U.S. patent application number 14/573230 was filed with the patent office on 2015-11-26 for hydrocarbon products.
The applicant listed for this patent is AUTERRA, INC., CENOVUS ENERGY INC.. Invention is credited to Kyle E. Litz, Jonathan P. Rankin.
Application Number | 20150337220 14/573230 |
Document ID | / |
Family ID | 54555593 |
Filed Date | 2015-11-26 |
United States Patent
Application |
20150337220 |
Kind Code |
A1 |
Litz; Kyle E. ; et
al. |
November 26, 2015 |
HYDROCARBON PRODUCTS
Abstract
A hydrocarbon product having at least 0.1 grams per gram of
hydrocarbon product having a boiling range distribution from an
initial boiling point to approximately 739.degree. C. wherein the
hydrocarbon products are further characterized by an infrared
spectroscopy reference peak, centered between approximately 1445
cm.sup.-1 and 1465 cm.sup.-1, a first infrared spectroscopy peak
between approximately 1310 cm.sup.-1 and 1285 cm.sup.-1, wherein
the height of the first infrared spectroscopy peak is at least
approximately 28% of the height of the infrared spectroscopy
reference peak and a second infrared spectroscopy peak between
approximately 1135 cm.sup.-1 and 1110 cm.sup.-1, wherein the height
of the second infrared spectroscopy peak is at least approximately
22% of the height of the infrared spectroscopy reference peak.
Inventors: |
Litz; Kyle E.; (Ballston
Spa, NY) ; Rankin; Jonathan P.; (Galway, NY) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
AUTERRA, INC.
CENOVUS ENERGY INC. |
Schenectady
Calgary |
NY |
US
CA |
|
|
Family ID: |
54555593 |
Appl. No.: |
14/573230 |
Filed: |
December 17, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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14286342 |
May 23, 2014 |
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14573230 |
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Current U.S.
Class: |
208/15 ; 208/14;
208/18 |
Current CPC
Class: |
C10L 1/08 20130101; Y02E
50/10 20130101; C10L 2270/026 20130101; C10N 2020/02 20130101; C10L
2200/0446 20130101; C10M 101/02 20130101; C10N 2020/015 20200501;
C10N 2030/40 20200501; C10N 2030/52 20200501; Y02E 50/13 20130101;
C10M 2203/003 20130101; C10N 2030/43 20200501; C10G 2300/202
20130101; C10G 27/00 20130101; C10N 2030/70 20200501; C10G 19/00
20130101; C10G 27/12 20130101; C10L 1/04 20130101 |
International
Class: |
C10G 27/12 20060101
C10G027/12; C10M 101/02 20060101 C10M101/02; C10L 1/08 20060101
C10L001/08 |
Claims
1. A hydrocarbon product comprising: at least 0.1 grams per gram of
hydrocarbon product having a boiling point that is less than
739.degree. C.; at least 75 to 85 mass % carbon; at least 9 to 16
mass % hydrogen; and the hydrocarbon product exhibits an infrared
spectroscopy reference peak, centered between approximately 1445
cm.sup.-1 and 1465 cm.sup.-1, a first infrared spectroscopy peak
between approximately 1310 cm.sup.-1 and 1285 cm.sup.-1, and a
second infrared spectroscopy peak between approximately 1135
cm.sup.-1 and 1110 cm.sup.-1, wherein a height or area of the first
infrared spectroscopy peak is at least approximately 28% of a
height or area of the infrared spectroscopy reference peak and a
height or area of the second infrared spectroscopy peak is at least
approximately 22% of the height or area of the infrared
spectroscopy reference peak.
2. The hydrocarbon product of claim 1, having a sulfur content
measure between 17 mg/kg of the hydrocarbon product and 4.6 mass %
of the hydrocarbon product.
3. The hydrocarbon product of claim 1, having a nitrogen
concentration between approximately <0.1 to 2 mass % of the
hydrocarbon product.
4. The hydrocarbon product of claim 1, having a nitrogen
concentration per gram of hydrocarbon product between 40 to 10,000
.mu.g/g nitrogen.
5. The hydrocarbon product of claim 1, wherein the hydrocarbon
product has an acid dissociation constant in water larger than
1.times.10.sup.-9.
6. The hydrocarbon product of claim 1, wherein the hydrocarbon
product has a total acid number (TAN) between 0.1 mg/g KOH and 150
mg/g KOH.
7. The hydrocarbon product of claim 1, wherein the hydrocarbon
product has a total base number (TBN) greater than 300 mg
KOH/g.
8. The hydrocarbon product of claim 1 further comprising a
hydrocarbon component accounting for approximately 0.01 to 30 mass
% of the hydrocarbon product.
9. The hydrocarbon product of claim 8, wherein the hydrocarbon
component has a boiling point range up to 225.degree. C. and is a
parafin, iso-parafin, olefin, naphthanene, aromatic in naphtha or a
blending stock.
10. The hydrocarbon product of claim 1, wherein the hydrocarbon
product has an olefin content less comprising than 25 mass % of the
hydrocarbon product.
11. The hydrocarbon product of claim 1, having a kinematic
viscosity between 0.2 mm.sup.2/s and 300000 mm.sup.2/s.
12. The hydrocarbon product of claim 1, wherein the hydrocarbon
product further exhibits a third infrared spectroscopy peak between
approximately 1040 cm.sup.-1 and 1000 cm.sup.-1, wherein a height
or area of the third infrared spectroscopy peak is at least
approximately 22% of the height or area of the infrared
spectroscopy reference peak.
13. A hydrocarbon product comprising: at least 0.1 grams per gram
of the hydrocarbon product has a boiling point greater than
738.degree. C.; up to 0.1 mass % of the hydrocarbon product is
insoluble in pentane; and the hydrocarbon product exhibits an
infrared spectroscopy reference peak, centered between
approximately 1445 cm.sup.-1 and 1465 cm.sup.-1, a first infrared
spectroscopy peak between approximately 1310 cm.sup.-1 and 1285
cm.sup.-1, and a second infrared spectroscopy peak between
approximately 1135 cm.sup.-1 and 1110 cm.sup.-1, wherein a height
or area of the first infrared spectroscopy peak is at least
approximately 28% of a height or area of the infrared spectroscopy
reference peak and a height or area of the second infrared
spectroscopy peak is at least approximately 22% of the height or
area of the infrared spectroscopy reference peak.
14. The hydrocarbon product of claim 13, wherein the hydrocarbon
product is a liquid having a Reid vapor pressure of 101.325 kPa and
an API gravity greater than 10.
15. The hydrocarbon product of claim 13 further comprising a carbon
to hydrogen to sulfur ratio, having a carbon concentration of at
least 75 to 85 mass %, a hydrogen concentration of at least 9 to 16
mass % and a sulfur concentration of 17 mg/kg to 4.6 mass %.
16. The hydrocarbon product of claim 13, further comprises a
nitrogen concentration of approximately <0.1 to 2 mass %.
17. The hydrocarbon product of claim 13, further comprises a
nitrogen concentration range between 40 to 10,000 .mu.g/g
nitrogen.
18. The hydrocarbon product of claim 13, wherein the hydrocarbon
product has a kinematic viscosity at 37.8.degree. C. between 0.2
mm.sup.2/s and 300,000 mm.sup.2/s.
19. The hydrocarbon product of claim 13, wherein the hydrocarbon
product has an acid dissociation constant in water larger than
1.times.10.sup.-9.
20. The hydrocarbon product of claim 13, wherein the hydrocarbon
product has a total acid number (TAN) between 0.1 mg/g KOH and 150
mg/g KOH.
21. The hydrocarbon product of claim 13, wherein the hydrocarbon
product has a total base number (TBN) greater than 300 mg
KOH/g.
22. The hydrocarbon product of claim 13 further comprising a
hydrocarbon component accounting for approximately 0.01 to 30 mass
% of the hydrocarbon product.
23. The hydrocarbon product of claim 22, wherein the hydrocarbon
component has a boiling point range up to 225.degree. C. and is a
parafin, iso-parafin, olefin, naphthanene, aromatic in naphtha or a
blending stock.
24. The hydrocarbon product of claim 13, wherein the hydrocarbon
product has an olefin content less comprising than 25 mass % of the
hydrocarbon product.
25. The hydrocarbon product of claim 13, having a kinematic
viscosity between 0.2 mm.sup.2/s and 300,000 mm.sup.2/s.
26. The hydrocarbon product of claim 13, wherein the hydrocarbon
product further exhibits a third infrared spectroscopy peak between
approximately 1040 cm.sup.-1 and 1000 cm.sup.-1, wherein a height
or area of the third infrared spectroscopy peak is at least
approximately 22% of the height or area of the infrared
spectroscopy reference peak.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation-in-part application
claiming priority and benefit of U.S. patent application Ser. No.
14/286,342 filed May 23, 2014, entitled "HYDROCARBON PRODUCTS", the
content of which is incorporated herein by reference.
FIELD OF THE TECHNOLOGY
[0002] The following relates generally to a hydrocarbon product
having relatively low viscosity and low density while containing a
significant amount of residue and micro-carbon residue.
BACKGROUND
[0003] Crude oil contains heteroatoms such as sulfur, nitrogen,
nickel, vanadium and acidic oxygenates in quantities that
negatively impact the refinery processing of the crude oil
fractions. Light crude oils or condensates contain heteroatoms in
concentrations as low as 0.001 wt %. In contrast, heavy crude oils
contain heteroatoms as high as 5-7 Wt %. The heteroatom content of
crude oil increases with increasing boiling point and the
heteroatom content increases with decreasing API gravity. These
impurities must be removed during refining operations to meet the
environmental regulations for the final product specifications
(e.g., gasoline, diesel, fuel oil) or to prevent the contaminants
from decreasing catalyst activity, selectivity, and lifetime in
downstream refining operations. Contaminants such as sulfur,
nitrogen, trace metals, and total acid number (TAN) in the crude
oil fractions negatively impact these downstream processes,
including hydrotreating, hydrocracking and fluid catalytic cracking
(FCC) to name just a few. These contaminants are present in the
crude oil fractions in varying structures and concentrations.
[0004] Crudes that have one or more unsuitable properties that do
not allow the crudes to be economically transported, or processed
using conventional facilities, are commonly referred to as
"disadvantaged crudes." Disadvantaged crudes often contain
relatively high levels of residue. Such crudes tend to be difficult
and expensive to transport and/or process using conventional
facilities. High residue crudes may be treated at high temperatures
to convert the crude to coke. Alternatively, high residue crudes
are typically treated with water at high temperatures to produce
less viscous crudes and/or crude mixtures. During processing, water
removal from the less viscous crudes and/or crude mixtures may be
difficult using conventional means.
[0005] Disadvantaged crudes may include hydrogen deficient
hydrocarbons. When processing of hydrogen deficient hydrocarbons
using previously known methods, consistent quantities of hydrogen
are generally needed to be added, particularly if unsaturated
fragments resulting from cracking processes are produced.
Hydrogenation during processing, which typically involves the use
of an active hydrogenation catalyst, may be needed to inhibit
unsaturated fragments from forming coke. Hydrogen is costly to
produce and/or costly to transport to treatment facilities.
[0006] Coke may form and/or deposit on catalyst surfaces at a rapid
rate during processing of disadvantaged crudes. It may be costly to
regenerate the catalytic activity of a catalyst contaminated by
coke. High temperatures used during regeneration may also diminish
the activity of the catalyst and/or cause the catalyst to
deteriorate. Disadvantaged crudes may include acidic components
that contribute to the total acid number (TAN) of the crude feed.
Disadvantaged crudes with a relatively high TANs may contribute to
corrosion of metal components during transporting and/or processing
of the disadvantaged crudes. Removal of acidic components from
disadvantaged crudes may involve chemically neutralizing acidic
components with various bases. Alternately, corrosion-resistant
metals may be used in transportation equipment and/or processing
equipment. The use of corrosion-resistant metal often involves
significant expense, and thus, the use of corrosion-resistant metal
in existing equipment may not be desirable. Another method to
inhibit corrosion may involve addition of corrosion inhibitors to
disadvantaged crudes before transporting and/or processing of the
disadvantaged crudes. The use of corrosion inhibitors may
negatively affect equipment used to process the crudes and/or the
quality of products produced from the crudes. Disadvantaged crudes
may contain relatively high amounts of metal contaminants, for
example, nickel, vanadium, and/or iron. During processing of such
crudes, metal contaminants, and/or compounds of metal contaminants,
may deposit on a surface of the catalyst or the void volume of the
catalyst. Such deposits may cause a decline in the activity of the
catalyst.
[0007] Disadvantaged crudes often include organically bound
heteroatoms (for example, sulfur, oxygen, and nitrogen).
Organically bound heteroatoms may, in some situations, have an
adverse effect on catalysts. Alkali metal salts and/or
alkaline-earth metal salts have been used in processes for
desulfurization of residue. These processes tend to result in poor
desulfurization efficiency, production of oil insoluble sludge,
poor demetallization efficiency, formation of substantially
inseparable salt-oil mixtures, utilization of large quantities of
hydrogen gas, and/or relatively high hydrogen pressures.
[0008] Some processes for improving the quality of crude include
adding a diluent to disadvantaged crudes to lower the weight
percent of components contributing to the disadvantaged properties.
Adding diluent, however, generally increases costs of treating
disadvantaged crudes due to the costs of diluent and/or increased
costs to handle the disadvantaged crudes. Addition of diluent to
disadvantaged crude may, in some situations, decrease stability of
such crude.
[0009] Other processes for improving the quality of crude include
hydrocracking. Hydrocracking, however, generally has a high cost
associated with expensive catalysts and pressure vessels. In
addition, hydrocracking, under certain conditions, may also create
olefins. Olefins are unstable and may, in some situations, decrease
the stability of crude. Therefore, olefin-containing crudes may
require the addition of expensive additives to permit
transportation in pipelines. See U.S. Pat. No. 3,136,714 to Gibson
et al.; U.S. Pat. No. 3,558,747 to Gleim et al.; U.S. Pat. No.
3,847,797 to Pasternak et al.; U.S. Pat. No. 3,948,759 to King et
al.; U.S. Pat. No. 3,957,620 to Fukui et al.; U.S. Pat. No.
3,960,706 to McCollum et al.; U.S. Pat. No. 3,960,708 to McCollum
et al.; U.S. Pat. No. 4,119,528 to Baird, Jr. et al.; U.S. Pat. No.
4,127,470 to Baird, Jr. et al.; U.S. Pat. No. 4,224,140 to Fujimori
et al.; U.S. Pat. No. 4,437,980 to Heredy et al.; U.S. Pat. No.
4,591,426 to Krasuk et al.; U.S. Pat. No. 4,665,261 to Mazurek;
U.S. Pat. No. 5,064,523 to Kretschmar et al.; U.S. Pat. No.
5,166,118 to Kretschmar et al.; U.S. Pat. No. 5,288,681 to Gatsis;
U.S. Pat. No. 6,547,957 to Sudhakar et al.; U.S. Pat. No. 7,598,426
to Fang et al.; U.S. Pat. No. 7,648,625 to Bhan et al.; U.S. Pat.
No. 7,678,264 to Bhan; U.S. Pat. No. 7,749,374 to Bhan et al.; U.S.
Pat. No. 7,918,992 to Bhan; U.S. Pat. No. 8,088,706 to Domokos et
al.; U.S. Pat. No. 8,372,777 to Bhan et al.; U.S. Pat. No.
8,409,541 to Reynolds et al.; U.S. Pat. No. 8,450,538 to Bhan et
al.; U.S. Pat. No. 8,481,450 to Bhan; U.S. Pat. No. 8,492,599 to
Bhan et al.; U.S. Pat. No. 8,530,370 to Donaho et al.; U.S. Pat.
No. 8,562,817 to Milam et al.; U.S. Pat. No. 8,562,818 to Milam et
al.; U.S. Pat. No. 8,608,946; and U.S. Patent Application
Publication Nos. 20030000867 to Reynolds; 20030149317 to Rendina;
20060231456 to Bhan; 20060231457 to Bhan; 2006023476 to Bhan;
20070000810 to Bhan et al.; 20070295646 to Bhan et al.; 20080083650
to Bhan et al.; 20080087575 to Bhan et al.; 20080135449 to Bhan et
al.; 20090188836 to Bhan et al; 20100055005 to Bhan et al.;
20100098602 to Bhan et al.; 20110178346 to Milam et al.; and
20110192762 to Wellington et al, all of which are incorporated
herein by reference, describe various processes and systems used to
treat crudes. The process, systems, and catalysts described in
these patents, however, have limited applicability because of many
of the technical problems set forth above.
[0010] In sum, disadvantaged crudes generally have undesirable
properties, for example, relatively high residue, a tendency to
corrode equipment, and/or a tendency to consume relatively large
amounts of hydrogen during treatment. Other undesirable properties
include relatively high amounts of undesirable components including
relatively high TANs, organically bound heteroatoms, and/or metal
contaminants. Such properties tend to cause problems in
conventional transportation and/or treatment facilities, including
increased corrosion, decreased catalyst life, process plugging,
and/or increased usage of hydrogen during treatment. Thus, there is
a significant economic and technical need for improved systems,
methods, and/or catalysts for conversion of disadvantaged crudes,
and other hydrocarbons into hydrocarbon products and crude products
with properties that are more desirable.
SUMMARY OF THE TECHNOLOGY
[0011] A first embodiment of this disclosure relates generally to
hydrocarbon product comprising at least 0.1 grams per gram of
hydrocarbon product having a boiling point that is less than
739.degree. C., at least 75 to 85 mass % carbon, at least 9 to 16
mass % hydrogen; and the hydrocarbon product exhibits an infrared
spectroscopy reference peak, centered between approximately 1445
cm.sup.-1 and 1465 cm.sup.-1, a first infrared spectroscopy peak
between approximately 1310 cm.sup.-1 and 1285 cm.sup.-1, and a
second infrared spectroscopy peak between approximately 1135
cm.sup.-1 and 1110 cm.sup.-1, wherein a height or area of the first
infrared spectroscopy peak is at least approximately 28% of a
height or area of the infrared spectroscopy reference peak and a
height or area of the second infrared spectroscopy peak is at least
approximately 22% of the height or area of the infrared
spectroscopy reference peak.
[0012] A second embodiment of this disclosure relates generally to
a hydrocarbon product comprising at least 0.1 grams per gram of the
hydrocarbon product has a boiling point greater than 738.degree.
C., up to 0.1 mass % of the hydrocarbon product is insoluble in
pentane and the hydrocarbon product exhibits an infrared
spectroscopy reference peak, centered between approximately 1445
cm.sup.-1 and 1465 cm.sup.-1, a first infrared spectroscopy peak
between approximately 1310 cm.sup.-1 and 1285 cm.sup.-1, and a
second infrared spectroscopy peak between approximately 1135
cm.sup.-1 and 1110 cm.sup.-1, wherein a height or area of the first
infrared spectroscopy peak is at least approximately 28% of a
height or area of the infrared spectroscopy reference peak and a
height or area of the second infrared spectroscopy peak is at least
approximately 22% of the height or area of the infrared
spectroscopy reference peak.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] Some of the embodiments will be described in detail, with
reference to the following figures, wherein like designations
denote like members, wherein:
[0014] FIG. 1a depicts a flowchart describing an embodiment of a
method of oxidative desulfurization of a hydrocarbon feed.
[0015] FIG. 1b depicts a flowchart describing an embodiment of
treating a sulfone and/or sulfoxide rich hydrocarbon feed.
[0016] FIG. 2 depicts how the selectivity of a reaction between a
sulfone and/or sulfonate and caustic may be manipulated using an
alcoholysis reaction to form more desirable products using a
selectivity promoter.
[0017] FIG. 3 depicts multiple embodiments of an alcoholysis
reaction between a sulfone, caustic and selectivity promoter and
provides embodiments of the reaction products thereof.
[0018] FIG. 4 depicts an embodiment of a reaction mechanism for
forming a sulfonate intermediate from a sulfone substrate.
[0019] FIG. 5a depicts an embodiment of a biphasic reaction
mechanism for forming a hydrocarbon product and a sulfate salt.
[0020] FIG. 5b depicts an alternate embodiment of a biphasic
reaction mechanism, forming a hydrocarbon product and a bisulfite
salt.
[0021] FIG. 6a depicts a comparative graphical representation of
multiple embodiments of a simulated distillation (SIMDIS) of
multiple hydrocarbon feeds and their predicted boiling point
distributions.
[0022] FIG. 6b depicts a graphical representation of a SIMDIS of
the crude feed boiling point distribution provided in FIG. 6a.
[0023] FIG. 6c depicts a graphical representation of a SIMDIS of
the sulfoxidized crude oil boiling point distribution provided in
FIG. 6a.
[0024] FIG. 6d depicts a graphical representation of a SIMDIS of
the hydrocarbon products of the low heteroatom removal boiling
point distribution provided in FIG. 6a.
[0025] FIG. 6e depicts a graphical representation of a SIMDIS of
the hydrocarbon products of the mild heteroatom removal boiling
point distribution provided in FIG. 6a.
[0026] FIG. 6f depicts a graphical representation of a SIMDIS of
the hydrocarbon products of the moderate heteroatom removal boiling
point distribution provided in FIG. 6a.
[0027] FIG. 7a depicts a graphical representation of infrared
spectroscopy of one embodiment of a hydrocarbon feed.
[0028] FIG. 7b depicts a graphical representation of an infrared
spectroscopy of one embodiment of a sulfoxidized intermediate
hydrocarbon stream.
[0029] FIG. 7c depicts a graphical representation of an infrared
spectroscopy of one embodiment of a hydrocarbon product.
[0030] FIG. 7d depicts a graphical comparison of the infrared
spectroscopies of FIG. 7a and FIG. 7b.
[0031] FIG. 7e depicts a graphical comparison of infrared
spectroscopies of FIG. 7a and FIG. 7c.
[0032] FIG. 7f depicts a graphical comparison of infrared
spectroscopies of FIG. 7b and FIG. 7c.
DETAILED DESCRIPTION OF THE DISCLOSURE
[0033] A detailed description of the hereinafter described
embodiments of the disclosed apparatus and method are presented
herein by way of exemplification and not limitation with reference
to the Figures. Although certain embodiments are shown and
described in detail, it should be understood that various changes
and modifications may be made without departing from the scope of
the appended claims. The scope of the present disclosure will in no
way be limited to the number of constituting components, the
materials thereof, the shapes thereof, the relative arrangement
thereof, etc., and are disclosed simply as an example of
embodiments of the present disclosure.
[0034] As a preface to the detailed description, it should be noted
that, as used in this specification and the appended claims, the
singular forms "a", "an" and "the" include plural referents, unless
the context clearly dictates otherwise.
[0035] Certain embodiments are described in detail below. Terms
used herein may be defined as follows:
[0036] "ASTM" refers to American Standard Testing and
Materials.
[0037] "API gravity" refers to American Petroleum Institute gravity
("API gravity") at 15.5.degree. C. (approximately 60.degree. F.),
unless stated otherwise. API gravity may be determined by ASTM
Method D6822 or equivalent method. API gravity, is a measure of how
heavy or light a petroleum liquid is compared to water. If its API
gravity is greater than 10, it is lighter and floats on water; if
less than 10, it is heavier and sinks API gravity is thus an
inverse measure of the relative density of a petroleum liquid and
the density of water, but it is used to compare the relative
densities of petroleum liquids. For example, if one petroleum
liquid floats on another and is therefore less dense, it has a
greater API gravity. Although mathematically, API gravity has no
units, it is nevertheless referred to as being in "degrees" or
according to the ASTM, API gravity may also be described in units
of kg/m.sup.3. API gravity is typically gradated in degrees on a
hydrometer instrument. Methods for determining API may be
performed, using a glass thermohydrometer in conjunction with a
series of calculations, of the density, relative density, or API
gravity of crude petroleum, petroleum products, or mixtures of
petroleum and nonpetroleum products which may be handled as liquids
having a Reid vapor pressures of 101.325 kPa (14.696 psi) or less.
Values are determined at the existing temperatures and may be
corrected to 15.degree. C. or 60.degree. F.
[0038] The ratio of atomic hydrogen to atomic carbon present in a
hydrocarbon feed and the crude product may be determined by ASTM
Method D5291 or equivalent method. In some embodiments, the test
methods may be applicable to various hydrocarbons, including crude
oils, fuel oils, additives, lubricants and residues. The hydrogen
to carbon ratio may be tested in concentration ranges of at least
75 to 85 mass % for carbon and at least 9 to 16 mass % for
hydrogen. Embodiments employing certain methods for identifying the
hydrogen to carbon ratio may express the results as mass % carbon
and mass % hydrogen.
[0039] Boiling range distributions for the hydrocarbon feed, the
total product, and/or the crude product may be determined by ASTM
Method D5307, ASTM Method D7169 or equivalent method thereof,
unless otherwise mentioned.
[0040] "Biphasic" means a chemical system that contains two
separate and distinct immiscible chemical phases. These phases may
be any immiscible substances, including gas-liquid, gas-solid,
liquid-liquid and liquid-solid phases.
[0041] Boiling range distributions for hydrocarbons and hydrocarbon
containing material may be as determined by ASTM Method D5307, ASTM
Method D7169 or equivalent method. Some methods testing the boiling
range distribution of a water-free crude petroleum may determine
the boiling range through approximately 538.degree. C. In such an
embodiment, materials that boil above 538.degree. C. may be
reported as residue. In other embodiments of methods for
identifying the boiling range distribution, the method may
determine boiling point distribution and cut point intervals of
hydrocarbons such as crude oils and residues by using high
temperature gas chromatography. The method may extend the
applicability of simulated distillation to samples that do not
elute completely from chromatographic systems. In some methods, the
range for diesel boiling points may be identified using a method
that establishes a boiling point distribution range up through
720.degree. C. which may correspond to the elution of
C.sub.n-C.sub.100 hydrocarbon compounds. In some embodiments of the
methods, tests may use capillary columns with thin films, which
results in the incomplete separation of C.sub.4-C.sub.8 in the
presence of large amounts of carbon disulfide, and thus yields an
unreliable boiling point distribution corresponding to this elution
interval. In addition, quenching of the response of the detector
employed to hydrocarbons eluting during carbon disulfide elution,
may result in unreliable quantitative analysis of the boiling
distribution in the C.sub.4-C.sub.8 region. Since the detector may
not quantitatively measure the carbon disulfide, its subtraction
from the sample using a solvent-only injection and corrections to
this region via quenching factors, may result in an approximate
determination of the net chromatographic area. A separate, higher
resolution gas chromatograph (GC) analysis of the light end portion
of the sample may be performed in order to obtain a more accurate
description of the boiling point curve in the interval in question.
Some testing methods may be designed to obtain the boiling point
distribution of other incompletely eluting samples such as
atmospheric residues, vacuum residues, etc., that are characterized
by the fact that the sample components are resolved from the
solvent. The content of a particular boiling range may be
characterized by the grams of the hydrocarbon boiling within the
specific range per 1 gram of the total hydrocarbon mixture of a
hydrocarbon feed or hydrocarbon product. For example, if a
hydrocarbon product produces 0.3 g of hydrocarbon having a boiling
point within a range of 204-260.degree. C., per gram of hydrocarbon
product, means that for every gram of hydrocarbon product produced,
0.3 g of the hydrocarbon product includes hydrocarbons that boil
within the 204-260.degree. C. boiling point range.
[0042] "C.sub.5 asphaltenes" refers to asphaltenes that are
insoluble in n-pentane. C.sub.5 asphaltene content may be
determined by ASTM Method D2007 or equivalent thereof. Asphaltene
compositions of oil and other hydrocarbons may be included in
rubber compounds which may have a large effect on the
characteristics and uses of the compounds. Methods for determining
C5 asphaltenes may also be useful in the determination of other
components such as saturates, aromatics, and other polar compounds
present in oil but insoluable in pentane. In some embodiments, C5
asphaltenes and other components that are insoluable in pentane may
comprise up to 0.1 mass % of the hydrocarbon being measured,
including a hydrocarbon feed and hydrocarbon product.
[0043] "C.sub.7 asphaltenes" refers to asphaltenes that are
insoluble in n-heptane. C.sub.7 asphaltene content may be
determined by ASTM Method D3279. Some methods for quantifying C7
asphaltenes may be applicable to all solid and semi-solid petroleum
asphalts containing little or no mineral matter, gas oils, heavy
fuel oils, and crude petroleum that has been topped to a cut-point
of approximately 343.degree. C. or higher.
[0044] "Carbon to hydrogen ratio" (C/H ratio) refers to the ratio
of the amount of atomic carbon present in a substance compared with
the amount of atomic hydrogen present. For example a hydrocarbon
product having a C/H ratio of 1.5 parts carbon for every one part
hydrogen may have a C/H ratio of 1.5/1. Alternatively, the C/H
ratio may reduce the fraction where applicable. Using the previous
example, the C/H ratio may simply be referred to as a C/H ratio of
1.5, because 1.5 divided by 1 equals 1.5.
[0045] "Diesel" refers to hydrocarbons with a boiling range
distribution from approximately 250.degree. C. up to approximately
350.degree. C. as determined in accordance with ASTM Method D5307,
ASTM Method D7169 or equivalent method. Diesel content may be
determined by the quantity of hydrocarbons having a boiling range
between 250-350.degree. C. relative to the quantity of hydrocarbons
as measured by the boiling range distribution.
[0046] "Distillate" refers to hydrocarbons with a boiling range
distribution from approximately 200-350.degree. C. as determined by
ASTM Method D5307, ASTM Method 7169, or an equivalent method
thereof. Distillates may include diesel and kerosene.
[0047] "Gasolines" refers to hydrocarbons with a boiling range
distribution from approximately 40 to 250.degree. C. in accordance
with ASTM Method D5307, ASTM Method D7169 or equivalent method.
Gasoline hydrocarbons may be short carbon chains having
approximately 4-12 carbons per molecule. Gasoline content may be
determined by the quantity of hydrocarbons having a boiling range
between 40 to 250.degree. C. relative to the quantity of
hydrocarbons as measured by the boiling range distribution.
[0048] "Hydrogen to carbon ratio" (H/C) ratio is the reciprocal of
the C/H ratio. It refers to the amount of atomic hydrogen present
compared with the amount of atomic carbon present in a substance.
For example, using the C/H ratio above, the H/C ratio would be
1/1.5. The H/C ratio may also be simplified by reducing the
fraction to a decimal or whole number. For example, H/C ratio of
1/1.5 may simply be referred to as an H/C ratio of 0.67.
[0049] "Group X metal(s)" refers to one or more metals of a column
of the Periodic Table of Elements in which X corresponds to a
column number of the Periodic Table. For example, "group 4
metal(s)" refers to one or more metals from column 4 of the
Periodic Table (ex. Ti, Zr, Hf, Rf). A "metal" may refer to any
element of the periodic table residing in groups 1-12 (excluding
hydrogen) of the periodic table of elements, plus aluminum,
gallium, indium, thallium, tin, lead, bismuth and polonium.
[0050] "Group X element(s)" refers to one or more elements located
in a column on the Periodic Table of Elements, wherein X
corresponds to one or more column numbers recited (ex. columns
13-18). For example, a column 13 element may include B, Al, Ga, In,
Tl, and Uut.
[0051] "Contaminated hydrocarbon stream" is a mixture of
hydrocarbons containing heteroatom constituents.
[0052] "Content" refers to the weight of a component (for example
heteroatom content) in a substrate. An example of a substrate may
be a hydrocarbon feed, a reaction product and/or crude product. The
content may be expressed as a weight fraction or weight % (wt %)
which may be calculated as the
weight of the component total weight of the substrate .times. 100 =
wt % . ##EQU00001##
For example, "metal content" may be expressed as a weight percent
(wt %) wherein the metal content may be determined using the
formula:
weight of the metal in substrate total weight of the substrate
.times. 100 = wt % of metal content . ##EQU00002##
[0053] "Hydrocarbon(s)" refers to a substance that has primary
components of hydrogen and carbon. Hydrocarbons may include, but
are not limited to both saturate and unsaturated forms of aromatic
hydrocarbons, alkanes, alkenes, alkynes, aryls and
cycloalkanes.
[0054] "Hydrocarbon feed" refers to a feed that includes
hydrocarbons. The hydrocarbon feed may include, but is not limited
to, crudes, heavy or extra heavy crudes, crude oils containing
significant quantities of residue or pitch, bitumen, disadvantaged
crudes, contaminated hydrocarbon streams, hydrocarbons derived from
tar sands, shale oil, crude atmospheric residues, asphalts,
hydrocarbons derived from liquefying coal and hydrocarbons obtained
from a refinery process or mixtures thereof. The hydrocarbon feed
may include hydrocarbons and a mixture of one or more heteroatoms.
Common sulfur containing contaminants to a hydrocarbon feed may be
mercaptans, sulfides, disulfides, thiophenes, benzothiophenes,
dibenzothiophenes and benzo-naphthothiophenes.
[0055] "Initial boiling point" (IBP) refers to the point where
hydrocarbons or a mixture of hydrocarbons first begin to boil. The
initial boiling point may vary depending on the composition of the
mixture. Depending on the composition of hydrocarbons, the initial
boiling point of the hydrocarbons may range from less than
30.degree. C. up to approximately 739.degree. C. In some
embodiments, the IBP may be less than 30.degree. C., less than
50.degree. C., less than 70.degree. C., or less than 100.degree. C.
In other embodiments, the IBP may be between 30-50.degree. C. or 50
to 100.degree. C. In alternative embodiments, the IBP may be less
than 150.degree. C., less than 200.degree. C., less than
250.degree. C., less than 350.degree. C. or less than 450.degree.
C. The IBP may be between 150-250.degree. C., 250-350.degree. C. or
between 350-450.degree. C. Other embodiments containing high
quantities of hydrocarbons having longer chains, may have a IBP
between 450 to 750.degree. C. In some instances the IBP may be less
than 450.degree. C., less than 550.degree. C., less than
650.degree. C. or less than 750.degree. C. The IBP may be between
450-550.degree. C., 550-650.degree. C., 650-750.degree. C. or even
greater than 750.degree. C. in some embodiments, for example those
embodiments containing a higher quantity of bitumen or asphalt.
[0056] As the carbon chains of the crude oil fractions become
longer, the boiling point of the fraction may become higher, thus
as the composition contains short chained hydrocarbons, the initial
boiling point may decrease, whereas in a composition having less
short chained hydrocarbons, the initial boiling point may rise. For
example, a mixture of hydrocarbons including petroleum gas
fractions having a small alkanes between 1-4 carbon atoms per
molecule may have an initial boiling point of 40.degree. C. or
less. In a hydrocarbon mixture including naphtha, having a mixture
of hydrocarbons between 5-9 carbon atoms per molecule, the naphtha
portion may have a boiling point between 60-100.degree. C., wherein
the boiling point may be between 60-69.degree. C., 70-79.degree.
C., 80-89.degree. C. and/or 90-100.degree. C. In a hydrocarbon
mixture including gasoline hydrocarbons, such as alkanes and
cycloalkanes, having carbon chains between 4-12 atoms of carbon per
molecule, the gasoline fraction may have an boiling point between
approximately 30-250.degree. C., wherein the boiling point may be
between 40-59.degree. C., 60-79.degree. C., 80-99.degree. C.,
100-149.degree. C., 150-199.degree. C. and/or 200-250.degree. C. In
a hydrocarbon mixture including kerosene, the kerosene portion may
include alkanes having a carbon chain length between 10-18 carbon
atoms per molecule and/or aromatic hydrocarbons. The kerosene
fractions may have a boiling point between approximately
175-325.degree. C., wherein the boiling point may be
175-199.degree. C., 200-249.degree. C., 250-299.degree. C. and/or
300-325.degree. C.
[0057] Some hydrocarbon mixture may include a gas oil fraction
which may be used for diesel fuel and heating oil. The gas oil
fraction may include alkanes having 12 or more carbon atoms per
molecule. The gas oil fraction may have a boiling point between
250-350.degree. C. In some embodiments, the boiling point may be
250-274.degree. C., 275-299.degree. C., 300-324.degree. C. and/or
325-350.degree. C. Hydrocarbon products may include a lubricating
oil fraction, having long hydrocarbons between 20 to 50 carbon
atoms per molecule. The lubricating oil fraction may include
alkanes, cycloalkanes and aromatics and the lubricating oil
fractions may have a boiling point between 300-370.degree. C.,
wherein the boiling point may be between 300-324.degree. C.,
325-349.degree. C. and/or 350-370.degree. C. A hydrocarbon product
may also include in its mixture of hydrocarbons a heavy gas or fuel
oil fraction having long chains of carbon atoms between
approximately 20-70 carbon atoms per molecule. The heavy gas or
fuel oil fraction may have a boiling point between approximately
370-600.degree. C., wherein the boiling point may be between
370-399.degree. C., 400-449.degree. C., 450-499.degree. C.,
500-549.degree. C. and/or 550-600.degree. C.
[0058] "Kerosene" refers to hydrocarbons with a boiling point
distribution between approximately 175.degree.-325.degree. C. at a
pressure of 0.101 MPa. Kerosene content may be determined by the
quantity of hydrocarbons having a boiling range from 204.degree. C.
to 260.degree. C. at a pressure of 0.101 MPa relative to a total
quantity of hydrocarbons as measured by boiling range distribution
in accordance with ASTM Method D5307, ASTM Method D7169 or an
equivalent method thereof.
[0059] "Naphtha" refers to hydrocarbon components with a boiling
range distribution from approximately 38.degree. C. to 204.degree.
C. at a pressure of 0.101 MPa. Naphtha content may be determined by
the quantity of hydrocarbons having a boiling range relative to a
total quantity of hydrocarbons as measured by boiling range
distribution in accordance with ASTM Method D5307, ASTM Method
D7169 or equivalent method thereof.
[0060] The content of hydrocarbon components, for example parafins,
iso-parafins, olefins, naphthanenes and aromatics in naphtha may be
determined by ASTM Method D6730 or equivalent method. Methods for
identifying the hydrocarbon components may include chromatographic
operating conditions and column tuning processes to provide and
enhance the separation and subsequent determination of many
individual components that may not obtained with previous
single-column analyses. The column temperature program profile may
be selected to afford the maximum resolution of possible co-eluting
components, for example, where there are of two different compound
types (such as a paraffin and a naphthene). Some embodiments of
methods determining hydrocarbon components may determine
hydrocarbon components of spark-ignition engine fuels and their
mixtures containing oxygenate blends (MTBE, ETBE, ethanol, and so
forth) with boiling ranges up to 225.degree. C. Other light liquid
hydrocarbon mixtures typically encountered in petroleum refining
operations, such as blending stocks (naphthas, reformates,
alkylates, and so forth) may also be analyzed. Individual component
concentrations and precision may be determined for hydrocarbon and
hydrocarbon products having values in the range from 0.01 to
approximately 30 mass % or higher. Some embodiments of methods for
analyzing hydrocarbon components may be applicable to samples
containing less than 25 mass % of olefins. However, some
interfering co-elution with the olefins above C.sub.7 may occur,
particularly if blending hydrocarbon components or their higher
boiling cuts. Embodiments of methods determining hydrocarbon
components may further be applied to benzene, toluene and
oxygenated hydrocarbons, including oxygenated aromatics.
"n-Paraffin" refer to normal (straight chain) saturated
hydrocarbons. Parrafins may be a mixture of hydrocarbons. Each of
the hydrocarbons may contain between 10-16 carbons on average per
molecule, however the general formula for a paraffin may be
described as C.sub.nH.sub.2n+2, wherein n=1 to 400. Constituents of
paraffin may include n-dodecane, alkyl benzenes, and naphthalene
and its derivatives. Parrafins may have a boiling point range
between approximately 140-320.degree. C. or higher.
[0061] "Olefins" or "olefinic hydrocarbons" refer to hydrocarbon
compounds with non-aromatic carbon-carbon double bonds (e.g.
Alkene). Types of olefins may include, but are not limited to cis,
trans, internal, terminal, branched and linear.
[0062] "Periodic Table" refers to the Periodic Table as specified
by the International Union of Pure and Applied Chemistry
(IUPAC).
[0063] "STP" as used herein refers to standard temperature and
pressure, which is 25.degree. C. and 0.101 MPa.
[0064] "Liquid mixture" refers to a composition that includes one
or more compounds that are liquid at standard temperature and
pressure (25.degree. C., 0.101 MPa, hereinafter referred to as
"STP"), or a composition that includes a combination of one of more
compounds that are liquid at STP with one or more compounds that
are solids at STP.
[0065] "Organometallic" refers to compound that may include an
organic compound bonded or complexed with a metal of the Periodic
Table. "Organometallic content" refers to the total content of
metal in the organometallic compounds.
[0066] "Promoted caustic visbreaker" refers to a heated reactor
that contains a caustic and a selectivity promoter that react with
oxidized heteroatoms to remove sulfur, nickel, vanadium, iron and
other contaminants or heteroatoms, increase API gravity, decrease
viscosity, and decreases total acid number.
[0067] "Residue" or residual refers to a hydrocarbon that has a
boiling range distribution above 538.degree. C. (1000.degree. F.),
as determined by ASTM Method D5307, ASTM Method D7169, or an
equivalent method thereof. The residual portion of a hydrocarbon
mixture of a hydrocarbon product may include coke, asphalt, tar and
waxes. The hydrocarbon fraction may include multi-ringed structures
having a carbon chain of approximately 70 or more carbon atoms per
molecule. In some embodiments, residual portion of a hydrocarbon
mixture may have a boiling point greater than 538.degree. C.,
greater than 600.degree. C., greater than 700.degree. C., greater
than 800.degree. C., greater than 1000.degree. C., greater than
1200.degree. C., greater than 1500.degree. C., and/or greater than
1800.degree. C.
[0068] "Sulfoxidation" may refer to a reaction or conversion,
whether or not catalytic, that produces organo-sulfoxide,
organo-sulfone, organo-sulfonate, or organo-sulfonic acid compounds
(and/or mixtures thereof) from organosulfur compounds.
[0069] "TAN" refers to a total acid number expressed as milligrams
("mg") of KOH per gram ("g") of sample. TAN may be determined by
ASTM Method D664 or an equivalent method thereof. The TAN is a
measurement of acidity that is determined by the amount of
potassium hydroxide in milligrams that is needed to neutralize the
acids in one gram of oil. It is an important quality measurement of
crude oil. The TAN value indicates to the crude oil refinery the
potential of corrosion problems. It is usually the naphthenic acids
in the crude oil that causes corrosion problems. Methods for
determining the TAN value may include titrating acidic constituents
of hydrocarbons, and other petroleum products such as oxidation
products. The acid number may be the measure of the amount of
amount of an acidic substance in a hydrocarbon or hydrocarbon
product. In one method for evaluating the TAN, the hydrocarbon
products may be soluble or nearly soluble in mixtures of toluene
and propan-2-ol. This method may be applicable for the
determination of acids whose dissociation constants in water are
larger than 10.sup.-9. In this embodiment, salts may react if their
hydrolysis constants are larger than 10.sup.-9. The range of acid
numbers of hydrocarbons and hydrocarbon products may range between
0.1 mg/g KOH to 150 mg/g KOH. Methods for calculating TAN may be
used to indicate relative changes that occur in oil during use
under oxidizing conditions regardless of the color or other
properties of the resulting oil.
[0070] "Total base number (TBN)" is a measure of a petroleum
product's reserve alkalinity. It is measured in milligrams of
potassium hydroxide per gram (mg KOH/g). TBN determines how
effective the control of acids formed will be during the combustion
process. The higher the TBN, the more effective it is in suspending
wear-causing contaminants and reducing the corrosive effects of
acids and acidic byproducts over an extended period of time. TBN
may be determined using ASTM D2896 or an equivalent method thereof.
Embodiments of methods for calculating TBN may make a determination
of basic constituents in hydrocarbon products by titration with
perchloric acid in glacial acetic acid. The constituents that may
be considered to have basic characteristics include organic and
inorganic bases, amino compounds, salts of weak acids (soaps),
basic salts of polyacidic bases, and salts of heavy metals. In some
methods of embodiments for determining TBN, embodiments of
hydrocarbon and hydrocarbon products may be calculated to have a
base number greater than 300 mg KOH/g in some embodiments.
[0071] "Used catalyst" or "spent catalyst" refers to one or more
catalysts that have been contacted with a hydrocarbon feed. In some
embodiments, a used catalyst may be regenerated and re-contacted
with the hydrocarbon feed.
[0072] "VGO" refers to hydrocarbons with a boiling range
distribution between 343.degree. C. (650.degree. F.) and
538.degree. C. (1000.degree. F.) at 0.101 MPa. VGO content may be
determined by ASTM Method D5307, ASTM Method D7169 or equivalent
method thereof.
[0073] "Viscosity" refers to kinematic viscosity at 37.8.degree. C.
(100.degree. F.), unless otherwise indicated. Viscosity may be
determined using ASTM Methods D445, D2170, D2171 or equivalent
methods thereof. Method for determining kinematic viscosity, .nu.,
of liquid hydrocarbon products, which may be transparent or opaque,
may be performed by measuring the time it takes for a volume of
liquid to flow under gravity through a calibrated glass capillary
viscometer. In some methods, the dynamic viscosity .eta. may be
calculated by multiplying the kinematic viscosity, .nu., by the
density .rho. of the liquid hydrocarbon product. The value of a
kinematic viscosity may range from approximately 0.2 mm.sup.2/s to
300000 mm.sup.2/s. To calculate dynamic viscosity, the SI unit used
may be mPas, wherein 1 mm.sup.2/s=10.sup.-6 m.sup.2/s=1 cSt and 1
mPas=1 cP=0.001 Pas. Crudes may be produced and/or retorted from
hydrocarbon containing formations. Crudes may generally be a solid,
semi-solid, and/or liquid. Crudes may include crude oil. A crude
oil may be further stabilized. Stabilization of crudes may include
the removal of non-condensable gases, water, salts, or combinations
thereof from the crude. The resulting crude post-stabilization may
be referred to as stabilized crude. Stabilization may occur at, or
proximate to, the crude production site and/or at the site of
retorting.
[0074] Stabilized crudes may or may not have been distilled and/or
fractionally distilled in a treatment facility to produce multiple
components with specific boiling range distributions (for example,
naphtha, distillates, VGO, and/or lubricating oils). Distillation
includes, but is not limited to, atmospheric distillation methods
and/or vacuum distillation methods. Undistilled and/or
unfractionated stabilized crudes may include components that have a
carbon number above 4 in quantities of at least 0.5 grams of
components per gram of crude. Examples of stabilized crudes include
whole crudes, topped crudes, desalted crudes, desalted topped
crudes, or combinations thereof. "Topped" refers to a crude that
has been treated such that at least some of the components having a
boiling point below 35.degree. C. at 0.101 MPa (95.degree. F. at 1
atm) have been removed. Typically, topped crudes will have a
content of at most 0.1 grams, at most 0.05 grams, or at most 0.02
grams of such components per gram of the topped crude.
[0075] Some crudes may have one or more unsuitable properties that
render the crudes disadvantaged. The properties of a disadvantaged
crude may include a TAN of at least 0.1, at least 0.3, at least
0.5, at least 1.0 or at least 2.0; a viscosity of at least 10
centistokes (cSt); API gravity of at most 19, at most 15 or at most
10; a total heteroatom content of at least 0.005 grams of
heteroatom per gram of crude; a residue content of at least 0.01
grams of residue per gram of crude; a content of metals in metal
salts of organic acids of at least 0.0001 grams of metals per gram
of crude; or a combination of properties thereof. In some
embodiments the disadvantaged crude may also have an oxygen content
of at least 0.005 grams of oxygen per gram of disadvantaged crude
or a C.sub.7 asphaltene content of at least 0.04 grams of C.sub.7
per gram of the disadvantaged crude.
[0076] Embodiments of a disadvantaged crude may include at least
0.2 grams of residue, at least 0.3 grams of residue, at least 0.5
grams of residue, or at least 0.9 grams of residue per gram of
disadvantaged crude. Embodiments of a disadvantaged crude may have
a TAN in the range from 0.1 to 20, while in alternative
embodiments, the TAN may range from 0.3 to 10 or 0.4 to 5.
Disadvantaged crudes may also include a sulfur content of at least
0.005 grams per gram of disadvantaged crude.
[0077] Disadvantaged crudes may include at least 0.001 grams of
hydrocarbons per grams of disadvantaged crudes having a boiling
range distribution between 95.degree. C. and 200.degree. C. at
0.101 MPa; at least 0.001 grams of hydrocarbons per gram of
disadvantaged crude with a boiling range distribution between
200.degree. C. and 300.degree. C. at 0.101 MPa; at least 0.001
grams hydrocarbons per gram of crude with a boiling range
distribution between 300.degree. C. and 400.degree. C. at 0.101
MPa; and at least 0.001 grams of hydrocarbons per gram of
disadvantaged crude with a boiling range distribution between
400.degree. C. and 650.degree. C. at 0.101 MPa.
[0078] Examples of locations that may have disadvantaged crudes
that might be treated using the processes described herein include,
but are not limited to, crudes from the U.S. Gulf Coast and
southern California, Canadian Oil sands, Brazil's Santos and Campos
basins, Egyptian Gulf of Suez, Chad, United Kingdom North Sea,
Angola Offshore, Chinese Bohai Bay, Venezuelan Zulia, Malaysia, and
Indonesia Sumatra. Treatment of disadvantaged crudes using
oxidative desulfurization and heteroatom removal may enhance the
properties of the hydrocarbons present in crudes or disadvantaged
crudes. The resulting hydrocarbon products from the methods
described herein may make the crude products or disadvantaged
crudes products easier and economically more viable to transport
and or treat.
[0079] Referring to FIG. 1a, depicting an embodiment 100 of a
system and method of oxidative desulfurization 100 of a hydrocarbon
feed 101, hydrocarbon feed 101 may also be referred to as a
heteroatom-containing hydrocarbon feed, or a contaminated
hydrocarbon stream. Embodiments of the hydrocarbon feed 101 may
include any element in addition to the carbon and hydrogen of the
hydrocarbon. Heteroatoms contaminating the hydrocarbon feed may
include, but is not limited to compounds containing sulfur, oxygen,
nitrogen, nickel, vanadium, iron or other transition metals and
combinations of compounds thereof. The heteroatom containing
hydrocarbon feed may contain at least 15 weight parts per million
(wppm) vanadium and at least 5 wppm nickel. The heteroatom
containing hydrocarbon feed may also contain at least 0.20 Wt. %
sulfur, or at least 2 Wt. % sulfur, or at least 4 Wt. % sulfur; and
the hydrocarbon-containing feedstock may contain at least 0.01 Wt.
% nitrogen, or at least 0.4 Wt. % nitrogen.
[0080] In some embodiments, the content of the hydrocarbon feed may
be characterized by infrared spectroscopy. Embodiments of a
hydrocarbon feed tested using IR spectroscopy may exhibit one or
more characteristics at a specific wavelength or wavenumber in
comparison with a reference peak. Referring to embodiments depicted
in FIG. 7a, the hydrocarbon feed reference peak was exhibited
between approximately 1445 cm.sup.-1 and 1465 cm.sup.-1. The
reference peak may vary depending on the content of the hydrocarbon
feed. In some embodiments, the hydrocarbon feed may exhibit an
absorbance between 1310 cm.sup.-1 and 1285 cm.sup.-1 that is at
most approximately 28% of the height of the reference peak. In
alternative embodiments, the absorbance between 1310 cm.sup.-1 and
1285 cm.sup.-1 may be at most 25%, at most 20%, at most 15%, at
most 10% or at most 5% of the peak of the reference peak.
[0081] Embodiments of the hydrocarbon feed may also exhibit
specific characteristics under IR spectroscopy between the
wavelengths or wavenumbers or wavenumbers of approximately 1135
cm.sup.-1 and 1110 cm.sup.-1. For example, the embodiments of the
hydrocarbon feed may exhibit an absorbance peak between the
wavelengths or wavenumbers of 1135 cm.sup.-1 and 1110 cm.sup.-1
that may be at most approximately 22% of the height of the
reference peak. In alternative embodiments, the hydrocarbon feed
101 may exhibit a peak that is at approximately most 20%, at most
15%, at most 10% or at most 5% of the height of the reference
peak.
[0082] Some embodiments of the hydrocarbon feed may also exhibit
specific characteristics under IR spectroscopy between the
wavelengths or wavenumbers of approximately 1040 cm.sup.-1 and 1000
cm.sup.-1. For example, the embodiments of the hydrocarbon feed may
exhibit an absorbance peak between the wavelengths or wavenumbers
of 1040 cm.sup.-1 and 1000 cm.sup.-1 that may be at most
approximately 22% of the height of the reference peak. In
alternative embodiments, the hydrocarbon feed 101 may exhibit an IR
absorbance peak that is at most approximately 20%, at most 15%, at
most 10% or at most 5% of the height of the reference peak.
[0083] Referring again to FIG. 1a, the heteroatom-containing
hydrocarbon feed 101 may be combined with an oxidant 104 and
subjected to an oxidation reaction in a heteroatom oxidizer 102 or
an oxidizer vessel.
[0084] Embodiments of the oxidation step may be carried out using
at least one oxidant, optionally in the presence of a catalyst.
Suitable oxidants 104 may include organic peroxides,
hydroperoxides, hydrogen peroxide, O.sub.2, air, O.sub.3, peracetic
acid, organic hydroperoxides may include benzyl hydroperoxide,
ethylbenzene hydroperoxide, tert-butyl hydroperoxide, cumyl
hydroperoxide and mixtures thereof, other suitable oxidants may
include sodium hypochlorite, permanganate, biphasic hydrogen
peroxide with formic acid, nitrogen containing oxides (e.g. nitrous
oxide), and mixtures thereof, with or without additional inert
organic solvents.
[0085] In an alternative embodiment, the step of oxidation may
further include an acid treatment including at least one immiscible
acid. The immiscible acid and oxidant treatment may remove a
portion of the heteroatom contaminants from the feed, wherein upon
being oxidized by the immiscible acid and oxidant, the heteroatoms
may become soluble in the acid phase, and be subsequently removed
via a heteroatom containing by-product stream. The immiscible acid
used may be any acid which is insoluble in the hydrocarbon oil
phase. Suitable immiscible acids may include, but are not limited
to, carboxylic acids, sulfuric acid, hydrochloric acid, and
mixtures thereof, with or without varying amounts of water as a
diluent. Suitable carboxylic acids may include, but are not limited
to, formic acid, acetic acid, propionic acid, butyric acid, lactic
acid, benzoic acid, and the like, and mixtures thereof, with or
without varying amounts of water as a diluent.
[0086] In some embodiments, the oxidation reaction(s) may be
carried out at a temperature of approximately 20.degree. C. to
about 120.degree. C., at a pressure of about 0.1 atmospheres to
about 10 atmospheres, with a contact time of about 2 minutes to
about 180 minutes.
[0087] A catalyst may be used in the presence of the oxidant 104. A
suitable catalyst may include transition metals including but not
limited to Ti(IV), V(V), Mo(VI), W(VI), transition metal oxides,
including ZnO, Al.sub.2O.sub.3, CuO, layered double hydroxides such
as ZnAl.sub.2O.sub.4.x(ZnO)y(Al.sub.2O.sub.3), organometallic
complexes such as Cu.sub.xZn.sub.1-x Al.sub.2O.sub.4, zeolite,
Na.sub.2WO.sub.4, transition metal aluminates, metal alkoxides,
such as those represented by the formula M.sub.mO.sub.m(OR).sub.n,
and polymeric formulations thereof, where M is a transition metal
such as, for example, titanium, rhenium, tungsten, copper, iron,
zinc or other transition metals, R may be a carbon group having at
least 3 carbon atoms, where at each occurrence R may individually
be a substituted alkyl group containing at least one OH group, a
substituted cycloalkyl group containing at least one OH group, a
substituted cycloalkylalkyl group containing at least one OH group,
a substituted heterocyclyl group containing at least one OH group,
or a heterocyclylalkyl containing at least one OH group. The
subscripts m and n may each independently be integers between about
1 and about 8. In some embodiments, R may be substituted with
halogens such as F, Cl, Br, and I. For example, embodiments of the
metal alkoxide catalyst may include bis(glycerol)oxotitanium(IV)),
wherein M is Ti, m is 1, n is 2, and R is a glycerol group. Other
examples of metal alkoxides include bis(ethyleneglycol)oxotitanium
(IV), bis(erythritol)oxotitanium (IV), bis(sorbitol)oxotitanium
(IV).
[0088] The sulfoxidation catalyst may further be bound to a support
surface. The support surface may include an organic polymer or an
inorganic oxide. Suitable inorganic oxides include, but are not
limited to, oxides of elements of groups IB, II-A, II-B, III-A,
III-B, IV-A, IV-B, V-A, V-B, VI-B, of the Periodic Table of the
Elements. Examples of oxides that may be used as a support include
copper oxides, silicon dioxide, aluminum oxide, and/or mixed oxides
of copper, silicon and aluminum. Other suitable inorganic oxides
which may be used alone or in combination with the abovementioned
oxide supports may be, for example, MgO, ZrO.sub.2, TiO.sub.2, CaO
and/or mixtures thereof. Other supports may include talc.
[0089] The support materials used may have a specific surface area
in the range from 10 to 1000 m.sup.2/g, a pore volume in the range
from 0.1 to 5 ml/g and a mean particle size of from 0.1 to 10 cm.
Preference may be given to supports having a specific surface area
in the range from 0.5 to 500 m.sup.2/g, a pore volume in the range
from 0.5 to 3.5 ml/g and a mean particle size in the range from 0.5
to 3 cm. Particular preference may be given to supports having a
specific surface area in the range from 200 to 400 m.sup.2/g, and a
pore volume in the range from 0.8 to 3.0 ml/g.
[0090] Referring still to FIG. 1a, after subjecting a hydrocarbon
stream to oxidation conditions in the heteroatom oxidizer vessel
102, an intermediate stream 106 may be generated. A hydrocarbon
feed 101 containing, for example sulfur-based heteroatom
contaminants such as thiophenes, benzothiophenes, dibenzothiophenes
and thioethers and others may be converted to a sulfone or
sulfoxide rich intermediate stream 106. The intermediate
hydrocarbon stream 106 may include oxidized heteroatom containing
compounds and oxidant by-products. In some embodiments, the
intermediate stream 106 may be subjected to distillation 107, for
example in a distillation column. During distillation 107, the
oxidized heteroatom containing compounds, may be separated from the
oxidant by-products 109. The oxidant by-products may be recovered
and recycled. As a result of the distillation 107, an oxidized
hydrocarbon intermediate stream 111 may be formed including
oxidized heteroatom compounds such as sulfones and sulfoxide rich
hydrocarbons. The oxidized hydrocarbon intermediate stream 111 may
also be referred to as a sulfoxidized intermediate hydrocarbon
product. The sulfone and sulfoxide rich, sulfoxidized intermediate
hydrocarbon product 111 may be sent to a reactor vessel 108 such as
oil/caustic reactor vessel or promoted caustic visbreaker 108. In
some embodiments, the reactor vessel 108 may be a sulfone
management unit. Once inside the reactor vessel 108, the heteroatom
rich stream 111, which may include sulfones and/or sulfoxides, may
be subsequently reacted with a caustic treatment solution 110 in an
alcoholysis reaction, under biphasic conditions to produce a
hydrocarbon product and sulfate salts. The caustic treatment
solution may comprise caustic, a selectivity promoter and/or a
caustic selectivity promoter. FIG. 4 and FIG. 5 describe an
embodiment of a reaction mechanism for producing a hydrocarbon
product 120 and a sulfate salts 1040 under biphasic conditions
1000, 1010. In FIG. 4, the initial reaction may be a hydroxyl
attack on the C--S bond of the sulfur containing compound present
in in the sulfone/sulfoxide rich oxidized heteroatom containing
stream, such as in a dibenzothiophene sulfone depicted in FIG. 4.
As a result of the hydroxyl attack, a hydrocarbon containing a
sulfonate group may form as a reaction intermediate. Without being
bound to any particular theory, FIG. 5 provides one possible
explanation for the reaction mechanism.
[0091] Referring to FIG. 5, under the biphasic conditions of the
oil/caustic reactor vessel or promoted caustic visbreaker 108, one
of the phases may be a polar phase 1010 such as an organic alcohol,
other selectivity promoter or phase transfer agent. The other phase
may be a non-polar phase 1000, which may include non-polar oil or
hydrocarbon rich molecules. The boundary between the two phases is
delineated by a phase boundary 1020. The phase boundary may further
be a liquid-solid phase boundary. The intermediate sulfonate 1030,
may align its polar sulfonate group into the more preferable polar
phase 1010 while the aromatic hydrocarbon portion of the
intermediate 1030 prefers the non-polar phase 1000. Subsequently, a
hydroxyl group or other nucleophile present in the polar phase may
perform a nucleophilic attack on the Sulfur of the sulfonate group.
As a result of the nucleophilic attack, the sulfonate portion may
form a sulfate 1040, a good leaving group. The sulfate 1040 may
remain in the polar phase 1010 and the hydrocarbon left behind may
remain in the non-polar phase of an intermediate stream 114. The
separate phases allow for the hydrocarbon products 120 of the
non-polar phase to be removed and separated from the heteroatom
containing byproducts 116 such as sulfates in separating vessel
115. Without being bound to any particular mechanism, referring
again to FIG. 5, another possible mechanism may involve the
conversion of the starting sulfone to a sulfinate salt 1130, which
may also be aligned at a phase boundary 1020, between non-polar
phase 1000 and polar phase 1010. This may be followed by hydrolysis
of the sulfinate salt to form a bisulfite salt 1140 and a
hydrocarbon product.
[0092] In some instances, undesired side reactions may occur.
Referring to FIG. 2, it can be seen that in situations wherein the
sulfonate intermediate B may be attacked by the hydroxyl
nucleophile in the polar phase, the hydroxyl may perform a carbon
selective attack on the carbon, forming the C--O bond instead of
forming an S--O bond. In that instance, reaction (2) may occur
resulting in phenolic hydrocarbon products and a sulfite, instead
of the formation of the biphenyl and sulfate depicted by reaction
(3). Other oxide salts of sulfur may also be present (e.g.
thiosulfate, thiosulfite, etc).
[0093] Referring again to FIG. 1a, in some embodiments, the reactor
vessel 108 such as the oil/caustic reactor vessel or promoted
caustic visbreaker may be heated to an elevated temperature between
100.degree. C. and 500.degree. C. with a pressure between 0 and
1000 psi. Suitable caustic compounds 110 that may be used for the
alcoholysis reaction may be compounds which may exhibit basic
properties. Caustic compounds may include inorganic oxides having
group IA and HA metals, inorganic hydroxides including group IA and
HA elements, alkali metal sulfides, alkali earth metal sulfides,
mixtures and molten mixtures thereof. Non-limiting examples
include, but are not limited to, Li.sub.2O, Na.sub.2O, K.sub.2O,
Rb.sub.2O, Cs.sub.2O, Fr.sub.2O, BeO MgO, CaO, SrO, BaO, Na.sub.2S,
K.sub.2S, LiOH, NaOH, KOH, RbOH, CsOH, FrOH, Be(OH).sub.2,
Mg(OH).sub.2, Ca(OH).sub.2, Sr(OH).sub.2, Ba(OH).sub.2.
[0094] Caustic compounds may also include carbonate salts, such as
alkali metal carbonates and alkali earth metal carbonates including
Na.sub.2CO.sub.3, K.sub.2CO.sub.3, CaCO.sub.3, MgCO.sub.3 and
BaCO.sub.3; phosphate salts, including alkali metal phosphates,
such as sodium pyrophosphate, potassium pyrophosphate, sodium
tripolyphosphate and potassium tripolyphosphate; and alkali earth
metal phosphates, such as calcium pyrophosphate, magnesium
pyrophosphate, barium pyrophosphate, calcium tripolyphosphate,
magnesium tripolyphosphate and barium tripolyphosphate; silicate
salts, such as, alkali metal silicates, such as sodium silicate and
potassium silicate, and alkali earth metal silicates, such as
calcium silicate, magnesium silicate and barium silicate, organic
alkali compounds expressed by the general formula: R-E.sup.n
M.sup.mQ.sup.m-1, where R is hydrogen or an organic compound (which
may be further substituted) including, but not limited to,
straight, branched and cyclic alkyl groups; straight, branched and
cyclic alkenyl groups; and aromatic or polycyclic aromatic groups.
Further substituents where R is an organic may include hydroxide
groups, carbonyl groups, aldehyde groups, ether groups, carboxylic
acid and carboxylate groups, phenol or phenolate groups, alkoxide
groups, amine groups, imine groups, cyano groups, thiol or thiolate
groups, thioether groups, disulfide groups, sulfate groups, and
phosphate groups. E.sup.n- represents an atom with a negative
charge (where n=-1, -2, -3, -4 etc.) such as oxygen, sulfur,
selenium, tellurium, nitrogen, phosphorus, and carbon; and M.sup.m
is any cation (m=+1, +2, +3, +4 etc.), such as a metal ion,
including, but not limited to, alkali metals, such as Li, Na, and
K, alkali earth metals, such as Mg and Ca, and transition metals,
such as Zn, and Cu. When m>+1, Q may be the same as E.sup.n-R or
an atom with a negative charge such as Br--, Cl--, I, or an anionic
group that supports the charge balance of the cation M.sup.m,
including but not limited to, hydroxide, cyanide, cyanate, and
carboxylates.
[0095] In one embodiment of the present invention, the caustic may
also be in the molten phase. Molten phase caustics may include
previously mentioned caustics as well as eutectic mixtures thereof
of two or more caustics. The eutectic mixtures of molten caustics
may have a melting point less than 350.degree. C., such as, for
example, a 51 mole % NaOH/49 mole % KOH eutectic mixture which may
melt at about 170.degree. C.
[0096] Referring still to FIG. 1a, a selectivity promoter may be
introduced to the reactor vessel as part of the caustic treatment
solution 110. The selectivity promoter may be any compound capable
of being used in the alcoholysis reaction between the caustic and
an oxidized heteroatom containing hydrocarbon to generate biphasic
conditions that may promote the formation of non-oxygenated
hydrocarbon products 120 and sulfate salts. In some embodiments,
the selectivity promoter may also be referred to as a phase
transfer agent. Examples of heteroatom products may include
non-oxygenated hydrocarbon products 120 including, but not limited
to, unsubstituted biphenyl compounds, and aromatic hydrocarbons
shown in FIG. 3. The alcoholysis reaction examples provided in FIG.
3, disclose multiple embodiments wherein a caustic mixture of NaOH
and KOH may be used with an Na.sub.2S desulfonylation catalyst
nucleophile and ethylene glycol selectivity promoter. In the
exemplary embodiment, the reaction may take place over 60 minutes
at a pressure of 300 psi, at a temperature of approximately
275.degree. C. In other embodiments, other hydrocarbon distillates
and fractions that are non-oxygenated, may include, but not limited
to, non-oxygenated crude oils or crude oil derived products such as
gasolines, napthas, paraffins, olefins, asphaltenes/bitumens,
diesel and gas oils. The non-oxygenated products may depend on the
carbon groups of the heteroatom containing compounds present.
[0097] FIG. 2 further illustrates how the selectivity promoter and
the biphasic conditions may improve the alcoholysis reaction to
form more valuable products. Dibenzothiophene sulfone was chosen as
an exemplary sulfur compound because most of the challenging sulfur
to treat in diesel fuel is in the form of substituted or
unsubstituted dibenzothiophene. Equation (1) illustrates how
hydroxide attacks the sulfur atom of dibenzothiophene sulfone (A),
forming biphenyl-2-sulfonate (B). Equation (2) illustrates how
hydroxide may attack (B) at the carbon atom adjacent to the sulfur
atom, forming biphenyl-2-ol (C) and sulfite salts (D). Compound C
may ionize in basic media, and may dissolve in the aqueous or
molten salt layer. Equation (3) illustrates how hydroxide may
attack the sulfur atom of (B) to form biphenyl (E) and sulfate
salts (F). Equation (4) illustrates how, in the presence of a
primary alcohol, including, but not limited to, methanol, methoxide
ions generated in-situ may attack the carbon atom, forming ether
compounds, such as 2-methoxybiphenyl (G). Equation (5) illustrates
the reaction of dibenzothiophene sulfone with alkoxides alone, not
in the presence of hydroxide to form
biphenyl-2-methoxy-2'-sulfinate salt (H), which may be
substantially soluble in the polar caustic phase.
[0098] Using aqueous or molten caustic without the presently
disclosed selectivity promoter may cause reaction (1) to occur,
followed predominantly by reaction (2). When a selectivity promoter
disclosed herein is used, reaction (1) occurs, followed
predominantly by reaction (3). Without being confined to any
particular theory, it is believed that the biphasic conditions may
assist in promoting the selective nucleophilic attack at the
Sulfur. When the selectivity promoter (such as an alcohol)
disclosed herein is used, reaction (1) occurs, followed
predominantly by reaction (3) under biphasic conditions. It can be
seen that the hydrogen atoms that become attached to biphenyl may
come from hydroxide. When water is used in the regeneration of the
caustic, the ultimate source of the hydrogen atoms added to the
biphenyl may be water.
[0099] In some embodiments, the selectivity promoter may be
referred to by other names including polar protic solvent,
desulfonylation catalyst or phase transfer catalyst. Compounds
suitable for promoting substantially non-oxygenated hydrocarbon
reaction products may include organic alcohols, morpholine,
dioxane, dimethylethanolamine, methyldiethanolamine, mono
ethanolamine, diethanolamine, triethanolamine, crown ethers
(18-crown-6, 15-crown-5), piperazine, choline hydroxide,
benzyltrimethylammonium hydroxide, ethylene glycol, propylene
glycol, glycerin, sugars, starches, cellulose, diethylene glycol,
triethylene glycol, polyethylene glycol, sulfides, hydrosulfides,
polysulfides, hydroxide, cyanide, ammonia, anionic amides, halides,
acetates, naphthenates, alkoxides, selenides, hydroselenides,
tellurides, hydrotellurides, carboranes, phosphorous oxyanions,
nitrogen oxyanions, aluminates, borates, carbonates, chromates,
silicates, vanadates and titanates. Embodiments may include
introducing an excess molar ratio of selectivity promoters to
caustic cations for increased conversion and selectivity.
[0100] Referring again to FIG. 1a, in one embodiment the caustic
treatment solution 110 may include at least one caustic and the at
least one selectivity promoter. The at least one caustic and at
least one selectivity promoters may be different components. In
another embodiment, the at least one caustic and the at least one
selectivity promoter may be the same component. When the at least
one caustic and the at least one selectivity promoter are the same
component they may be referred to as a caustic selectivity
promoter. Moreover, a suitable caustic selectivity promoter may
possess the properties of both the at least one caustic and the at
least one selectivity promoter. That is, combinations of caustics
with selectivity promoters may react (in situ or a priori) to form
a caustic selectivity promoter which has the properties of both a
caustic and a selectivity promoter.
[0101] The molar ratio of caustic to selectivity promoter in the
caustic treatment solution 110 may be in the range of from about
100:1 to about 1:100. In some embodiments, the mole ratio of
caustic to selectivity promoter is in the range of from about
70:1-1:70, 50:1-1:50, 25:1-1:25, 1:10, 10:1, 1-5-5:1, 3:1 to about
1:3 or from about 2:1 to about 1:2.
[0102] Generally, the molar ratio of caustic and selectivity
promoter to heteroatom in the heteroatom-containing hydrocarbon
feed oil 111 may be in the range of from about 100:1 to about 1:1.
In some embodiments, the molar ratio of caustic and selectivity
promoter to heteroatom in the heteroatom-containing hydrocarbon
feed oil may be in the range of about 10:1 to about 1:1, and in
alternative embodiments, the molar ratio of caustic and selectivity
promoter to heteroatom in the heteroatom-containing hydrocarbon
feed oil may be from about 3:1 to about 1:1.
[0103] Referring still to embodiment 100 in FIG. 1a, the phases
resulting from the contact of the caustic treatment solution 110
with the oxidized heteroatom feed 111, may be separated into a
light phase containing the hydrocarbon products 120 and a dense
phase consisting of the caustic containing byproducts. The
intermediate 114 comprises a biphasic, caustic treated hydrocarbon
intermediate stream that may be transferred to a separating vessel
115, such as a gravity settler in some embodiments to separate the
hydrocarbon products 120 from the caustic by-products 116. The
hydrocarbon products 120 may be further washed, refined or utilized
for gas, oil, fuel, lubricants or other hydrocarbon based products
and further treated using known refinery processes. Separation of
the heavy caustic phase from the light oil phase may be performed
using gravity or other suitable separation methods. The hydrocarbon
product 120 may further be washed to remove traces of by-product
116 with known methods including, but not limited to, solvent
extraction or by washing with water, centrifugation, distillation,
vortex separation, and membrane separation and/or combinations
thereof. Trace quantities of caustic and selectivity promoter may
be removed using electrostatic desalting and dewater techniques
according to known methods by those skilled in the art.
[0104] Referring to alternative embodiment 200 in FIG. 1b, the
hydrocarbon feed 211 may already be rich in sulfones or sulfoxides
without having to oxidize the hydrocarbon feed or the hydrocarbon
feed may be pre-oxidized using other known methods in the art. The
hydrocarbon feed 211 may have properties similar to the sulfone or
sulfoxide rich intermediate stream 111 shown in FIG. 1a. In this
alternative embodiment, the steps of oxidation 102 may not be
needed. Instead, the sulfone or sulfoxide rich oil may be sent
directly from the source of the hydrocarbon feed 211 into the
oil/caustic reactor vessel 108. From the reactor vessel 108, a
caustic treatment solution 110 may be provided into reactor 108 to
form a biphasic mixture 114 of substantially non-oxygenated
hydrocarbon products 120 and caustic byproducts 116. The
hydrocarbon products 120 may settle in the light phase, while the
denser phase may contain caustic byproducts. The mixture 114 may be
separated in a settler vessel 115 or other vessel capable of
separating the light phase from the dense phase. Once separated,
the hydrocarbon products 120 may be used directly or transported,
refined or fractionally distilled into one or more distillate
fractions. The distillate fractions may be further processed to
produce hydrocarbon products such as gasoline, fuel oil, heating
oil, lubricants or other hydrocarbon based products.
[0105] The hydrocarbon product 120 may be a liquid at standard
temperature and pressure (STP). In some embodiments, the resulting
hydrocarbon product 120 may be a crude product wherein the crude
product is a liquid mixture at approximately 25.degree. C. and
0.101 MPa. In some embodiments the hydrocarbon product 120 may have
a TAN of at most 90% of the TAN of the hydrocarbon feed 101. In
other embodiments, the TAN of the hydrocarbon product 120 may have
a TAN of at most 80%, at most 60%, at most 50%, at most 40%, at
most 30% at most 20% or at most 10% of the hydrocarbon feed. In
certain embodiments, the hydrocarbon products may have a TAN of at
most 1, while in other embodiments, the TAN may range from at most
0.5, at most 0.3, at most 0.2 or at most 0.1 mg of KOH equivalent
per gram of oil. Embodiments of the hydrocarbon product 120 may
have a TAN that ranges. For example, the hydrocarbon may have a TAN
ranging from 0.001 to 0.5, 0.004 to 0.4 or from 0.01 to 0.2. In
certain embodiments, the hydrocarbon products may have a TAN
measuring less than 0.5 mg KOH equivalent per gram of the
hydrocarbon product.
[0106] In some embodiments, the hydrocarbon product 120 may include
a content of trace metallic heteroatoms such as Ni, V and Fe
wherein the content of the metallic heteroatoms may be at most 90%
of the metallic heteroatom content of the hydrocarbon feed. In
other embodiments, the metallic heteroatom content may be at most
80%, at most 70%, at most 60%, at most 50%, at most 30%, at most
10%, or at most 5% of the metallic heteroatom content of the
hydrocarbon feed 101. In certain embodiments, the hydrocarbon
product 120 may have a metallic heteroatom content per gram of
hydrocarbon product ranging from 1.times.10.sup.-7 g to
5.times.10.sup.-4 g or approximately 0.1 ppm to approximately 50
ppm.
[0107] In some embodiments, the crude product may have a total
content of metals in metal salts of organic acids of at most 90% of
the total content of metals in metal salts in organic acids of the
hydrocarbon feed. In other embodiments, the content of metals in
metal salts of organic acids may range from at most 50% to at most
5% of the content found in the hydrocarbon feed. Organic acids that
may form metal salts may include carboxylic acids such as napthenic
acids, phenanthrenic acids and benzoic acid. Other organic acids
that might form metal salts may include thiols, imides, sulfonic
acids and sulfonates. Metals that may form metal salts in organic
acids may include alkali metals, alkali earth metals, and
transition metals from groups 3-12 of the periodic table including
Ti, Zr, Zn, Cu, Ni and cadmium. Other metals that may form metal
salts may include metalloids (also called semi-metals) found in
group 13-16 of the periodic table include for example aluminum,
arsenic, boron and selenium. In one or more embodiments, the
hydrocarbon product 120 may have a total content of metals in metal
salts of organic acids, in the range from 0.0000001 g to 0.0005 g
per gram of hydrocarbon product.
[0108] In certain embodiments, the API gravity of the hydrocarbon
product 120 produced from the caustic treatment may be between 10
and 30. In other embodiments, the API gravity of the hydrocarbon
product may be increased by at least 3 units over the API gravity
of the hydrocarbon feed 101, at least 10 units over the API gravity
of the hydrocarbon feed or at least 15 units over the API gravity
of the hydrocarbon feed 101. In yet another embodiment, the API
gravity of the hydrocarbon product may be at least 12, at least 15,
at least 20 or at least 25.
[0109] Embodiments of the hydrocarbon products 120 may have a
viscosity less than the viscosity of the hydrocarbon feed. For
example, in some embodiments, the viscosity may be at most 90% of
the viscosity of the hydrocarbon feed 101. In other embodiments,
the viscosity of the hydrocarbon product may be at most 80% or at
most 70% of the hydrocarbon feed. Embodiments of the hydrocarbon
product 120 may also have a total heteroatom content that is at
most 90% of the total heteroatom content of the hydrocarbon feed.
In certain embodiments, the hydrocarbon products may contain at
most 50%, at most 10% or at most 5% of the heteroatom content of
the hydrocarbon feed 101. In some embodiments, the viscosity of the
hydrocarbon composition may be measured by a stabinger
viscometer.
[0110] Embodiments of the hydrocarbon product 120 may have a sulfur
content that may be at most 95% of the hydrocarbon feed. In other
embodiments, the sulfur content may be at most 50%, at most 10% or
at most 5% of the sulfur content of the hydrocarbon feed. In one or
more embodiments, the sulfur content of the hydrocarbon product 120
may be less than approximately 4.0 wt % of the hydrocarbon product.
The wt % of the sulfur content may be measured by ASTM D4294 or
equivalent methods. Methods for measuring the wt % of sulfur
content may provide a rapid and precise measurement of total sulfur
in the hydrocarbon feed or hydrocarbon product and it may be
performed in an analysis time between 1 to 5 minutes per sample.
Methods for identifying the total sulfur may be applied to
hydrocarbons, including diesel, jet fuel, kerosene, distillates,
naphtha, residues, lubricating oil, crude oil, gasoline, gasohol
and biodiesel, wherein the hydrocarbons may be liquid at an ambient
condition, liquefiable with moderate heat, or soluble in
hydrocarbon solvents. Methods identifying sulfur content may
further be applied to oxygenated fuels with high oxygen content
(>3%) by diluting the samples. In some embodiments, the method
may be performed on hydrocarbon or hydrocarbon product samples
having 17 mg/kg to 4.6 mass % sulfur present. Embodiments of the
method for determining sulfur content may have a pooled limit of
quantitation (PLOD) is 16.0 mg/kg as calculated in accordance with
ASTM D6259 or an equivalent method. In some embodiments, samples of
the hydrocarbon feed or hydrocarbon product containing a mass % of
sulfur greater than 4.6 mass % may be diluted to less than 4.6 mass
%.
[0111] In some embodiments the hydrocarbon products may contain per
gram of hydrocarbon product, at least 0.0005 gram of sulfur or at
least 0.001 gram of sulfur. The sulfur content of the hydrocarbon
composition may be determined in accordance with ASTM Method D4294.
A substantial portion of the sulfur in the hydrocarbon composition
may be contained in hydrocarbons having a carbon number of 17 or
less, Where at least 40 Wt. %, or at least 50 Wt. %, or at least 60
Wt. %, or at least 70 Wt. % of the sulfur may be contained in
hydrocarbons having a carbon number of 17 or less, Where at least
60 Wt. %, or at least 70 Wt. %, or at least 75 Wt. % of the sulfur
contained in hydrocarbons having a carbon number of 17 or less may
be contained in benzothiophenic compounds. The amount of sulfur in
hydrocarbons having a carbon number of 17 or less and the amount of
sulfur in benzothiophenic compounds in the hydrocarbon composition
relative to all sulfur containing compounds in the hydrocarbon
composition may be determined by two dimensional gas chromatography
(GCxGC-SCD).
[0112] In some embodiments, the total of the hydrocarbon product
120 may be at most 90% of the hydrocarbon feed. In other
embodiments, the nitrogen content may be at most 50%, at most 10%
or at most 5% of the nitrogen content of the hydrocarbon feed 101.
In one or more embodiments, the nitrogen content of the hydrocarbon
product 120 may be less than approximately 0.2 wt % of the
hydrocarbon product. The wt % of nitrogen content may be measured
by ASTM D5291 or equivalent methods. Embodiments of the method for
measuring the total nitrogen content may be performed on a
hydrocarbon feed or hydrocarbon product having a concentration of
approximately <0.1 to 2 mass % nitrogen.
[0113] In some embodiments, the nitrogen content may contain, per
gram of hydrocarbon product, at least 0.0005 gram or at least 0.001
gram of nitrogen as determined in accordance with ASTM Method
D5762. Embodiments of hydrocarbons and hydrocarbon products may be
tested and demonstrated to include a nitrogen concentration per
gram of liquid hydrocarbon. In some embodiments, the nitrogen
content of hydrocarbon streams or feeds and hydrocarbon products
may be in the concentration range of 40 to 10,000 .mu.g/g nitrogen.
The hydrocarbon product may have a relatively low ratio of basic
nitrogen compounds to other nitrogen containing compounds. In some
embodiments, at least 30 Wt. % of the nitrogen is contained in
hydrocarbon compounds having a carbon number of 17 or less, and at
least 35 Wt. % or at least 40 Wt. % of the nitrogen may be
contained in hydrocarbon compounds having a carbon number of 17 or
less.
[0114] In some embodiments, the oxygen content of the hydrocarbon
product may be at most 90% of the hydrocarbon feed. In other
embodiments, the oxygen content may be at most 50%, at most 30%, at
most 10% or at most 5% of the oxygen content of the hydrocarbon
feed. In certain embodiments, the oxygen content may be less than
approximately 1.2 wt % of the hydrocarbon product.
[0115] In some embodiments, the hydrocarbon product may include
from approximately 0.05-0.15 grams of hydrogen per gram of
hydrocarbon product 120. The hydrocarbon product may include in its
molecular structure 0.8 to 0.9 grams of carbon per gram of
hydrocarbon product. The hydrocarbon product may have a ratio of
atomic carbon to atomic hydrogen (C/H) within 70-130% of the
hydrocarbon feed. In an exemplary embodiment, the C/H ratio of the
hydrocarbon product may be .gtoreq.90% of the hydrocarbon feed.
Embodiments of a hydrocarbon product may have a hydrogen to carbon
ratio of the hydrocarbon less than or equal to 1.7:1 in some
embodiments. In other embodiments, the H/C ratio may be between
approximately 0.01:1 to 0.09:1, between 0.1:1 to 0.49:1, between
0.50:1 to 1:1 and/or between 1:1 to 1.7:1. Accordingly, in some
embodiments, the H/C ratio may be less than 1:100, less than 1:75,
less than 1:50, less than 1:30, less than 1:20 or less than
1:10.
[0116] In some embodiments, the hydrocarbon product 120 may be
amenable to additional refinery operations and treatments,
including but not limited to distillation, hydrotreating,
alkylation, hydrocracking, fluid catalytic cracking, coking, and
visbreaking.
[0117] In some embodiments, the hydrocarbon products may be
hydro-treated to adjust the H/C or C/H ratio of the hydrocarbon
products and/or decrease the sulfur content of the hydrocarbon
products. A hydrocarbon product with a C/H ratio within 10-30% of
the hydrocarbon feed may indicate that the uptake or consumption of
hydrogen was relatively small and/or that the hydrogen was produced
in situ. In some embodiments, the hydrocarbon product with a low
C/H ratio may be sent to a refinery for further processing wherein
the refinery may modify the C/H ratio by increasing the hydrogen
content as needed in the formation of the refined product. In such
an embodiment, the oil producers may save money by avoiding the
addition of costly hydrogen processing, while still being able to
economically transport the oxidized hydrocarbon products.
[0118] Referring to FIG. 6a-6f, which depicts various boiling point
distributions for hydrocarbon feeds such as crude bitumen,
sulfoxidized intermediates 111 of the hydrocarbon feed and the
boiling point of distributions of various hydrocarbon products
based on the amount of heteroatom removal that has occurred. For
example, the hydrocarbon products 120 may contain VGO hydrocarbons,
distillate hydrocarbons (kerosene and diesel), naphtha hydrocarbons
and residual hydrocarbons (asphalt and bitumen). The hydrocarbon
composition may contain, per gram of hydrocarbon composition, at
least 0.1 grams of hydrocarbons having a boiling point from the
initial boiling point (IBP) of the hydrocarbon composition up to
204.degree. C. (400.degree. F.). The hydrocarbon composition may
also contain, per gram of hydrocarbon composition, at least 0.15
grams of hydrocarbons having a boiling point from 204.degree. C. up
to 260.degree. C. The hydrocarbon composition may also contain, per
gram of hydrocarbon composition, at least 0.3 grams, or at least
0.35 grams of hydrocarbons having a boiling point of from
260.degree. C. up to 343.degree. C. The hydrocarbon composition may
also contain, per gram of hydrocarbon composition, at least 0.35
grams, or at least 0.4 grams, or at least 0.45 grams of
hydrocarbons having a boiling point of from 343.degree. C. up to
538.degree. C. The relative amounts of hydrocarbons within each
boiling range and the boiling range distribution of the
hydrocarbons may be determined in accordance with ASTM Method
D5307, ASTM Method D7169 or an equivalent method thereof.
[0119] Referring still to FIG. 6a-6f, the hydrocarbon product 120
may include hydrocarbons within one or more ranges of boiling
points. In some embodiments, the hydrocarbon product may include at
least 0.1 g of hydrocarbons per gram of hydrocarbon product having
a boiling range distribution between the initial boiling point and
739.degree. C. In other embodiments, the hydrocarbon product may
have approximately at least 0.2 g, at least 0.3 g, at least 0.4 g,
at least 0.5 g, at least 0.8 g, at least 0.9 g of hydrocarbons per
gram of hydrocarbon product having a boiling range distribution
between the IBP and the 739.degree. C.
[0120] In some embodiments, the hydrocarbon product may include at
least 0.05 grams of hydrocarbons per gram of hydrocarbon product
120 having a boiling range distribution from the initial boiling
point of the hydrocarbon product to 67.degree. C. The initial
boiling point may be the temperature wherein a hydrocarbon or
mixture of hydrocarbons first begins to boil. The IBP may vary
depending on the composition of hydrocarbons present. For example,
a hydrocarbon product including a high gasoline hydrocarbon content
having short chain hydrocarbons between 4-12 carbons per molecule
will begin to boil at a much lower temperature than a mixture of
hydrocarbons lacking gasoline. For example, a hydrocarbon product
with a high concentration of gasolines may have an initial boiling
point of less than 70.degree. C., whereas a hydrocarbon product
including a higher concentration of gas oil or diesel and a lower
concentration of gasolines may have a higher initial boiling point
around 120-150.degree. C. In an embodiment including few gasolines
and a lower concentration of gas oil or diesel, and instead having
a higher concentration of lubricating oils, the hydrocarbon product
may have an IBP of approximately 150-300.degree. C. In comparison,
a hydrocarbon product having a high concentration of fuel oil
fractions but still having a fair amount of naphtha and gasoline
may still have a lower IBP because the naphtha and gasoline may
begin to boil at temperature between 40-200.degree. C. In a
hydrocarbon product that is predominantly lubricating oil, heavy
gas and residual products, the hydrocarbon mixture may have a much
higher IBP than the previous examples, for instance between
275.degree. C.-450.degree. C.
[0121] In some embodiments, the hydrocarbon product 120 may include
0.01 to 0.25 grams of hydrocarbon per gram of hydrocarbon product
having a boiling range distribution between the IBP of the
hydrocarbon products and 204.degree. C. In another embodiment, the
hydrocarbon product may include at least 0.1 gram of hydrocarbons
per gram of hydrocarbon product having a boiling range distribution
from the IBP to 253.degree. C. In other embodiments, the
hydrocarbon product may include at least 0.4 g of hydrocarbons per
gram of hydrocarbon product having a boiling range distribution
between IBP of the hydrocarbon product to approximately 538.degree.
C.
[0122] Additional embodiments of the hydrocarbon product 120 may
include at least 0.05 g of hydrocarbons per gram of hydrocarbon
products having a boiling point distribution between 204.degree. C.
and 260.degree. C. Embodiments of the hydrocarbon product 120 may
further include at least 0.1 grams of hydrocarbons per gram of
hydrocarbon product 120 having a boiling point distribution between
260.degree. C. to 343.degree. C. Embodiments of the hydrocarbon
products may also include at least 0.2 grams of hydrocarbons per
gram of the hydrocarbon product 120 with a boiling range
distribution between 343.degree. C. and 510.degree. C. In certain
embodiments, of the hydrocarbon products, the hydrocarbon products
may contain at least 0.75 grams of hydrocarbons per gram of
hydrocarbon product having a boiling range distribution from the
IBP of the hydrocarbon products 120 up to 739.degree. C. In other
embodiments, the hydrocarbon products 120 may include at most 0.3
grams of hydrocarbons per gram of hydrocarbon products having a
boiling range distribution greater than 738.degree. C.
[0123] In some embodiments, the hydrocarbon products 120 may have
at least 0.05 g of gasolines per gram of hydrocarbon product. The
gasoline fraction may have a boiling range distribution between the
IBP of the hydrocarbon product and approximately 67.degree. C. In
other embodiments, the hydrocarbon product may have at most 0.6
grams of gasolines per gram of hydrocarbon product.
[0124] In some embodiments, the hydrocarbon product may have less
than 0.001 g of olefinic hydrocarbons per gram of hydrocarbon
product. In some embodiments, the hydrocarbon product may have at
least 0.001 g of olefinic hydrocarbons per gram of the hydrocarbon
product. In one or more embodiments, the hydrocarbon product may
contain less than 0.02 g of olefins per gram hydrocarbon product.
The amount of olefinic hydrocarbons measured per gram of the
hydrocarbon product may be measured using the Canadian Crude
Quality Technical Association (CCQTA)--Olefins in Crude Oil by
.sup.1H-NMR method. The olefinic hydrocarbon fractions may have a
boiling range distribution between the IBP of the hydrocarbon
product and 253.degree. C. Non-limiting examples of olefins may
include for example, styrene, 1-hexene, cyclohexene, limonene, and
trans-stilbene.
[0125] In some embodiments, the hydrocarbon product may have
between 0.01 g and 0.30 g of gasolines, naphtha, and/or paraffin,
per gram of hydrocarbon product. The gasolines, naphtha and/or
paraffin fractions may have a boiling point range distribution
between the IBP and approximately 204.degree. C.
[0126] In one or more embodiments, the hydrocarbon product may
contain at least 0.05 g of diesel oil per gram hydrocarbon
products. In other embodiments, the hydrocarbon product may contain
at most 0.8 g of diesel oil per gram of hydrocarbon product. The
diesel oil fraction may have boiling range distribution between
approximately 204.degree. C. and 260.degree. C.
[0127] In some embodiments, the hydrocarbon products may contain at
least 0.1 g of lubricating oils per gram of hydrocarbon products.
In other embodiments, the lubricating oils may be at most 0.8 g per
gram of hydrocarbon product. The lubricating oil fraction may have
a boiling range distribution between approximately 260.degree. C.
and 343.degree. C.
[0128] Embodiments of the hydrocarbon products may contain at least
0.2 g of fuel oils, greases, waxes and/or some bitumens per gram
hydrocarbon product. In other embodiments, the hydrocarbon product
may contain at most 0.8 g of fuel oils, greases, waxes and/or some
bitumens per gram hydrocarbon product. The fuel oils, greases,
waxes and/or some bitumens may have a boiling range distribution
between approximately 343.degree. C. and 510.degree. C.
[0129] Embodiments of the hydrocarbon products may contain at most
0.3 g of bitumen per gram of hydrocarbon product wherein the
bitumen has a boiling point range distribution greater than
738.degree. C.
[0130] The hydrocarbon products 120 of the present invention may
contain significant quantities of aromatic hydrocarbon compounds.
The hydrocarbon product may contain, per gram of hydrocarbon
product, at least 0.3 gram, or at least 0.35 gram, or at least 0.4
gram, or at least 0.45 gram, or at least 0.5 gram of aromatic
hydrocarbon compounds.
[0131] In some embodiments, the hydrocarbon product may have a
distillate content between 50-150% of the distillate content of the
hydrocarbon feed. The distillate content of the distillate
hydrocarbons per gram of hydrocarbon product may be in a range from
0.00001-0.8 g. In certain embodiments, the hydrocarbon product may
have VGO content of 50-150% of the VGO content of the hydrocarbon
feed. In some embodiments, the VGO content may range from
0.0001-0.8 g per gram of hydrocarbon product.
[0132] Embodiments of the hydrocarbon product may have a residue
content of at most 90% of the hydrocarbon feed. In other
embodiments, the residue content may be at most 80%, at most 50%,
at most 30%, at most 20%, at most 10% or at most 3% of the residue
content of the hydrocarbon feed. In certain embodiments, the
hydrocarbon products may have a residue content between 70-130% of
the residue content of the hydrocarbon feed.
[0133] Embodiments of the hydrocarbon product may have a total
C.sub.5 and C.sub.7 asphaltene content of at most 90% of the total
C.sub.5 and C.sub.7 asphaltene content of the hydrocarbon feed. In
other embodiments, the asphaltene content may be at most 50%, at
most 30% or at most 10% of the hydrocarbon feed. In certain
embodiments, the hydrocarbon feed may have a total C.sub.5 and
C.sub.7 asphaltene content of at least 0.01 g per gram of
hydrocarbon product. In other embodiments, the asphaltene content
may be at most 0.5 g per gram of hydrocarbon product. In some
embodiments, the asphalt content of the hydrocarbon product may be
the content of C.sub.5 and/or the content of C.sub.7 asphaltene.
The asphalt content may be measured using ASTM D3279-2 or an
equivalent method thereof. The asphalt content may be the
measurement of the grams of asphaltene insoluble n-heptane per gram
of hydrocarbon product containing asphalt. In one embodiment, the
asphalt content may be at least 0.3 g of asphaltene may be
insoluble in n-heptane, per gram of hydrocarbon product. A
hydrocarbon product containing asphalt or asphaltenes may have a
hydrogen to carbon ratio of less than 1.5:1 in some
embodiments.
[0134] Embodiments of methods for quantifying C.sub.5 or C.sub.7
asphaltene content may include the determination of the mass
percent of asphaltene defined by their insolubility in an n-heptane
solvent. Embodiments of methods characterizing the insolubility of
the asphaltene in n-heptane may be applicable to all solid, and
semi-solid asphalts, gas oils, heavy fuel oils and crude petroleum
that may be topped to a cut-point of approximately 343.degree. C.
or higher.
[0135] The H/C ratio of hydrogen to carbon may be determined by
ASTM D5291 or equivalent method. In some embodiments, the H/C ratio
may be between approximately 0.01:1 to 0.09:1, between 0.1:1 to
0.49:1, between 0.50:1 to 1:1 and/or between 1:1 to 1.5:1.
Accordingly, in other embodiments, the H/C ratio may be less than
1:100, less than 1:75, less than 1:50, less than 1:30, less than
1:20 or less than 1:10. The methods for testing test the carbon and
hydrogen content of various hydrocarbons and hydrocarbon products,
including crude oils, fuel oils, additives, lubricants and residues
may include concentration ranges of at least 75 to 85 mass % of
carbon and at least 9 to 16 mass % for hydrogen in some
embodiments. Embodiments employing certain methods for identifying
the hydrogen to carbon ratio may express the results as mass %
carbon and mass % hydrogen.
[0136] A hydrocarbon product containing asphalt or asphaltenes may
be the product of a crude asphalt hydrocarbon feed. In embodiments
where a crude asphalt hydrocarbon feed is used for hydrocarbon feed
101, the total acid number of the asphalt hydrocarbon product 120
may be less than the total acid number of the crude asphalt
hydrocarbon feed. In some embodiments, the TAN of asphalt
hydrocarbon products may be between 5 to 90% of the TAN of the
asphalt hydrocarbon feed. Embodiments of an asphalt hydrocarbon
product may have a TAN less than 0.5 mg KOH per gram of asphalt
containing hydrocarbon product.
[0137] A hydrocarbon product containing asphalt or derived from a
crude asphalt hydrocarbon feed subjected to oxidative
desulfurization treatment may have a viscosity of hydrocarbon
product that is less than the viscosity of the hydrocarbon feed.
For instance, in some embodiments, the viscosity of the asphalt
containing hydrocarbon product may have a viscosity less than the
hydrocarbon feed measured at 15.degree. C., 80.degree. C.,
100.degree. C., 120.degree. C. using ASTM D7042 to measure the
viscosity. In some embodiments, methods for determining viscosity
may include measurements of both the dynamic viscosity, .eta., and
the density, .rho., of hydrocarbons and hydrocarbon products and,
both transparent and opaque. The kinematic viscosity, .nu., can be
obtained by dividing the dynamic viscosity, .eta., by the density,
.rho., obtained at the same test temperature. Embodiments of the
methods may include determining the density or relative density of
hydrocarbons and hydrocarbon products for the conversion of
measured volumes to volumes at the standard temperature of
15.degree. C. The results obtained from testing methods may be
dependent upon the behavior of the sample in some embodiments, and
it's intended application to liquids for which primarily the shear
stress and shear rate are proportional (Newtonian flow
behavior).
[0138] In other embodiments, ASTM D7042 methods may be used to
measure the density of the hydrocarbon product and hydrocarbon
feeds containing asphalts and crude asphalts. The density of the
hydrocarbon feed may be 1.05 grams/cubic centimeter (g/cc) or
greater when measured at 15.degree. C. In other embodiments, the
density of the hydrocarbon product may be measured at intervals
above 15.degree. C., such as 80.degree. C., 100.degree. C. and
120.degree. C. then extrapolated back to 15.degree. C. to determine
that the density of the hydrocarbon product is greater than 1.05
g/cc.
[0139] In some embodiments, as a result from removing heteroatoms
from the hydrocarbon feed, the light oil phase containing the
hydrocarbon products 120, may have a lower density and viscosity
than the untreated, contaminated feed. The heavy caustic phase
density may be in the range from about 1.0 to about 3.0 g/cc and
the light product oil phase may have density generally in the range
of from about 0.7 to about 1.1 g/cc as measured at 15.degree.
C.
[0140] In some embodiments, the composition of the crude asphalt
hydrocarbon product may have some residual or remaining metals
after oxidative desulfurization. The metal content of the
hydrocarbon product may be less than the crude asphalt hydrocarbon
feed. In some embodiments, the hydrocarbon product may have a total
metal content that is less than 90% of the metal content of the
hydrocarbon feed. In other embodiments, the hydrocarbon product may
be less than 50%, less than 20% or less than 10% of the metal
content of the hydrocarbon feed. The product may be further treated
by other well-known refinery operations including, but not limited
to: hydrotreating, hydrocracking, fluidized catalytic cracking,
coking, distillation, etc.
[0141] In some embodiments, the hydrocarbon feed 101, hydrocarbon
products 120 and the intermediate products 111 may be characterized
using infrared (IR) spectroscopy to identify the characteristics
and properties of the hydrocarbons. The IR spectra may be used to
measure the absorbance (A) at each wavelength or wavenumber and
then the peaks may be plotted along the spectrum, wherein the
location along the spectrum may signify the functional class (such
as sulfoxide or sulfone) and the height or area of the peak may be
proportional to the amount (for example weight %) of the functional
class present. A non-limiting list of examples of functional
classes are provided in Table 1 and Table 2 below.
[0142] The hydrocarbon feed, hydrocarbon products and intermediate
products may be measured by any known infrared spectroscopy
techniques. For example, each of the hydrocarbons may be measured
using attenuated total reflectance Fourier Transform Infrared
Spectroscopy. Embodiments measuring the content of the hydrocarbon
feed 101, the sulfoxidized intermediate stream 111 and the
hydrocarbon product may be measured "neat" in some embodiments
(without the addition of solvents or additives).
[0143] The IR spectra provided in FIG. 7a to FIG. 7e demonstrate an
example of using IR to characterize, compare and contrast the
compositions and content of the hydrocarbon feed 101, hydrocarbon
product 120 and intermediate stream 111. In some embodiments, the
infrared spectroscopy peaks or areas of interest in classifying the
signature compositions of the intermediate stream and the
hydrocarbon products may be those peaks or areas corresponding to
sulfone and sulfoxide functional groups. Table 1 provides an
example of typical infrared absorption frequencies and some sample
characteristics describing the vibrations, range and intensity of
the bands. Table 2 below provides example absorption ranges for IR
spectroscopy for various functional classes including classes of
compositions that may be present in hydrocarbon feeds, sulfoxidized
intermediate streams and the hydrocarbon product such as sulfones,
sulfoxides and sulfates.
TABLE-US-00001 TABLE 1 Stretching Vibrations Bending Vibrations
Functional Range Range Class (cm.sup.-1) Intensity Assignment
(cm.sup.-1) Intensity Assignment Alkanes 2850-3000 str CH.sub.3,
CH.sub.2 & CH 1350-1470 med CH.sub.2 & CH.sub.3 2 or 3
bands 1370-1390 med deformation 720-725 wk CH.sub.3 deformation
CH.sub.2 rocking Alkenes 3020-3100 med .dbd.C--H &
.dbd.CH.sub.2 880-995 str .dbd.C--H & .dbd.CH.sub.2 1630-1680
var (usually sharp) 780-850 med (out-of-plane 1900-2000 str C.dbd.C
(symmetry 675-730 med bending) reduces cis-RCH.dbd.CHR intensity)
C.dbd.C asymmetric stretch Alkynes 3300 str C--H (usually 600-700
str C--H 2100-2250 var sharp) deformation C.ident.C (symmetry
reduces intensity) Arenes 3030 var C--H (may be 690-900 str-med
C--H bending & 1600 & 1500 med-wk several bands) ring
C.dbd.C (in ring) (2 puckering bands) (3 if conjugated) Alcohols
& 3580-3650 var O--H (free), 1330-1430 med O--H bending Phenols
3200-3550 str usually sharp 650-770 var-wk (in-plane) 970-1250 str
O--H (H- O--H bend bonded), (out-of- usually broad plane) C--O
TABLE-US-00002 TABLE 2 Functional Class Characteristic Absorptions
Sulfur Functions S--H thiols 2550-2600 cm.sup.-1 (wk & shp)
S--OR esters 700-900 (str) S--S disulfide 500-540 (wk) C.dbd.S
thiocarbonyl 1050-1200 (str) S.dbd.O sulfoxide 1030-1060 (sir)
sulfone 1325 .+-. 25 (as) & 1140 .+-. 20 (s) (both str)
sulfonic acid 1345 (sir) sulfonyl chloride 1365 .+-. 5 (as) &
1180 .+-. 10 (s) (both str) sulfate 1350-1450 (str) Phosphorous
Functions P--H phosphine 2280-2440 cm.sup.-1 (med & shp)
950-1250 (wk) P--H bending (O.dbd.)PO--H phosphonic acid 2550-2700
(med) P--OR esters 900-1050 (str) P.dbd.O phosphine oxide 1100-1200
(str) phosphonate 1230-1260 (str) phosphate 1100-1200 (str)
phosphoramide 1200-1275 (str) Silicon Functions Si--H silane
2100-2360 cm.sup.-1 (str) Si--OR 1000-11000 (str & brd)
Si--CH.sub.3 1250 .+-. 10 (str & shp) Oxidized Nitrogen
Functions .dbd.NOH oxime O--H (stretch) 3550-3600 cm.sup.-1 (str)
C.dbd.N 1665 .+-. 15 N--O 945 .+-. 15 N--O amine oxide aliphatic
960 .+-. 20 aromatic 1250 .+-. 50 N.dbd.O nitroso 1550 .+-. 50
(sir) nitro 1530 .+-. 20 (as) & 1350 .+-. 30 (s)
[0144] Referring to FIGS. 7a to 7e as an example of an IR spectra,
an infrared spectroscopy reference peak may be established between
approximately 1445 cm.sup.-1 and 1465 cm.sup.1 for the hydrocarbon
product 120, intermediate product 111 and the hydrocarbon feed 101.
In some embodiments, the peak height or area of the reference peak
may be at approximately 1455 cm.sup.-1. In the embodiments depicted
in FIG. 7a to FIG. 7e, the height or area of the reference peak may
be normalized so that the peak height or area of the reference peak
may be approximately 1.0 absorbance (A). In an alternative
embodiment, the reference peak may be measured by absolute
absorbance rather than normalizing the curve.
[0145] As shown in FIG. 7b and FIG. 7d, intermediate products 111
may be characterized by the presence of infrared spectroscopy peaks
identified by one or more peaks recorded using IR spectroscopy. The
peaks may be referred to as a first, second, third, fourth or fifth
peak, etc., however name of the peak denotes the order in which the
peak is discussed. The location and identifying nature of the peak
may be based on the wavelength or wavenumber where the peak may be
located during IR spectroscopy, not the designation of the peak as
the first, second or third, etc. For example, a peak that may be
described as a first peak in one embodiment because it resides at a
lower wavenumber, may also be referred to as a second peak, or a
third peak in another embodiment when the peak appears subsequent
to another peak. Likewise, a peak that may be present in an IR spec
as a "second peak" in a first embodiment may be referred to as a
first peak in a second embodiment wherein the "first peak" of the
first embodiment is not present in the second embodiment.
[0146] A first peak that may characterize the contents of the
intermediate products 111 may be present on the IR spectrum between
the wavelengths or wavenumbers of approximately 1310 cm.sup.-1 to
1285 cm.sup.-1. This first peak may have a height or area that is
at least approximately 28% of the height or area of the reference
peak. In some embodiments, the first peak may have a height or area
that is approximately at least 30%, at least 35%, at least 40%, at
least 50%, at least 70%, at least 85%, at least 100% or greater
than 100% of the height or area of the reference peak.
[0147] Embodiments of the intermediate products 111 may also be
classified using IR spectroscopy by the presence of another peak.
This second peak may appear on an IR spectroscopy readout at a
wavelength or wavenumber between approximately 1135 cm.sup.-1 and
1110 cm.sup.-1. The peak height or area of this second peak may be
present at a wavelength or wavenumber of approximately 1125
cm.sup.-1. Embodiments of the intermediate product 111, may exhibit
this second peak with height or area that is approximately at least
22% of the height or area of the reference peak. In some
embodiments, this second peak may have a height or area that is at
least 25%, at least 30%, at least 40%, at least 50%, at least 70%,
at least 85%, at least 100% or greater than 100% of the height or
area of the reference peak.
[0148] In some embodiments of the intermediate products 111, the
intermediate products may be characterized by the presence of yet a
third peak identified using IR spectroscopy. This third peak may
appear on an IR spectroscopy readout at a wavelength or wave number
between approximately 1040 cm.sup.-1 and 1000 cm.sup.-1. The peak
height or area of the third peak may be present at a wavelength or
wavenumber of approximately 1031 cm.sup.-1. Embodiments of the
intermediate product 111, may exhibit a third peak having a height
or area that is approximately at least 22% of the height or area of
the reference peak. In some embodiments, the second peak may have a
height or area that is at least 25%, at least 30%, at least 40%, at
least 50%, at least 70%, at least 85%, at least 100% or greater
than 100% of the height or area of the reference peak.
[0149] Embodiments of the hydrocarbon product 120 may also be
characterized by IR spectroscopy in a manner similar to the
intermediate products 111. For example, the hydrocarbon products
may be characterized by the presence of peaks identified by one or
more peaks recorded using IR spectroscopy. For example, in one
embodiment, a first peak that may characterize the contents of the
hydrocarbon products 120 may be present on the IR spectrum between
the wavelengths or wavenumbers of approximately 1310 cm.sup.-1 to
1285 cm.sup.-1. This first peak may have a height or area that is
at least approximately 28% of the height or area of the reference
peak. In some embodiments, the first peak may have a height or area
that is approximately at least 30%, at least 35%, at least 40%, at
least 50%, at least 70%, at least 85%, at least 100% or greater
than 100% of the height or area of the reference peak.
[0150] Embodiments of the hydrocarbon product may also be
classified using IR spectroscopy by the presence of other peaks. A
second peak that may appear on an IR spectroscopy readout may be at
a wavelength or wavenumber between approximately 1135 cm.sup.-1 and
1110 cm.sup.-1. The peak height or area of this second peak may be
present at a wavelength or wave number of approximately 1125
cm.sup.-1. Embodiments of the hydrocarbon products 120, may exhibit
a second peak with height or area that is approximately at least
22% of the height or area of the reference peak. In some
embodiments, the second peak may vary in height or area, for
example, the height or area of the second peak may be at least 25%,
at least 30%, at least 40%, at least 50%, at least 70%, at least
85%, at least 100% or greater than 100% of the height or area of
the reference peak.
[0151] In some embodiments of the hydrocarbon products 120, the
hydrocarbon products may be characterized by the presence of a
third signature peak identified using IR spectroscopy. The third
peak may appear on an IR spectroscopy readout at a wavelength or
wavenumber between approximately 1040 cm.sup.-1 and 1000 cm.sup.-1.
The peak height or area of the third peak may be present at a
wavelength or wavenumber of approximately 1031 cm.sup.-1.
Embodiments of the hydrocarbon product 120, may exhibit a third
peak having a height or area that is approximately at least 22% of
the height or area of the reference peak. In some embodiments, the
second peak may have a height or area that is at least 25%, at
least 30%, at least 40%, at least 50%, at least 70%, at least 85%,
at least 100% or greater than 100% of the height or area of the
reference peak.
[0152] In the embodiments of the intermediate product 111 and the
hydrocarbon product 120, having a reference peak, a first peak, a
second peak or a third peak, the wavelength or wavenumber
classifying the location of the peaks may vary between +/-10% of
the value of the upper and lower bounds of the peak's range
described herein. Distillates derived from intermediate product 111
or hydrocarbon product 120 having a reference peak and a plurality
of peaks such as a first peak, a second peak or a third peak, the
peak heights or areas in relation to the reference peak may vary
between +/-60% of those described herein. The following
non-limiting examples illustrate certain aspects of the present
invention:
Example 1
Preparation of Catalyst
[0153] Bis(glycerol)oxo titanium(IV) is prepared according to the
method of U.S. Pat. No. 8,394,261 B2 which is hereby incorporated
by reference. Titanium oxychloride (2 kilograms (kg), Millenium
Chemicals) is diluted with de-ionized water (2 kg) and then added
to a 20 liter (1) round bottom flask containing glycerine (2 kg).
The mixture is allowed to stir until a straw color is attained. The
20 liter round bottom flask is then heated to 50.degree. C. under
vacuum (-25 inches Hg) in a rotary evaporator to remove excess
water and hydrochloric acid. When no further liquid condensate is
noted, the flask is recharged with water (0.65 l) and rotary
evaporated to further remove excess water and hydrochloric acid.
This is repeated two additional times. After the final evaporation,
the viscous, straw colored liquid is weighed (2.64 kg) and diluted
with methoxypropanol (0.85 kg) to reduce the viscosity. This is
then neutralized with triethylamine (3.3 kg, 33% weight/weight in
ethanol). The combined neutralized solution is then chilled for
several hours producing rod-like needles of triethylamine
hydrochloride. The crystalline triethylamine hydrochloride is
removed by vacuum filtration. The filtrate is added slowly to
acetone (70 L) causing the product to precipitate as a white solid.
The acetone is then decanted and an off-white solid residue is
obtained. The off-white solid residue is then washed vigorously
with hexanes (20 L) to afford a fine white powder. The powder is
collected by filtration (>63% yield based upon Ti). % Ti
Calculated: 16.98. Analysis: 16.7; mp DSC (dec) 273.degree. C.;
ESI-MS (positive mode) 245 amu; .sup.1H-NMR (DMSO-d6) 4.25 (br s,
4H), 3.45 (m, 2H), 3.38 (m, 4H), 3.31 (m, 4H).
Example 2
General Method for Adsorption of Catalyst onto Support
[0154] A 2% by weight solution of the catalyst from example 1 is
prepared by mixing with methanol. The solution is added to a silica
support until the solids are fully immersed at ambient temperature.
The solids are allowed to soak for approximately 30 minutes, or
until all air is displaced. The liquid is decanted from the solids
and the solids are dried in vacuo (50.degree. C.) until the weight
of the solids no longer changes. A 40% solution of t-butyl
hydroperoxide in xylene is added to the dried catalyst-coated
support until the solids are fully immersed. The suspension is
allowed to gently mix at 95 C for 90 minutes. Afterwards, the
liquid is decanted from the solids. Then the solids are washed with
sufficient hexanes until residual peroxide content in the hexanes
is less than 0.5%. The solids are then dried in vacuo at 50.degree.
C. until the solid weight no longer changes.
Example 3
Preparation of Caustic Treatment Mixture
[0155] A solution containing 79.1% w/w sodium sulfide nonahydrate
and 20.9% w/w propylene glycol is prepared. The mixture is heated
to 50.degree. C. to insure complete dissolution. The solution is
stored in a warm water bath to prevent sulfide precipitation before
further use.
Examples 4A and 4B
Continuous Catalytic Heteroatom Oxidation
[0156] A water jacketed plug flow reactor with an aspect ratio
(length/diameter) of 20 is filled with 171 grams of supported
catalyst prepared according to the method of example 2 containing
about 0.4% w/w Ti. The reactor temperature is stabilized at 95 C.
An Athabasca bitumen feed is warmed to 80 C under nitrogen in a
stainless steel drum to facilitate pumping into the reactor. The
bitumen is combined with an excess of tert-butylhydroperoxide
solution in xylenes (40% w/w) to obtain a 6:1 molar ratio of
peroxide to sulfur at the reactor inlet.
[0157] The solution is pumped into the reactor at a sufficient flow
rate to obtain a liquid residence time of 90 minutes in the
reactor. Samples are collected periodically at the reactor outlet
to measure peroxide concentration. The reactor effluent is
continuously distilled under vacuum to remove all residual
peroxide, tert-butanol, and xylenes and to obtain an oxidized
heteroatom bitumen stream.
[0158] Example 4B is the same as 4A except that the reactor
temperature is increased to 115.degree. C.
Example 5A and 5B
Caustic Treatment of Example 4 Output
[0159] The oxidized heteroatom bitumen stream of Example 4A and 4B
are independently co-fed with the mixture of Example 3 into a
continuously stirred tank reactor (CSTR) so as to obtain a liquid
residence time of 90 minutes at 275.degree. C. under 300 psig. The
reactor effluent flows into a gravity settler producing an oil
phase and a spent caustic phase. The oil product is separated from
the spent caustic phase. The properties of the products of 4A, 4B,
5A, 5B and the hydrocarbon feed may be compared and characterized
by the IR spectroscopy printout depicted in FIG. 7a to FIG. 7e.
[0160] While this disclosure has been described in conjunction with
the specific embodiments outlined above, it is evident that many
alternatives, modifications and variations will be apparent to
those skilled in the art. Accordingly, the preferred embodiments of
the present disclosure as set forth above are intended to be
illustrative, not limiting. Various changes may be made without
departing from the spirit and scope of the invention, as required
by the following claims. The claims provide the scope of the
coverage of the invention and should not be limited to the specific
examples provided herein.
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