material in a crude oil or bitumen and is an important
quality indicator for refinery processing.
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Table 2. Composition and properties of Athabasca bitumen4
Component or property
Units
Value
Carbon
wt%
83.1
Hydrogen
wt%
10.6
Sulfur
wt%
4.8
Nitrogen
wt%
0.4
Oxygen, by difference
wt%
1.1
Vanadium
wt ppm
145
Nickel, ppm by weight
wt ppm
75
Density
kg/m3
1015
Gravity
°API
7.9
Viscosity at 25°C
cP or mPa·s
300,000
Light gas oil (LGO, 177-343 C)
wt%
10
Heavy gas oil (HGO, 343-
wt%
40
Vacuum residue, 524 C +
wt%
50
Micro carbon residue (MCR)
wt%
13.6
Boiling fractions
524 C)
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Asphaltene, heptane (C7)
wt%
11.5
wt%
17.2
insoluble Asphaltene, pentane (C5) insoluble
The solubility of crude oil components is also important for production and upgrading,
and standard assays are used to test solubility behavior. When bitumen is diluted in
paraffinic solvents, the densest fraction becomes insoluble and precipitates as
asphaltene solid. The data of Table 2 give asphaltene content by standard procedure
using dilution in either n-pentane, to give C5-asphaltenes, or n-heptane to give C7asphaltenes. A significant fraction of the asphaltene material is present as aggregates of molecules with a size in the range of 2-20 nm 10. The aggregation of these
components prevents comprehensive molecular analysis by any techniques available currently 11, 12 and gives rise to complex behavior at interfaces. Changes in the
asphaltene aggregates with processing are important in determining the viscosity of bitumen blends and in the formation of coke13.
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When crude oils are processed at high temperature, the solubility of the asphaltene
components tends to decrease. These changes are normally tested by determining the
fraction of the product blend that will not dissolve in toluene. Initially, bitumen is
completely soluble in toluene, except for mineral contaminants such as clay. With
exposure to high temperatures, coke can begin to form, giving some material that is
toluene-insoluble. The compatibility of the asphaltenes in processed bitumen for
blending can be examined using spot-tests on filter paper, microscopic examination after dilution with solvents, or titration measurements 14, 15.
3. Physical Properties and Dependence on Composition The primary goal of partial upgrading is to enhance the transportability of bitumen,
which focuses on the crucial properties of viscosity and density. The reduction of
viscosity to 350 cSt at pipeline operating temperature is the most important target,
because this viscosity most commonly controls the amount of diluent required to make
bitumen transportable by pipeline. For example, a diluted bitumen such as Access
Western Blend (AWB) cycles seasonally from 20.3 API in summer to 23.3 API in
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winter, with a long-term average of 21.8 API 5. It falls below the maximum limitation on
density in order to meet the maximum viscosity. However, for diluted bitumens from
other reservoirs, density may be the limiting specification in summer.
3.1 Reduction in Bitumen Viscosity
The high viscosity of bitumen is due to the high-boiling components in the vacuum
residue fraction, which includes the asphaltenes. The strong physical interactions of the
large molecules and the aggregated asphaltene species give rise to this high viscosity. Although asphaltenes have a strong impact on viscosity16, 17, and contribute to viscoelastic behavior at low temperature18, the exact impact of molecular aggregation at
the nanometer scale is very difficult to assign. Viscosity is extremely sensitive to
temperature; an increase in temperature reduces the strength of the molecular
interactions and reduces the viscosity. As a blend of these heavy components with
lighter material, the viscosity of bitumen is also extremely sensitive to the presence of low-boiling hydrocarbons, i.e. solvents19. Both temperature and composition can reduce the viscosity by orders of magnitude, from 106 mPas to 102 mPa·s or less 19.
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An example of the reduction in viscosity due to increase in temperature and solvent
addition is shown in Figure 2. The left panel shows viscosity as a function of
temperature, and the right panel shows viscosity as a function of addition of naphtha as
a solvent. To achieve a viscosity of 100 Pa·s (A), heating to 40 C or addition of 3.5%
solvent are equivalent. Reduction to 3 Pa·s requires 80 C or 18% solvent. Achieving a
pipeline viscosity of approximately 0.3 Pa·s requires around 33% solvent.
Biases in measurement of high viscosities are common, due to viscous heating during experiments or the presence of residual solvents 19, 20. Errors are much less significant
for diluted or upgraded bitumens. In general, any change in viscosity due to composition
or temperature, in the absence of chemical reactions, are completely reversible. Once
the composition or temperature is returned to the original condition, the viscosity will
return to its original value within a few days.
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No Solvent addition
25 oC temperature (A)
(B)
Figure 2. Viscosity Reduction via Temperature and/or Solvent Addition21.
In order to achieve a permanent reduction in viscosity, the chemical composition of
the bitumen mixture must change due to physical removal or addition of components, or
the structure of the components must change due to chemical reaction. The following
changes are known to reduce viscosity:
•
Increase in the fraction of low-boiling components, by adding a solvent or diluent
(physical change), or by cracking large molecules to make small solvent-like fragments
(chemical reaction)
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•
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Decrease in the fraction of high boiling components, e.g. vacuum residue and
asphaltene, by physical removal or chemical reaction. For the asphaltene fraction, the volume fraction in solution is particularly important 22, 23
•
Reduction in density, due to chemical reactions such as hydrogenation or
desulfurization.
Models for viscosity of bitumen and diluted bitumen give directional information on the contributions from the main components as discussed above24, but the complexity of the
vacuum residue components and asphaltenes requires experimental data for
verification.
3.2 Reduction in Bitumen Density
The target for current pipeline operation is a maximum density of 940 kg/m3 (minimum
gravity of approximately 19 °API). The same factors that reduce viscosity also reduce
density: more light components, less heavy components, and shifting the elemental composition to increase hydrogen and decrease sulfur and nitrogen content 8. Although
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bitumen contains a significant concentration of oxygen (Table 2), insufficient data are
available to define the contribution of the oxygenated components to density. Reducing the density of bitumen from approximately 1,000 kg/m3 to approximately 940 kg/m3 requires the addition of around 24 vol% of 750 kg/m3 density condensate.
3.
Market Value – Composition Relationships
Blends containing bitumens are discounted in price relative to light crude oils because
the yields of desirable distillate products are lower and cracking of large components is
needed to increase distillate yield. In addition, more processing is required to remove
unwanted contaminants such as sulfur and metals and achieve the required product
specifications. The entries of Table 3 list the main components of bitumen that change
the crude oil properties of interest to refiners. The vacuum residue fraction must be
cracked in order to produce transportation fuels, therefore, the amount of this fraction
and its tendency to form coke have an impact on product yields from the refinery.
Table 3. Effect of Composition Changes on Value of Blends Containing Bitumens
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Bitumen Component
Crude
Oil
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Properties Effect on Refinery
Assessed by Refiners Vacuum residue, including Micro asphaltenes
Carbon
(MCR)
Residue Reduced yield of distillate
content
or
Conradson Carbon (CCR)
Limited capacity for processing in some units
C7 Asphaltene content Sulfur and nitrogen
Sulfur
and
nitrogen, More hydrotreating of
weight%
products or discounted value
Metals (V and Ni)
Metals, parts per million
Catalyst deactivation
Acids in bitumen
Total acid number (TAN)
Potential for corrosion and corrosion mitigation costs, or limits on feed blends
Olefins
Weight % olefins by NMR,
Bromine
1H-
Potential for fouling in
number, refinery equipment, and
diene number
indicator of unstabilized thermally cracked material
Aromatic distillates
compounds
in Vacuum gas oil density, Yields from refinery sulfur content, aniline point; processing and blending Cetane
number
of into products
distillates
Sulfur is undesirable in fuel products due to environmental regulations, so that
refineries must use catalytic hydrodesulfurization to remove it. The content of nitrogen
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compounds is not often examined in crude oil marketing because unlike sulfur, the
nitrogen content does not have an environmental impact that is subject to regulation as
a component of fuels. However, the presence of high nitrogen levels in bitumen has
significant impact as an inhibitor or poison on refinery catalytic processes, including hydrodesulfurization25, hydrocracking26, catalytic cracking and catalytic reforming27. Like
nitrogen, the vanadium and nickel are a concern to refiners due to their role as catalyst
poisons. These elements accumulate in hydroprocessing catalysts as metal sulfides, and cause unwanted side reactions in fluid catalytic cracking catalysts28.
The acidity of the feed, due mainly to organic carboxylic acids, is measured as total acid number (TAN). High TAN may result in increased corrosion of refining equipment29,
but a number of factors control the actual corrosion rates, including the specific acid components which can change during processing30, sulfur species in the crude oil and hydrogen sulfide31, and the details of the metallurgy. Consequently, a measurement of
TAN by itself is not an accurate indicator of corrosion rate when comparing between different crude oils29. Furthermore, TAN does not affect refining yields. Refiners that
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have not upgraded their refining equipment may not be able to process much high TAN
crude oils, but refiners that have upgraded their metallurgy can process crudes with a
higher acid content. This disparity can lead to discounts on high-TAN content oils in
some refinery markets.
Olefins are generated in refineries by fluid catalytic cracking and delayed coking
processes, and are an important component of gasolines. The content of olefins in a
crude oil, which arises from thermal cracking, is a concern mainly for access to pipeline
systems, as discussed above. Refineries use olefin content in crude oil as an indicator
of prior thermal cracking of a feed, but there is little evidence for negative impact of these components in refinery operation, apart from some fouling of distillation trays15 and hydrotreater catalyst beds32, both due to diolefin components. Olefins are an
inevitable result of thermal cracking of hydrocarbon mixtures, but their concentration
may potentially be reduced by a range of reactions, including polymerization or
dimerization, hydration, and mild catalytic hydrogenation, or by selective separation
from the rest of the cracked products. Depending on the location of the plant,
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hydrogenation may be the least desirable of these options because it requires additional
infrastructure for generation of hydrogen gas.
Aromatic compounds, in contrast, have direct implications for refinery operating units.
Aromatic rings are not easily cracked, therefore, a high aromatic content in the vacuum
gas oil fraction reduces the yield of cracked products. The combustion properties of
aromatic rings are undesirable in diesel engines because they ignite too quickly, as
indicated by decreasing cetane number. Consequently, highly aromatic diesel fractions
must either be hydrogenated before blending into fuels, or added in limited concentration33.
4.
Processing Reactions to Improve Properties and Market Value
Dozens of process technologies have been used over the past century to add value to
heavy petroleum fractions by inducing chemical reactions, and many more have been
pilot tested. At the base of this process technology is a very limited range of chemistry,
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consisting of thermal reactions, and a limited set of catalytic reactions. This section
reviews the main reactions that are relevant to partial upgrading of bitumen, which
emphasizes liquid-range products rather than gases. Data are presented from
laboratory experiments under idealized conditions. The final sections of this paper will
discuss how these processes can be used to meet the objectives of partial upgrading of
bitumen.O
4.1 Thermal Reactions Heating of petroleum liquids to over 350°C begins a complex series of reactions at
rates that are sufficiently fast to be of commercial and practical interest. The yields and
product properties from a given feed depend on the time and temperature history of the
components, which in turn affect the formation of vapor phase or solid phase coke. The
fundamental reactions are:
Cracking or scission, which breaks carbon-carbon, carbon-sulfur, and carbon
oxygen bonds to produce liquid and gas products, and reactive species such as
olefins and diolefins
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Addition reactions of reactive species in the liquid phase, giving coke precursors
Hydrogen transfer reactions due to formation of unsaturated and aromatic species
4.1.1
Thermal Cracking
Cracking in the liquid phase gives all three reactions, while cracking in the vapor
phase gives mainly scission, with little addition or hydrogen transfer. Cracking in the
vapor phase gives much higher yields of light olefin products, such as ethylene,
propylene, and butylenes. Addition reactions in the liquid phase increase the
concentration of the asphaltene fraction, which eventually becomes insoluble in the liquid and begins to form solid coke13.
The most reactive components of bitumen are in the vacuum residue, where reactivity
is defined as weight fraction cracked to lighter components at a given temperature for a given amount of time34. High reactivity for cracking is often associated with high sulfur content, mainly due to the organic sulfide species4 which increase in concentration with
boiling point. Within the vacuum residue, the reactivity of the asphaltenes is significantly
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different. For example, Figure 3 shows the conversion of ten fractions of Athabasca
vacuum residue by cracking with and without hydrogen. The ten fractions were
prepared by extraction with supercritical pentane. The heaviest fraction, number 10,
contained most of the asphaltenes (88 wt% C5 asphaltenes). This fraction resulted in lower conversion to light products than the other fractions but higher coke yield. The
asphaltene-rich fraction 10 gave 29% coke yield (as g coke/g fraction 10) when reacted
under nitrogen, compared to only 2.7 wt% from fraction 1 and 4.7 wt% from fraction 9.
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80 70 60 50 40 30
Maltene fractions
20
Asphaltene
Residue Conversion to < 524oC,%
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
Nitrogen at 0.24MPa Hydrogen at 10 MPa Hydrogen at 10 MPa + Catalyst Mean for Fractions 1 - 9 St Dev
10 0 1
2
3
4
5
6
7
8
9
10
Fraction Number
Figure 3. Reactivity of Heavy Fractions of Athabasca Bitumen at 430 C for 1 h35
The activation energy for thermal cracking of vacuum residue is in the range 200-250 kJ/mol, which is consistent with a free-radical chain reaction mechanism 4, 36. Once the
conversion of vacuum residue exceeds approximately 20-30%, coke formation can be a significant operating problem37, depending on how the heat is provided to the reacting
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Page 28 of 81
liquid. The time to achieve 20% conversion ranges from approximately 1 hour at 365°C
to less than 10 minutes at 400°C.
The data of Figure 4 illustrate how the properties of bitumen change with thermal
cracking without formation of insoluble solids. As shown in this figure, viscosity is
reduced significantly over time, but the density of the oil decreases only slightly. The
data in this figure were obtained at different temperatures, then represented on an
equivalent time basis at a reference temperature of 427 C using the following equation:
=
exp
[ ()(
1 + 273
)]
1 700
(1)
with t the experimental reaction time at temperature T C, Ea = 50.1 kcal/mol, and R = 1.987 cal/mol/K.
The lowest viscosity obtained in this example was still too high for pipeline transport,
and the density was still much too low. Thermal reactions alter the properties of the
asphaltene components, so that they become less stable in the product oil and are
more easily precipitated by blending with more paraffinic streams. The same thermal
reactions also increase the volume of diluent material, which destabilizes the
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asphaltenes in solution. The phase stability of asphaltenes in the crude oil is measured
by titrating the sample with the paraffin n-heptane until precipitation is observed, and the
result is expressed as the peptization value or P-value. Peptization is defined as the
dispersion of sub-micron sized particles, or “colloids” in a liquid, which in this case is the
dispersion of asphaltenes in the crude oil. A P-value of 1.0 indicates that the
asphaltenes are on the verge of precipitation without adding any n-heptane. Higher P-
values indicate a greater margin of stability to maintain the asphaltenes in solution when
a crude oil is blended.
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1020
105
1000
104 980 103
Density, kg/m3
Viscosity, cP at 25oC
106
960 3.5 3.0
P-value
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 30 of 81
2.5 2.0 1.5 1.0
Minimum for stability
0.5 0
200
400
600
800
1000
1200
Equivalent Reaction Time, s
Figure 4. Effect of Thermal Cracking on the Properties of Athabasca Bitumen 38. Experiments were in a laboratory batch reactor at maximum temperatures from 423449 C. The reaction time is given as equivalent time at 427 C.
In the example shown in Figure 4, the unreacted bitumen has a P-value of 3.4 so that
it would be stable in a mixture with up to 80% diluent. In contrast, the product at the
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highest reaction time has a P-value of only 1.05, which would begin to precipitate material when mixed with only 25% diluent 38. The minimum recommended P-value is 1.1 in refinery practice 38, for manufacturing fuel oils that do not plug intake filters on
engines and boilers. The key point is that too much thermal cracking of bitumen gives
unstable products even before coke begins to form. The result is that this processed
bitumen may be incompatible with diluent or with refinery streams. These data show
why thermal cracking by itself cannot achieve pipeline specifications without addition of
some diluent. The primary goal for partial upgrading of bitumen is to economically meet
pipeline specifications with reduced or no addition of diluent.
The main driver for thermal cracking is temperature. The weakest bonds in bitumen
begin to break in the range of 250 C, giving rise to the formation of detectable hydrogen
sulfide. At 350 C the rates of cracking weak carbon-carbon bonds are more
pronounced, so that short residence times of a few minutes at this temperature are
considered the limit for distillation with minimal alteration of the feed.
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Pressure has little effect on the reactions in the liquid phase, because the liquid
density is only changed significantly at pressures well over 3,000 psia (21 MPa), the
normal upper limit for refinery processing. The combination of pressure and reactor
configuration can, however, have a significant impact on the outcome of the thermal
reactions, when the thermal cracking is carried out in a continuous process. Higher
pressure operation suppresses the formation of the vapor phase, which reduces the
formation of light olefin products such as ethylene, and increases the residence time of the liquid in flow reactors 39.
Reactor design can allow the separation of liquid and vapor phases, so that the vapor
phase is subjected to much shorter reaction times than the liquid phase. Addition of
gases such as steam further enhance the vaporization of lighter components at a given
pressure, and can reduce the time available for reaction in both liquid and vapor phase
by increasing the velocity of fluids in process furnaces. Steam can be used to sweep the
vapors out of a reactor to give much shorter reaction times for the vapor phase than for
the liquid phase and thereby reduce olefin formation in the vapor phase.
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4.1.2
Addition reactions
Although the temperatures that produce thermal cracking of bitumen favor the
cracking of chemical bonds to give lighter products, reactions in the liquid phase always
progress to give larger molecules via addition reactions. Due to the complexity of the
mixture of compounds that comprise bitumen, these reactions are exceedingly difficult
to track directly, but they are easily identified in reactions of representative pure compounds at the same conditions 4. An example of this type of reaction is illustrated in
Figure 5, which shows an actual reaction based on experimental data. In this case, the
product has almost twice the molecular weight of the reactant.
C 10 H21 H21 C 10
H21 C 10
C 10 H21
C 10 H21 C 8 H17
2
H15 C 7
H21 C 10
C 10 H21 H21 C 10
C 10 H21
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Figure 5. Example Addition Reaction of a Model Bitumen Component 40. Addition products were 40 wt% of the total products of reaction at 420 C after 20 minutes
These reactions contribute to the formation of less soluble material in the bitumen,
which is detected as asphaltenes (heptane insoluble) and coke (toluene insoluble).
These solubility characteristics are a major factor in coke formation, which is covered in
Section 4.1.4 below.
4.1.3
Hydrogen transfer reactions
Thermal cracking reactions tend to redistribute hydrogen. The light cracked products
from bitumen tend to be richer in hydrogen than the initial mixture, so that the liquid
phase becomes more depleted in hydrogen as the reactions proceed. Within the liquid
phase, components can donate hydrogen by undergoing reactions that release
hydrogen. For example, partly hydrogenated aromatic compounds give up hydrogen to
form more aromatic products (lower H/C ratio). The hydrogen that is released has been observed to saturate olefins at 270-310 C in the liquid phase 41.
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Hydrogen donor compounds are naturally present in the vacuum residue and
asphaltene fractions of bitumen, but the exact concentrations of donatable hydrogen are difficult to measure. Estimates range from 10% of the total hydrogen content42 to 30% 43,
although the latter value is too high based on data for the types of hydrogen
present4.
Athabasca asphaltenes are able to transfer measurable hydrogen at temperatures as low as 100-150 C, and give conversion of olefins at 250 C 44. The quantity of hydrogen
transferred was about 5% of the total hydrogen content.
Augmenting the natural hydrogen donor capacity by adding partly hydrogenated aromatic compounds gives benefits during thermal cracking 39. These streams can both
act as hydrogen donors and enhance the solubility of asphaltenes. The result is
suppression of solids or coke formation at a given reaction time and temperature. When
the stability of the asphaltenes in the product oil limits conversion, the addition of
hydrogen donors allows more conversion, which can achieve lower viscosity and still maintain the P-value within an acceptable range. 39
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4.1.4
Coking
If thermal cracking continues past the point where asphaltenes are no longer stably
dispersed in the crude oil, they begin to precipitate from the oil and form a new phase, commonly called coke13. The coke material can attach to the surfaces of process
equipment, causing severe fouling and plugging. While coke can be plastic at high
temperature, it is a solid at normal temperatures.
The progress of coke formation is illustrated in an open reactor in Figure 6. The
concentration of asphaltenes increases with time for the first 45 min, then begins to fall
as toluene-insolubles, or coke, begins to form. The delay of the onset of coke formation
is called the induction time.
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80 Volatiles Heptane solubles Asphaltene Toluene insolubles
70 60
Yield, wt% of feed
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
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50 40 30 20 10 0 0
50
100
150
200
Time, min
Figure 6. Thermal cracking of Cold Lake Vacuum Residue at 400 C. 13 Data are from reaction in an open reactor which allows evolution of gas and vapor, reported here as volatiles. Smooth curves are from a kinetic model for thermal cracking and coke formation.
When the more volatile components are retained in the reactor, more and more gas
formation occurs (Figure 7), which in cracking of petroleum is defined as gases at
ambient temperature and pressure. These gases include hydrogen sulfide, methane,
ethane, ethylene, propane, propylene, butylenes, and some butane, along with low
concentrations of hydrogen, carbon monoxide and carbon dioxide.
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100
Yield, wt%
80
60 Solids Liquid product Gas
40
20
0
Yield, wt%
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 38 of 81
20 10 0 0
100
200
300
400
Time, min
Figure 7. Thermal cracking of Athabasca bitumen in a closed reactor at 400 C 45. Solids yields are net formation of filterable material, subtracting the mineral solids present in the initial bitumen.
The data of Figure 7 show three distinct phases of solids formation: an initial induction
period that is around 80 minutes in duration where very small amounts of solids are
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formed, linear formation from 80 min to around 300 min, then a significant increase in
solids yield starting at 300 min of reaction. The duration of the induction period was
longer than on Figure 6 for Cold Lake Vacuum Residue, which illustrates that the onset
of coking is a function of the composition of both the liquid phase in the reactor and the
reacting asphaltene material.
The formation of almost 12% gases, which are rich in hydrogen, gave liquid and solid
products that were depleted in hydrogen relative to the initial bitumen. The H/C ratio of
the liquid product dropped from 1.455 mol/mol at time zero to 1.06 at 360 min.
If the coke formation occurs in a controlled fashion within a reaction vessel, then this
mechanism provides a means to continue cracking the heavy components of the
vacuum residue to obtain very high conversions. In this case the conversion of the
vacuum residue fraction can approach 100%, giving coke, lighter liquid fractions, and
gases as products. In a batch reactor, conversion is defined as the initial mass of
vacuum residue, less the remaining vacuum residue liquid, all divided by the initial mass
of vacuum residue.
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Page 40 of 81
A large number of studies show that coke forms most easily from the asphaltene
fraction, so that partial or complete removal of the asphaltenes will significantly reduce
the formation of coke. An example is given in Table 4, for a whole vacuum residue and
two deasphalted samples. The yields of coke and asphaltene are given after thermal
cracking at 420 C for one hour.
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Table 4. Formation of Asphaltenes and Coke from Fractions of Vacuum Residue.46 Weight fractions are for weight of initial sample.
Composition
Initial C7-
Whole
C7 soluble,
C5 soluble,
vacuum
deasphalted
deasphalted
residue1
with heptane
with pentane
9.4
0
0
12.6
3.5
0
3.2
3.5
0
2.1
0.0
0
15.5
13.6
6.0
asphaltenes, wt% Initial C5asphaltenes, wt% Initial C5 soluble-C7 insoluble, wt% Final tolueneinsoluble coke, wt%2 Final C7asphaltenes, wt%2 1. Vacuum residue from a Middle East crude oil. 2. Reaction conditions: 20wt% solution of sample in 1-methylnaphthalene, react at 420 C for 1 hour.
Removal of the C7-asphaltenes eliminated the formation of coke, but due to addition and other reactions, significant amounts of asphaltenes were formed. The removal of
the C5-insoluble asphaltenes resulted in much less asphaltene formation. These results
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suggest that material that is soluble in heptane but insoluble in pentane may play an
important role in the formation of asphaltenes during thermal cracking. The contribution
of these different fractions to coke formation and generation of more asphaltenes during
thermal cracking is an important fundamental knowledge gap.
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4.1.5
Thermal cracking in industrial reactors
The data presented in this section on the fundamentals of bitumen reactions are
derived from idealized conditions, in laboratory reactors that use either intense mixing
by impellers or very small scale (a few milliliters of liquid) to achieve uniform
temperatures. Under these conditions, the temperature of the reacting liquid in the bulk
is very similar to the reactor walls.
When thermal cracking is conducted at a larger scale, as in pilot plants or
demonstration plants, these conditions no longer apply. Heating of bitumen in process
furnaces can give wall temperatures that are significantly higher than the bulk liquid,
giving localized reaction conditions with coke formation even as the bulk fluid is just
beginning to react. Such localized conditions can give rise to fouling of surfaces and
formation of solids even when the temperatures might appear safe in the bulk liquid.
Continuous reactor operation tends to cumulate these effects with time of operation, so
that fouling that may not be detected in a batch laboratory reactor can shut down a
continuous process in a matter of hours.
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4.1.6
Page 44 of 81
Boundaries on thermal cracking processes
The trends in product yield and density can be illustrated by plotting the results of reactions or upgrading processes on a x-y plot of density versus volumetric yield 8. The
target for partial upgrading technologies is to achieve pipelineable density and viscosity
with minimal loss of liquid yield. Data for thermal cracking and coking are illustrated in
Figure 8.
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1020 Athabasca bitumen
1000
Delayed coking Thermal cracking
980
API Gravity
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
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Single pass coking
960 940 Maximum Pipeline Density
920 900 880 70
80
90
100
110
Yield, vol% Figure 8. Density and yield from thermal cracking of Athabasca bitumen. Data are for thermal cracking at 263-371 C 47, single-pass coking without recycle at 530-550 C 48, 49 and delayed coking 8.
The data illustrate that mild thermal cracking alone does not significantly change the density of the product. All but one product reported by Henderson and Weber 47 had a density within 12 kg/m3 of the feed, similar to the data presented in Figure 8. Without
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the removal of dense components or elements, breaking of bonds alone does not
significantly change the density of the liquid product. The formation of dense insoluble
solids, such as coke, which is removed from the liquid product, can provide a means of
changing the density. This is illustrated in Figure 8 for single-pass coking, which
achieves around 80% conversion of vacuum residue, and delayed coking, which
achieves 100% conversion. The latter process exceeds the required specifications for
partial upgrading.
4.2 Catalytic Reactions 4.2.1 Catalytic Cracking Reactions Catalysts with strong acidity have the capacity to accelerate cracking of carbon-
carbon bonds in petroleum materials, and these materials are widely used in processing
of distillates. The vacuum residue components of bitumen, however, are rich in nitrogen
compounds, which strongly suppress the activity of these catalysts and often result in
irreversible deactivation, and contain high-boiling compounds that react to form coke on
the catalyst surface. Residue fluid catalytic cracking uses rapid recycle and
regeneration of zeolite-based catalyst to overcome this deactivation, but this technology
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is limited by the amount of coke formation to feeds with less than 5-10% MCR content50,
well below the level of a bitumen (Table 2). RFCC could be applied to blends of bitumen
with other more easily processed crude oils, or to a deasphalted bitumen with low
enough MCR content.
Hydrocracking uses a dual-functional catalyst that combines acid cracking with
hydrogenation to control coke formation, but can only be applied one the nitrogen
content is reduced to circa 2000 ppm by a combination of desphalting and hydrotreating51. Consequently, RFCC and hydrocracking are valuable in refineries
where suitable streams can be prepared by blending or prior separations, but this
complexity is not suitable to producing high volumetric yields of partially upgraded
bitumen at low competitive.
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4.2.2
Page 48 of 81
Catalytic Hydrogenation
Catalysts based on metal sulfides, particularly molybdenum-nickel blends, are very
effective for hydrogenation of sulfur, nitrogen, and metal-bearing compounds, and for
hydrogenation of aromatic compounds and olefins. These reactions are the basis of
commercial hydrotreating processes. Reaction conditions range from very mild, for
conversion of diolefins in cracked products, to very severe for removing sulfur from vacuum residues 25, 32.
The addition of metal sulfide catalyst and high-pressure hydrogen during thermal
cracking reactions enables much more conversion of vacuum residue components
without the formation of coke. This combination of conditions results in hydrogenation of all olefin products from thermal cracking, which suppresses their addition reactions 52 and helps to suppress coke formation 36. This approach is the basis of commercial
hydroconversion processes which reduce the density and viscosity of the product oil by
a combination of conversion of the vacuum residue fraction and removal of a significant
fraction of the sulfur. The capital cost of high pressure reactor operation, coupled with
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the cost of hydrogen production and handling large volumes of hydrogen sulfide, make
this reaction approach much less attractive for partial upgrading than for refinery operation7.
4.3 Other Reaction Pathways 4.3.1
Sodium-Sodium Sulfide Cycle
Metallic alkali metals, such as sodium and lithium, are strong reducing agents that
react readily with organic sulfur compounds and hydrogen to produce sulfur-free hydrocarbons and sodium sulfide 53-55. A small amount of hydrogen gas is required at
low pressure to ensure that the fragments of bitumen do not undergo addition reactions
after the sulfur is removed. A catalytic cycle can be established if the sodium sulfide is
separated from the reaction products and electrolytically reduced to regenerate the sodium metal 56. Removal of sulfur as elemental sulfur is accompanied by significant
removal of metals, conversion of vacuum residue, reduction in density, and reduction in
viscosity. This technology faces two significant barriers: establishing safe operation in a
refinery environment with large volumes of molten sodium, and development of
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electrolytic cells to operate continuously and reliably for conversion of molten sodium
sulfide to metallic sodium and elemental sulfur.
4.3.2
Carbon Oxidation-Water Reduction
The direct use of water as a source of hydrogen is highly desirable, but extremely
challenging due to the high enthalpies of reaction of water to form hydrogen species.
One approach is to develop catalysts that can drive gasification reactions, which
normally occur at temperatures over 600 C, at the temperatures for thermal cracking of
liquid hydrocarbons, which are below 450 C. The general approach is cracking of heavy components to give a carbon rich solid, indicated as C in reaction (2), followed by
reaction of the carbon-rich solids with steam to produce carbon dioxide and hydrogen
via reactions (3) and (4). The liberated hydrogen is then available for reaction with
bitumen components (5).
Bitumen
C + Vaporized products
(2)
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C + H2O
CO + H2
(3)
CO + H2O
H2 + Bitumen
CO2 + H2
(4)
Hydrogenated products
(5)
The obvious consequence of the net reaction of water is that carbon oxides must be
produced in stoichiometric quantities.
A number of studies have attempted to use this type of chemistry with liquid fractions of
heavy oils and bitumen. The most successful approach is to use catalysts to establish a
redox cycle to transfer the oxygen from water to carbon, catalyzing reactions (3) and (4)
to form carbon dioxide, and thereby produce hydrogen from water that can be reacted with the oil components57, 58. The approach has been demonstrated for iron oxide
supported on titanium dioxide powder. Data for dispersed particulate catalysts have also given some evidence for increased carbon dioxide formation, but in lower amounts 59.
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In the absence of a catalyst, the effect of adding water to thermal cracking reactions is to add a solvent which alters the phase behavior of bitumen components 60. Lower
molecular weight species in bitumen readily dissolve in liquid water at high-pressure or supercritical conditions 61, 62 and the solubility of water in heavy bitumen fractions increases dramatically with temperature 63. Although water undergoes exchange of
hydrogen atoms with bitumen under thermal cracking conditions, based on isotope studies 64, the available scientific papers do not suggest significant net transfer of hydrogen to the bitumen 60.
4.3.3
Ionizing Radiation
Besides thermal reactions, other techniques can create active reactive species in bitumen, including ionizing radiation (e.g. beams of electrons or gamma rays 65, and contacting with hydrogen plasma 66. In order for these reactive species to give
measurable conversion, the temperature of the bitumen must be high enough to thermodynamically favor cracking reactions 67, and to support chain reactions at useful
rates. Consequently, these schemes would need to operate at comparable
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temperatures to conventional thermal processes, as demonstrated on hydrocarbon model compounds 65.
4.3.4
Fluid-Mechanical Alteration
A number of patents have proposed the use of cavitation from sonication or fluid
expansion from jets to cause reactions and structural changes in heavy bitumen fractions 68-71. The collapse of bubbles during cavitation can give tiny hot spots with temperatures over 3,000 C that initiate reaction 72. However, at low temperature of the
bulk liquid, the rate of conversion of hydrocarbons is insignificant and addition or polymerization reactions are favored 73, 74. Like ionizing radiation, significant conversion
would require operation at temperatures comparable to conventional thermal processes. Shear forces in liquids can break high molecular-weight polymers 75 and DNA 76.
The molecular components of bitumen are all below a molecular weight of 3,000 11, 12,
which is much lower than the molecular weight of polymers, which are over 1 million
and can be broken by fluid forces. The largest aggregated species in bitumen are the
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asphaltene aggregates, which are in the range 2-20 nm 10, and are also smaller than the
size of polymers that break due to cavitation shear.
When cavitation and thermal cracking are used together to obtain more conversion of
heavy components, the compressed fluid is typically first heated and then expanded
through a flow device. Reaction of the feed oil may occur due to thermal cracking under
pressure, as well as cavitation at the outlet. As the residue components crack to form
light ends, the volume of vapor is lower than in an unpressurized cracking reaction,
which in turn affects the actual residence time of the liquid phase at reaction
temperatures. This coupling of reaction, phase behavior, and fluid mechanics makes
assignment of the contribution of each mechanism more challenging.
4.3.5
Oxidative Desulfurization
Oxidative desulfurization can be used to reduce the sulfur content of crude oils by
converting sulfur species into the corresponding sulfoxides and sulfones, which are
removed by extraction or adsorption. The amount of material removed depends on the
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molecular weight of the species containing the sulfur, the number of sulfur molecules on
the species, and the solubility properties of the reacted material.
We can examine the impact of oxidative desulfurization for a typical bitumen. Assume
the bitumen contains around 5 wt% sulfur and has a molecular weight of around 582 g/mole 77, 78. This gives an average ratio of 0.87 moles sulfur per mole of bitumen, which
means that a typical molecule contains at least one sulfur. If there is one sulfur atom on
each typical molecule, removal of half of the sulfur requires removing around 40 wt% of
the bitumen.
In the asphaltene fraction, the average molecular weight is higher, approximately 2,000 78, and the sulfur content is higher at 6.5 wt%. Conversion of 50% of the sulfur
would convert at least one sulfur per molecule to a polar sulfoxide or sulfone. Such
oxidation of bitumen generates more material that will not dissolve in heptane, nominally asphaltenes 79. These high density, oxidized products are unlikely to give efficient
removal by extraction into water or by adsorption. The combination of high molecular
weight and polar sulfur species could result in almost complete conversion to highly
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insoluble surface-active solids that dissolve in neither hydrocarbon solvents nor water.
Such oxidation products would cause serious problems with attempts to extract the rest
of the oxidized sulfur species from the bitumen into an aqueous solution. The
combination of large losses of oxidized sulfur species and potential insolubility of
products makes oxidative desulfurization better suited to removing low levels of sulfur,
as a polishing step for distillates rather than bulk desulfurization of high-density
materials.
In order to minimize the serious loss of yield, the sulfones and sulfoxides would need
to be reacted to remove the sulfur, leaving the hydrocarbon portion of the compounds
behind. Such chemistries have not been demonstrated on heavy bitumen fractions,
although patents claiming successful conversion of model compounds and a crude oil feed containing 2% sulfur have been published80.
5.
Separations to Improve Properties and Market Value
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Two types of separation technology are commonly used in petroleum processing;
distillation and solvent deasphalting. Distillation under vacuum in commercial operation
can remove up to half of the bitumen, which is useful in processing of fractions in an
upgrading or refining plant, but not by itself as a means of partial upgrading. Higher
boiling point fractions can be recovered at the laboratory scale using specialized
equipment such as ultra-high vacuum (to 573 C normal boiling point) or short-path distillation (to 720 C) 81.
In solvent deasphalting, paraffinic solvents such as propane, butane, isobutane,
pentane or hexane are used to precipitate the least soluble components of the vacuum
residue, either as a liquid phase or as a solid depending on the solvent used and the
temperature. By selection of solvent and solvent-bitumen ratio any desired amount of precipitation can be observed, from 1% up to 50% of the initial bitumen 4, 82.
For example, the data of Figure 9 show that a range of material can be precipitated
from Athabasca bitumen depending on the choice of solvent. If solvents such as butane
or propane are used, which are weaker than pentane, then the trend continues to the
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upper left in the plot in Figure 9, and larger and larger amounts of material is
precipitated. The precipitate is rich in asphaltenes, which are the densest fraction of
crude oil with the highest concentrations of sulfur, nitrogen, and metals. The
asphaltenes also have the highest yield of MCR.
20
15
10
toluene
n-pentane
Amount precipitated, wt%
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
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5 Benzene + n-pentane Pure solvents
0 13
14
15
16
17
Solubility parameter, MPa
18
19
1/2
Figure 9. Precipitation of Asphaltene Components as a Function of the Solubility Parameter of the Liquid Phase 83. Data are for Athabasca bitumen at 20 C and a 20:1 ratio of solvent to bitumen, with solvent strength plotted as the Hildebrand solubility parameter84.
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Consequently, the precipitation of asphaltene components produces a product of
lower density with reduced MCR, sulfur, nitrogen and metals, as illustrated in Figure 10.
The density of deasphalted bitumen is reduced (API gravity increases) as a result of
removing material via solvent deasphalting, and the diluent requirement to meet pipeline
specifications is reduced. At the same time that the yield of bitumen is reduced, the
yield of asphaltene by product is increased, which must be sold or disposed of in some
way.
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1040 Maximum Pipeline Density
1020
Density, kg/m3
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1000 980 960 940 920
Cold Lake bitumen, 1000 kg/m3
900 50
60
70
80
90
100
Yield, vol%
Figure 10. Yield and Density of Product Oil from Solvent Deasphalting. 82 Data for Cold Lake bitumen from deasphalting with butane and pentane.
6.
Feasible Range of Partial Upgrading Products
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Given the range of possible reactions and separation processes that can be applied to
bitumen to achieve partial upgrading, the technically feasible space for potential
upgrading operation can be defined. The data of Figure 11 show the trajectories for the
established technologies described in Sections 4 and 5 that offer high volumetric yields
of product per barrel of bitumen. The trajectories for thermal cracking, coking, and
deasphalting were from Figures 8 and 10. The trajectory for diluent addition was from a
mass and volume balance, and for hydroconversion from published yield and density
data. Distillation is not a feasible technology because it gives less than 50% volume
yield, and residue fluid catalytic cracking and hydrocracking are not compatible with a
whole bitumen feed, therefore, these technologies are not represented.
The default option for a bitumen producer who does not have a full upgrader to
produce SCO is to add diluent to the bitumen and ship the product. Although this is not
a conversion technology, the trajectory for diluent addition is illustrated in Figure 11 for
reference. This option allows selling 100% of the bitumen product, plus the volume of
the purchased diluent; the diluent component in dilbit is sold at a discount to its
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purchase price. At the opposite extreme is solvent deasphalting, which removes the
denser asphaltenes and other components from the bitumen, but can only achieve pipeline density at the expense of removing approximately half the initial bitumen 82. Similarly, delayed coking gives densities higher than 940 kg/m3, but the volume yield is
reduced due to coke rejection from the process.
1040
Solvent deasphalting Diluent addition (Total volume) Delayed coking Thermal cracking Hydroconversion Pipelineable gravity
1020
Density, kg/m3
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1000
Athabasca bitumen 3 1016 kg/m
980 960 940 Maximum Pipeline Density
920 900 880 40
60
80
100
120
140
Yield, vol%
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Figure 11. Trajectories for Partial Upgrading Based on Established Process Technologies. Data are for Athabasca bitumen, and are approximate for illustration of trends in yield versus density of product 8, 38, 55.
The volume of bitumen can also be increased by catalytic reactions with hydrogen
gas, giving removal of the dense sulfur and nitrogen atoms, and net addition of
hydrogen. This trend is illustrated for hydroconversion in Figure 11. Other technologies
that are under development to remove sulfur atoms from the bitumen molecules
selectively, such as sodium metal desulfurization (Section 4.3.1), would follow a similar
trajectory to catalytic hydroconversion.
Although the vectors in Figure 11 show four technically feasible methods of achieving or
exceeding a pipelineable bitumen with a single reaction or separation approach, only
diluent addition is economically attractive for in situ producers. The other pathways of
deasphalting, delayed coking, and hydroconversion require too much capital investment
or result in too much loss of volume. Consequently, the main strategies under
development involve the use of more than one process step.
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6.1 Combinations of Processes If processes are combined, a larger feasible operating space will open to achieve the
desired pipeline specifications. Many combinations are possible, for example, thermal
cracking, addition of diluent, and deasphalting can be combined pairwise to meet
pipeline specifications for partially upgraded bitumen. Each of these combinations could
be illustrated as combinations of vectors from Figure 11, but this approach does not
illustrate the effect of different extents of processing. The possible operating space for
two- and three-way combinations of these processes is illustrated in Figure 12.
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deasphalting apex is the most extreme case, based on the data of Figure 10, for 50%
removal of the bitumen by solvent deasphalting. This approach is not economic, but it is
technically feasible. Similar to a ternary diagram for composition, at each apex only one
process step is used, in the central zone all three are combined, while on the edges
appear the pairwise combination of two technologies.
One zone of operation in the ternary space is not feasible for operation. Thermal
cracking at too high a severity generates unstable asphaltenes as illustrated in Figure 4.
Deasphalting can remove this material to give a stable product, but deasphalting has
not been operated below about 8-10% rejection of precipitated solid asphaltenes due to
the slow settling rate. The zone shown is white is not feasible for operation because of
these two limits. Zone A is where the combination of thermal cracking and diluent
addition will require the smallest volume of diluent, without any use of deasphalting.
Zone B is where the combination of thermal cracking and deasphalting will give the
highest liquid yield. Zone C is the feasible operating space for combinations of all three
technologies.
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The minimum limit on solid asphaltene rejection achieved in a commercial process
corresponds to precipitation of 8-10% of the bitumen, or 50-65% of the asphaltenes, as demonstrated in the paraffinic froth treatment process85. Rejection of less asphaltenes
is technically possible, as indicated in Figure 9, but has not been demonstrated in
commercial operation. Consequently, although operation in Zone D is theoretically
possible, it would likely require a new approach to removal of precipitated asphaltenes.
The schematic of Figure 12 shows two qualitative boundaries within the operating
space, but the exact position of these boundaries depends on the details of process
design. For example, the minimum limit for deasphalting could potentially be shifted by
using new technology for removal of precipitated asphaltenes, or by operating at higher
temperature. The boundary on the stability of asphaltenes in product from thermal
cracking will shift up or down depending on the details of the cracking process
conditions. The order of the processes is also important, so that thermal cracking followed by deasphalting will give different results than the reverse order86, and addition of a donor solvent diluent prior to thermal cracking can be beneficial39, 87, 88. Details of
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process operation are significant, so that time, temperature and the addition of donor
solvents can shift the boundary of phase stability of the reacted asphaltenes. All thermal
cracking-based technologies for bitumen have a limit of the type shown in Figure 12.
This diagram illustrates the potential domains of operation, but the preferred choice
will depend on the economics of the process, governed mainly by the liquid yield, the
value of the liquid product, and the capital and operating cost of the processes. Use of
two processes is preferred to three, due to the lower operating cost, and these choices
all lie on the edges of the diagram. Zones A is the most attractive range for a
combination of thermal cracking and diluent, while Zone B offers the highest liquid yield
without any use of diluent. Combinations of deasphalting and diluent, on the right-hand
edge, are less attractive for in situ producers because the total volume of bitumen sold
is reduced. In mining operations, the combination of partial deasphalting and diluent is
used to produce pipelineable bitumen that is free of emulsified water and solids, using
paraffinic froth treatment.
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An equivalent diagram can be drawn for the case of hydroconversion, which uses
thermal cracking in combination with hydrogen and a catalyst to suppress coke
formation and to maintain a compatible product over a wider range of conversion.
Although hydroconversion is attractive for liquid yield from the initial bitumen (see Figure
11), the high capital investment makes it an unattractive approach for partial upgrading of in situ bitumen production7.
7.
Research Needs
The commercial attractiveness of partial upgrading depends on the ability to improve the
properties of the crude bitumen to enable less use of diluent, while at the same time
minimizing the capital and operating expenses. New research in this area of technology
can contribute in three distinct ways. The first is to extend the range and selectivity of the
current process steps beyond the current limits. Thermal cracking gives reduction in
viscosity, but as discussed in section 4, these reactions generate less stable asphaltenes
and olefins in the distillate fractions. The ability to push the boundary on thermal cracking
by making the cracked asphaltenes more stable in the product crude oil and reducing
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Page 70 of 81
their tendency to cause fouling in downstream equipment would be a significant benefit.
Approaches to altering the molecular interactions of asphaltenes and resins, and the
attendant impact on viscosity would also enhance the benefits of thermal cracking. New
approaches to reducing olefin content, other than conventional hydrotreating, would
mitigate one of the undesirable side products of these reactions.
A second direction for research would be more selective separations of unwanted
components of the bitumen, beyond the current approach of using solvents for partial
deasphalting discussed in Section 5. Design of ionic liquids or other additives for selective
removal of metals, for disaggregation of asphaltene aggregates, or for selective removal
of some of the very large aromatic species could enable changing the composition of the
bitumen without rejecting as much volume. The recent work on imaging asphaltene molecular species89 emphasizes that bitumen contains components that are very
undesirable for clean fuels, but that might be attractive for carbon-based products.
Improved characterization of asphaltenes would help to define which structural
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components are difficult to convert to fuels, making them candidates for selective removal
or processing to non-fuel products
The third area of research is development of new pathways for conversion or reaction of
the vacuum residue fraction. Due to the high cost of processing with hydrogen gas,
catalytic processes were not discussed in Section 4 as current prospects for partial
upgrading. Alternate sources of hydrogen, such as methane or water, could be attractive
if the hydrogen could be made to react with bitumen at low cost. Novel catalysts could be
supported or unsupported nano-particles, but would need to meet the challenge of very
low cost for single use, or resistance to vanadium, nickel, and coke fouling for longer
times on stream.
8. Conclusions 1. Partial upgrading produces transportable bitumen or heavy oil with reduced use of
diluents. Feasible technologies must offer lower costs than conversion to synthetic crude
oil and high liquid yields.
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2. Reductions in viscosity and density to meet transport requirements require either
conversion of vacuum residue into lower-boiling components or removal of a portion of
the asphaltene.
3. Thermal cracking is a preferred process, but gives only a small change in density
unless coke is formed, which reduces the volumetric yield. The extent of thermal cracking
without coke formation is limited by the solubility of the reacted asphaltenes in the product
oil.
4. Established catalytic processes are not attractive due either to limited application to
vacuum residue or high cost.
5. Partial deasphalting can help to achieve reductions in viscosity and density, but cannot
by itself achieve targets for transportable product without a dramatic loss of volume.
6. Combinations of processes offer feasible options for partial upgrading, including
thermal cracking with reduced diluent addition and thermal cracking with partial
deasphalting.
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ACKNOWLEDGMENT
The author is grateful to Jinwen Chen, Tom Corscadden, John Gieseman, Damien
Hocking, Iftikhar Huq, Bill Keesom, Shunlan Liu, Robin Penner, Todd Pugsley, Scott
Smith, and Nestor Zerpa for their helpful comments and suggestions on the content of
this manuscript.
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