Fundamentals of Partial Upgrading of Bitumen

Subscriber access provided by BUFFALO STATE

Review

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

Just Accepted “Just Accepted” manuscripts have been peer-reviewed and accepted for publication. They are posted online prior to technical editing, formatting for publication and author proofing. The American Chemical Society provides “Just Accepted” as a service to the research community to expedite the dissemination of scientific material as soon as possible after acceptance. “Just Accepted” manuscripts appear in full in PDF format accompanied by an HTML abstract. “Just Accepted” manuscripts have been fully peer reviewed, but should not be considered the official version of record. They are citable by the Digital Object Identifier (DOI®). “Just Accepted” is an optional service offered to authors. Therefore, the “Just Accepted” Web site may not include all articles that will be published in the journal. After a manuscript is technically edited and formatted, it will be removed from the “Just Accepted” Web site and published as an ASAP article. Note that technical editing may introduce minor changes to the manuscript text and/or graphics which could affect content, and all legal disclaimers and ethical guidelines that apply to the journal pertain. ACS cannot be held responsible for errors or consequences arising from the use of information contained in these “Just Accepted” manuscripts.

is published by the American Chemical Society. 1155 Sixteenth Street N.W., Washington, DC 20036 Published by American Chemical Society. Copyright © American Chemical Society. However, no copyright claim is made to original U.S. Government works, or works produced by employees of any Commonwealth realm Crown government in the course of their duties.

Page 1 of 81 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

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

1

Energy & Fuels 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 2 of 81

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.


2

Page 3 of 81 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

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


3

Energy & Fuels 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 4 of 81

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


4

Page 5 of 81 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

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.


5

Energy & Fuels 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 6 of 81

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


6

Page 7 of 81 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

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.


7

Energy & Fuels 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 8 of 81

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.


8

Page 9 of 81 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


Energy & Fuels 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 10 of 81

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


10

Page 11 of 81 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

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.


11

Energy & Fuels 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 12 of 81

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)


12

Page 13 of 81 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

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.


13

Energy & Fuels 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 14 of 81

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


14

Page 15 of 81 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

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.


15

Energy & Fuels 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 16 of 81

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.


16

Page 17 of 81 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

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)


17

Energy & Fuels 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 18 of 81

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


18

Page 19 of 81 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

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


19

Energy & Fuels 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

Bitumen Component

Crude

Oil

Page 20 of 81

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


20

Page 21 of 81 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

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


21

Energy & Fuels 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 22 of 81

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,


22

Page 23 of 81 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

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,


23

Energy & Fuels 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 24 of 81

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


24

Page 25 of 81 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

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


25

Page 26 of 81

Energy & Fuels 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

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.


26

Page 27 of 81

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


27

Energy & Fuels 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 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


28

Page 29 of 81 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

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.


29

Energy & Fuels

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


30

Page 31 of 81 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

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.


31

Energy & Fuels 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 32 of 81

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.


32

Page 33 of 81 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

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


33

Energy & Fuels 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 34 of 81

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.


34

Page 35 of 81 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

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


35

Page 36 of 81

Energy & Fuels 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

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.


36

Page 37 of 81

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

Energy & Fuels

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.


37

Energy & Fuels

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


38

Page 39 of 81 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

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.


39

Energy & Fuels 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 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.


40

Page 41 of 81 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

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


41

Energy & Fuels 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 42 of 81

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.


42

Page 43 of 81 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

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.


43

Energy & Fuels 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

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.


44

Page 45 of 81

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

Energy & Fuels

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


45

Energy & Fuels 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 46 of 81

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


46

Page 47 of 81 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

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.


47

Energy & Fuels 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

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


48

Page 49 of 81 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

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


49

Energy & Fuels 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 50 of 81

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)


50

Page 51 of 81 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

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.


51

Energy & Fuels 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 52 of 81

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


52

Page 53 of 81 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

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


53

Energy & Fuels 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 54 of 81

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


54

Page 55 of 81 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

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


55

Energy & Fuels 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 56 of 81

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


56

Page 57 of 81 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

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


57

Energy & Fuels

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

Page 58 of 81

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.


58

Page 59 of 81 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

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.


59

Energy & Fuels

1040 Maximum Pipeline Density

1020

Density, kg/m3

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 60 of 81

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


60

Page 61 of 81 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

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


61

Energy & Fuels

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

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 62 of 81

1000

Athabasca bitumen 3 1016 kg/m

980 960 940 Maximum Pipeline Density

920 900 880 40

60

80

100

120

140

Yield, vol%


62

Page 63 of 81 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

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.


63

Energy & Fuels 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 64 of 81

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.


64

Page 65 of 81 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


Energy & Fuels 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 66 of 81

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.


66

Page 67 of 81 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

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


67

Energy & Fuels 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 68 of 81

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.


68

Page 69 of 81 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

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


69

Energy & Fuels 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 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


70

Page 71 of 81 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

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.


71

Energy & Fuels 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 72 of 81

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.


72

Page 73 of 81 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

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.


73

Energy & Fuels 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 74 of 81

REFERENCES

1.

Sanchez, A. F. P.; Sanchez, J. D. B.; Gonzalez, J. F. R.; Ramirez, L. E. M., The

pipeline transportation of heavy oil by using the dilution method: A practical apprach for modeling pressure drop and asphaltenes precipitation. Fuentes Reventon Energ. 2017, 15, (2), 7-17. 2.

Escojido, D. M.; Urribarri, O.; Gonzalez, J., Part 1: Transportation of Heavy

Crude Oil and Natural Bitumen. In 13th World Petroleum Congress, World Petroleum Congress: Buenos Aires, Argentina, 1991; p 8. 3.

New Technologies of Processing Inferior Heavy Oil; China National Petroleum

Corporation: Retrieved from https://docplayer.net/43682742-New-technologies-ofprocessing-inferior-heavy-oil.html July 2019, 2013. 4.

Gray, M. R., Upgrading Oilsands Bitumen and Heavy Oil. University of Alberta

Press: Edmonton, AB, 2015. 5.

Crude_Monitor crudemonitor.ca. [Online] http://www.crudemonitor.ca/.

(December 2017), 6.

Test Method for Determination of Olefin Content of Crude Oils, Condensates and

Diluents by 1H NMR; Maxxam Analytics Inc.: Retrieved from: http://www.ccqta.com//methods/Olefins%20in%20Crude%20Oil%202005.pdf, July 2019, 2005. 7.

Keesom, W.; Gieseman, J. Bitumen Partial Upgrading 2018 Whitepaper

AM0401A; Alberta Innovates: Calgary, AB, 2018; p pp. 152. 8.

Gray, M. R., New technique defines the limits of upgrading heavy oil, bitumens.

Oil Gas J. 2002, 100, (1), 50-54. 9.

ASTM, Annual Book of ASTM Standards. American Society for Testing and

Materials: Philadelphia, PA., 2017; Vol. 05.01 to 05.03. 10.

Yarranton, H. W.; Ortiz, D. P.; Barrera, D. M.; Baydak, E. N.; Barre, L.; Frot, D.;

Eyssautier, J.; Zeng, H.; Xu, Z.; Dechaine, G.; Becerra, M.; Shaw, J. M.; McKenna, A. M.; Mapolelo, M. M.; Bohne, C.; Yang, Z.; Oake, J., On the Size Distribution of SelfAssociated Asphaltenes. Energy Fuels 2013, 27, (9), 5083-5106.


74

Page 75 of 81 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

11.

McKenna, A. M.; Donald, L. J.; Fitzsimmons, J. E.; Juyal, P.; Spicer, V.;

Standing, K. G.; Marshall, A. G.; Rodgers, R. P., Heavy petroleum composition. 3. Asphaltene aggregation. Energy Fuels 2013, 27, (3), 1246-1256. 12.

Chacón-Patiño, M.; Rowland, S. M.; Rodgers, R. P., Advances in asphaltene

petroleomics. Part 1: Asphaltenes are composed of abundant island and archipelago structural motifs. Energy Fuels 2017, DOI: 10.1021/acs.energyfuels.7b02873. 13.

Wiehe, I. A., A phase separation kinetic model for coke formation. Ind. Eng.

Chem. Res. 1993, 32, 2447-2457. 14.

Wiehe, I. A.; Kennedy, R. J., The oil compatibility model and crude oil

incompatibility. Energy Fuels 2000, 14, 56–59. 15.

Wiehe, I. A., Process Chemistry of Petroleum Macromolecules. Vol. 121, CRC

Press: Boca Raton, FL, 2008; p 427. 16.

Pierre, C.; Barré, L.; Pina, A.; Moan, M., Composition and heavy oil rheology. Oil

Gas Sci. Technol. 2004, 59, (5), 489-501. 17.

Luo, P.; Gu, Y., Effects of asphaltene content on the heavy oil viscosity at

different temperatures. Fuel 2007, 86, 1069-1078. 18.

Lesueur, D., The colloidal structure of bitumen: Consequences on the rheology

and on the mechanisms of bitumen modification. Adv. Colloid Interface Sci. 2009, 145, 42-82. 19.

Seyer, F. A.; Gyte, C. W., Viscosity. In AOSTRA Technical Handbook on Oil

Sands, Bitumens, and Heavy Oils, Hepler, L. C.; Hsi, C., Eds. AOSTRA: Edmonton, AB, 1989; pp 155-184. 20.

Bazyleva, A. B.; Hasan, M. A.; Fulem, M.; Becerra, M.; Shaw, J. M., Bitumen and

heavy oil rheological properties: Reconciliation with viscosity measurements. J. Chem.

Eng. Data 2010, 55, 1389-1397. 21.

Zhang, M. Role of Bitumen Viscosity in Bitumen Recovery from Athabasca Oil

Sands. University of Alberta, Edmonton, AB, 2012. 22.

Barre, L.; Espinat, D.; Rosenberg, E.; Scarsella, M., Colloidal structure of heavy

crudes and asphaltene solutions. Rev. Inst. Fr. Pet. 1997, 52, (2), 161-175. 23.

Barre, L.; Simon, S.; Palermo, T., Solution properties of asphaltenes. Langmuir

2008, 24, (8), 3709-3717.


75

Energy & Fuels 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

24.

Page 76 of 81

Yarranton, H. W.; Satyro, M. A., Expanded Fluid-Based Viscosity Correlation for

Hydrocarbons. Ind. Eng. Chem. Res. 2009, 48, (7), 3640-3648. 25.

Topsøe, H.; Clausen, B. S.; Massoth, F. E., Hydrotreating Catalysis. Springer:

Berlin, 1996. 26.

Aoyagi, K.; McCaffrey, W. C.; Gray, M. R., Kinetics of hydrocracking and

hydrotreating of coker and oilsands gas oils. Pet. Sci. Technol. 2003, 21, 997-1015. 27.

Mills, G. A.; Boedeker, E. A.; Oblad, A. G., Chemical characterization of

catalysts. 1. Poisoning of cracking catalysts by nitrogen compounds and potassium ion.

J. Am. Chem. Soc. 1950, 72, 1554-1560. 28.

Dechaine, G. P.; Gray, M. R., Chemistry and association of vanadium

compounds in heavy oil and bitumen, and implications for their selective removal.

Energy Fuels 2010, 24, 2795-2808. 29.

Slavcheva, E.; Stone, B.; Turnbull, A., Review of naphthenic acid corrosion in oil

refining. Brit. Corr. J. 1999, 34, (2), 125-131. 30.

Smith, D. F.; Rodgers, R. P.; Rahimi, P.; Teclemariam, A.; Marshall, A. G., Effect

of Thermal Treatment on Acidic Organic Species from Athabasca Bitumen Heavy Vacuum Gas Oil, Analyzed by Negative-Ion Electrospray Fourier Transform Ion Cyclotron Resonance (FT-ICR) Mass Spectrometry. Energy Fuels 2009, 23, (1-2), 314319. 31.

Yepez, O., Influence of different sulfur compounds on corrosion due to

naphthenic acid. Fuel 2005, 84, 97–104. 32.

Yui, S. M., Removing diolefins from coker naphtha necessary before

hydrotreating. Oil Gas J. 1999, 97, (36), 64-68. 33.

Wilson, M. F.; Fisher, I. P.; Kriz, J. F., Cetane improvement of middle distillates

from Athabasca syncrudes by catalytic hydroprocessing. Ind. Eng. Chem. Prod. Res.

Dev. 1986, 25, 505-511. 34.

Gray, M. R.; Jokuty, P.; Yeniova, H.; Nazarewycz, L.; Wanke, S. E.; Achia, U.;

Krzywicki, A.; Sanford, E. C.; Sy, O. K. Y., The relationship between chemical structure and reactivity of Alberta bitumens. Can. J. Chem. Eng. 1991, 69, 833-843.


76

Page 77 of 81 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

35.

Chung, K. H.; Xu, S.; Gray, M. R.; Zhao, Y.; Kotlyar, L.; Sparks, B., The

chemistry, reactivity and processability of Athabasca bitumen pitch. Rev. Process

Chem. Eng. 1998, 1, 41-79. 36.

Gray, M. R.; McCaffrey, W. C., Role of chain reactions and olefin formation in

cracking, hydroconversion and coking of petroleum and bitumen fractions. Energy Fuels 2002, 16, 756-766. 37.

Nelson, W. L., Petroleum Refinery Engineering (4th Edition). McGraw-Hill: New

York, NY, 1958. 38.

Rahimi, P.; Parker, R. J.; Wiehe, I. A., Stability of visbroken products obtained

from Athabsca bitumen for pipeline transportation. Prepr. – Am. Chem. Soc. Div. Petrol.

Chem. 2001, 46(2), 95-98. 39.

Langer, A. W.; Stewart, J.; Thompson, C. E.; White, H. T.; Hill, R. M., Hydrogen

donor diluent visbreaking of residua. Ind. Eng. Chem. Process Des. Dev. 1962, 1, (4), 309-312. 40.

Alshareef, A. H.; Scherer, A.; Tan, X.; Azyat, K.; Stryker, J. M.; Tykwinski, R.;

Gray, M. R., Formation of archipelago structures during thermal cracking implicates a chemical mechanism for the formation of petroleum asphaltenes. Energy Fuels 2011, 25, 2130-2136. 41.

Ruchardt, C.; Gerst, M.; Nolke, M., Bimolecular formation of radicals by hydrogen

transfer. 1. The uncatalyzed transfer hydrogenation of alpha-methylstyrene by dihydroanthracene or xanthene - a radical reaction. Angew. Chem., Int. Ed. Engl 1992, 31, 1523-1525. 42.

Rahmani, S.; McCaffrey, W. C.; Gray, M. R., Kinetics of solvent interactions with

asphaltenes during coke formation. Energy Fuels 2002, 16, 148-154. 43.

Gould, K. A.; Wiehe, I. A., Natural hydrogen donors in petroleum resids. Energy

Fuels 2007, 21, (3), 1199-1204. 44.

Naghizada, N.; Prado, G. H. C.; de Klerk, A., Uncatalyzed hydrogen hransfer

during 100–250 °C conversion of asphaltenes. Energy Fuels 2017, 31, 6800–6811. 45.

Zachariah, A.; de Klerk, A., Thermal Conversion Regimes for Oilsands Bitumen.

Energy Fuels 2016, 30, (1), 239-248.


77

Energy & Fuels 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

46.

Page 78 of 81

Avid, B.; Sato, S.; Takanohashi, T.; Saito, I., Effect of n-pentane and n-heptane

insolubles on the pyrolysis of vacuum residue. Energy Fuels 2006, 20, (6), 2475-2477. 47.

Henderson, J. H.; Weber, L., Physical upgrading of heavy crude oils by the

application of heat. J. Can. Pet. Technol. 1965, 4, 206-212. 48.

Soskind, D. M.; Spektor, G. S.; D. F. Kasatkin, D. F.; Zenchenkova, M. G., Fluid

coking of heavy resids. Khim. Tekhnol. Topliv Masel 1982, 10, (October), 5-9. 49.

Brown, W., IyQ Upgrading at a 1 bbl/d scale. In 5th NCUT Upgrading and

Refining Conference, Edmonton, AB, 2009. 50.

O'Connor, P.; Verlaan, J. P. J.; Yanik, S. J., Challenges, catalyst technology and

catalytic solutions in resid FCC. Catal. Today 1998, 43, 305-313. 51.

McGehee, J., Solvent Deasphalting in Today's Deep Conversion Refinery. In

Refinery Processing and In-Plant Energy Conservation and Optimization, AICHE: Chicago Il., 2006. 52.

Habib, F.; Diner, C.; Stryker, J. M.; Semagina, N.; Gray, M. R., Suppression of

addition reactions during thermal cracking using hydrogen and sulfide catalyst. Energy

Fuels 2013, 27, 6637-6645. 53.

Sternberg, H. W.; Delle Donne, C. L.; Markby, R. E.; Friedman, S., Reaction of

sodium with dibenzothiophene - Method for desulfurization of residua. Ind. Eng. Chem.

Prod. Res. Dev. 1974, 13, 433-436. 54.

Verkade, J. G.; Yu, Z., Desulfurization of organosulfur compounds with lithium

and sodium. Energy Fuels 1999, 13, 23-28. 55.

Field_Upgrading In Desufurizing and Upgrading the Bottom of the Barrel, World

Heavy Oil Conference, Edmonton, AB, 2015; Edmonton, AB, 2015; pp WHOC15-[130]. 56.

Brons, G.; Myers, R. D.; Bearden Jr., R.; MacLeod, J. B. Process for

desulfurization of petroleum feeds utilizing sodium metal. US Patent 6,210,564, 2001. 57.

Fumoto, E.; Sugimoto, Y.; Sato, S.; Takanohashi, T., Catalytic Cracking of Heavy

Oil with Iron Oxide-based Catalysts Using Hydrogen and Oxygen Species from Steam.

J. Jpn. Pet. Inst 2015, 58, (5), 329-335. 58.

Fumoto, E.; Matsumura, A.; Sato, S.; Takanohashi, T., Recovery of Lighter Fuels

by Cracking Heavy Oil with Zirconia-Alumina-Iron Oxide Catalysts in a Steam Atmosphere. Energy Fuels 2009, 23, 1338-1341.


78

Page 79 of 81 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

59.

Fathi, M. M.; Pereira-Almao, P., Catalytic Aquaprocessing of Arab Light Vacuum

Residue via Short Space Times. Energy Fuels 2011, 25, (11), 4867-4877. 60.

Cheng, Z. M.; Ding, Y.; Zhao, L. Q.; Yuan, P. Q.; Yuan, W. K., Effects of

supercritical water in vacuum residue upgrading. Energy Fuels 2009, 23, 3178-3183. 61.

Vilcaez, J.; Watanabe, M.; Watanabe, N.; Kishita, A.; Adschiri, T., Hydrothermal

extractive upgrading of bitumen without coke formation. Fuel 2012, 102, 379-385. 62.

Watanabe, M.; Kato, S.; Ishizeki, S.; Inomata, H.; Smith, R. L., Heavy oil

upgrading in the presence of high density water: Basic study. J. Supercrit. Fluids 2010, 53, 48-52. 63.

Amani, M. J.; Gray, M. R.; Shaw, J. M., On Correlating Water Solubility in Ill-

defined Hydrocarbons. Fuel 2014, 134, 644-658. 64.

Dutta, R. P.; McCaffrey, W. C.; Gray, M. R.; Muehlenbachs, K., Thermal cracking

of Athabasca bitumen: Influence of steam on reaction chemistry. Energy Fuels 2000, 14, (3), 671-676. 65.

Soebianto, Y. S.; Katsumura, Y.; Ishigure, K.; Kubo, J.; Koizumi, T., Protection in

Radiolysis of N-Hexadecane .2. Radiolysis of n-Hexadecane in the Presence of Additives. Radiat. Phys. Chem. 1992, 40, (6), 451-459. 66.

Rahimi, P.; Fairbridge, C.; Tanner, D. D., The use of methane as a source of

higher hydrocarbons and hydrogen for upgrading heavy oils and bitumen Prepr. Pap. –

Am. Chem. Soc., Div. Fuel Chem. 1998, 43, (3), 476-480. 67.

Raseev, S., Thermal and Catalytic Processes in Petroleum Refining. Marcel

Dekker: New York, 2003. 68.

Duyvesteyn, W. P. C.; Salazar, J. A.; Ard, C. D. Systems and methods for

processing nozzle reactor pitch. WPO 2011046660 A1, 2011. 69.

Kostrov, S. A.; Bortkevitch, S. V.; Boldyrev, A. M.; Wooden, W. Method and

apparatus for treatment of crude oil or bitumen under auto-oscillation conditions for viscosity decrease. US Patent Application 20110005973A1, 2011. 70.

Chornet, M.; Chornet, E. Process for Treating Heavy Oils. Canadian Patent

2,814,773, 2008.


79

Energy & Fuels 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

71.

Page 80 of 81

Dawson, W. H.; Chornet, E.; Overend, R. P.; Chakma, A.; Lemonnier, J. P.

Process for reducing the viscosity of heavy hydrocarbon oils. US Patent 5,096,566 A, 1992. 72.

Thompson, L. H.; Doraiswamy, L. K., Sonochemistry: Science and engineering.

Ind. Eng. Chem. Res. 1999, 38, (4), 1215-1249. 73.

Suslick, K. S.; Gawienowski, J. J.; Schubert, P. F.; Wang, H. H., Alkane

sonochemistry. J. Phys. Chem. 1983, 87, (13), 2299-2301. 74.

Cataldo, F., Ultrasound-induced cracking and pyrolysis of some aromatic and

naphthenic hydrocarbons. Utrasonics Sonochem. 2000, 7, (1), 35-43. 75.

Kuijpers, M. W. A.; Iedema, P. D.; Kemmere, M. F.; Keurentjes, J. T. F., The

mechanism of cavitation-induced polymer scission; experimental and computational verification. Polymer 2004, 45, (19), 6461-6467. 76.

Bowman, R. D.; Davidson, N., Hydrodyamic shear breakage of DNA.

Biopolymers 1972, 11, (12), 2601-2624. 77.

Lu, B. C.-Y.; Fu, C.-T., Phase equilibria and PVT properties. In AOSTRA

Technical Handbook on Oil Sands, Bitumens, and Heavy Oils, Hepler, L. G.; Hsi, C., Eds. AOSTRA: Edmonton, AB, 1989; pp 131-151. 78.

Agrawal, P.; Schoeggl, F. F.; Satyro, M. A.; Taylor, S. D.; Yarranton, H. W.,

Measurement and modeling of the phase behavior of solvent diluted bitumens. Fluid

Phase Equilib. 2012, 334, 51-64. 79.

Moschopedis, S. E.; Speight, J. G., Effect of air blowing on properties and

constitution of natural bitumen. J. Mater. Sci. 1977, 12, (5), 990-998. 80.

Rankin, J.; Clickner, S.; Litz, K. E.; Lewis, L. N.; Queensbury, J.; Eric Kolibas, E.;

Hemberger, S.; Richardson, J.; Rossetti, M. Reaction system, methods and products therefrom. US Patent 9,828,557, Nov. 28, 2017. 81.

Diaz, O. C.; Sanchez-Lemus, M. C.; Schoeggl, F. F.; Satyro, M. A.; Taylor, S. D.;

Yarranton, H. W., Deep-Vacuum Fractionation of Heavy Oil and Bitumen, Part I: Apparatus and Standardized Procedure. Energy Fuels 2014, 28, (5), 2857-2865. 82.

Brons, G.; Yu, J. M., Solvent deasphalting effects on whole Cold Lake bitumen.

Energy Fuels 1995, 9, 641-647.


80

Page 81 of 81 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

83.

Mitchell, D. L.; Speight, J. G., The solubility of asphaltenes in hydrocarbon

solvents. Fuel 1973, 52, 149-152. 84.

Barton, A. F. M., CRC Handbook of Solubility Parameters and Other Cohesion

Parameters, Second Edition. CRC Press: Boca Raton, FL, 1991. 85.

Masliyah, J. H.; Xu, Z.; Dabros, M.; Czarnecki, J. A., Handbook on Theory and

Practice of Bitumen Recovery from Athabasca Oil Sands. Volume 2. Industrial Practice. Kingsley Knowledge Pub.: Cochrane, AB, 2013. 86.

Zachariah, A.; de Klerk, A., Partial Upgrading of Bitumen: Impact of Solvent

Deasphalting and Visbreaking Sequence. Energy Fuels 2017, 31, (9), 9374-9380. 87.

Maxa, D.; Sebor, G.; Blazek, J.; Kolar, M., Hydrogen-donor solvent visbreaking of

petroleum vacuum residue. Pet. Coal 2000, 42, (1), 52-55. 88.

Simpson, P. L.; Souhrada, F.; Fisher, I. P.; Woods, H. J., Gulf Canada donor

refined bitumen (DRB) process. Energy Prog. 1984, 4, (1), 59-63. 89.

Schuler, B.; Fatayer, S.; Meyer, G.; Rogel, E.; Moir, M.; Zhang, Y.; Harper, M. R.;

Pomerantz, A. E.; Bake, K. D.; Witt, M.; Peña, D.; Kushnerick, D.; Mullins, O. C.; Ovalles, C.; van den Berg, F. A. G.; Gross, L., Heavy Oil Based Mixtures of Different Origins and Treatments Studied by Atomic Force Microscopy. Energy Fuels 2017, 31, 6856–6861.


81

Fundamentals of Partial Upgrading of Bitumen

Recommend Documents