U.S. patent application number 14/551410 was filed with the patent office on 2015-05-28 for methods and systems for treating petroleum feedstock containing organic acids and sulfur.
The applicant listed for this patent is Ceramatec, Inc.. Invention is credited to John Howard Gordon.
Application Number | 20150144503 14/551410 |
Document ID | / |
Family ID | 53181703 |
Filed Date | 2015-05-28 |
United States Patent
Application |
20150144503 |
Kind Code |
A1 |
Gordon; John Howard |
May 28, 2015 |
METHODS AND SYSTEMS FOR TREATING PETROLEUM FEEDSTOCK CONTAINING
ORGANIC ACIDS AND SULFUR
Abstract
Methods and systems of treating petroleum feedstock contaminated
with naphthenic acids and sulfur are disclosed. The methods and
systems include heating the petroleum feedstock to decompose the
naphthenic acids, pressurizing to minimize the portion in the vapor
phase, sweeping water vapor and carbon dioxide into a headspace
with a non-oxidizing gas, removing water vapor and carbon dioxide
from the headspace, reacting the sulfur with an alkali metal and a
radical capping gas to convert the sulfur into alkali sulfides, and
removing the alkali sulfides. Also disclosed is reacting the
naphthenic acid with water and an oxide or hydroxide of an alkaline
earth element to convert the naphthenic acid into naphthenates,
removing water, ketonizing, removing oxides or carbonates, reacting
the sulfur with an alkali metal and a radical capping gas to
convert the sulfur into alkali sulfides, and removing the alkali
sulfides.
Inventors: |
Gordon; John Howard; (Salt
Lake City, UT) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Ceramatec, Inc. |
Salt Lake City |
UT |
US |
|
|
Family ID: |
53181703 |
Appl. No.: |
14/551410 |
Filed: |
November 24, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61909092 |
Nov 26, 2013 |
|
|
|
Current U.S.
Class: |
205/705 ;
208/187; 208/188 |
Current CPC
Class: |
C10G 53/14 20130101;
C10G 29/04 20130101; C10G 53/12 20130101; C25C 3/02 20130101; C10G
53/02 20130101; C10G 2300/203 20130101; C25C 1/02 20130101; C10G
67/02 20130101; Y02P 30/20 20151101; C25B 1/00 20130101; C25C 7/04
20130101; C10G 3/40 20130101; C10G 2300/202 20130101 |
Class at
Publication: |
205/705 ;
208/188; 208/187 |
International
Class: |
C10G 53/12 20060101
C10G053/12; C25C 1/02 20060101 C25C001/02; C25C 3/02 20060101
C25C003/02; C10G 67/02 20060101 C10G067/02 |
Claims
1. A method for treating petroleum feedstock comprising: providing
a petroleum feedstock comprising naphthenic acids and sulfur;
heating the petroleum feedstock to decompose the naphthenic acids;
pressurizing the petroleum feedstock to minimize a portion of the
petroleum feedstock in a vapor phase; sweeping water vapor and
carbon dioxide from the petroleum feedstock into a headspace with a
non-oxidizing gas; removing water vapor and carbon dioxide from the
headspace to promote naphthenic acid decomposition; reacting the
sulfur with an alkali metal and a radical capping gas to convert
the sulfur into alkali sulfides; and removing the alkali
sulfide.
2. The method of claim 1, wherein the petroleum feedstock is heated
in a range of about 200.degree. C. to about 425.degree. C.
3. The method of claim 1, wherein the petroleum feedstock is heated
in a range of about 300.degree. C. to about 400.degree. C.
4. The method of claim 1, wherein the non-oxidizing gas comprises
hydrogen, light hydrocarbon gas, pyrolysis gas, or combinations
thereof.
5. The method of claim 1, wherein the alkali metal comprises
lithium, sodium, potassium, or combinations thereof.
6. The method of claim 1, wherein the radical capping gas comprises
one or more of the following: methane, ethane, propane, butane,
pentane, hexane, heptane, octane, ethene, propene, butane, pentene,
hexene, heptene, octene, and isomers of the foregoing, natural gas,
shale gas, liquid petroleum gas, ammonia, primary, secondary, and
tertiary ammines, thiols, mercaptans, and hydrogen sulfide.
7. The method of claim 1, further comprising regenerating the
alkali metal from the alkali metal sulfide.
8. The method of claim 7, wherein regenerating the alkali metal
from the solids comprises an electrolytic process using an alkali
metal ion conductive ceramic membrane.
9. A method for treating petroleum feedstock comprising: providing
a petroleum feedstock comprising naphthenic acids and sulfur;
reacting the naphthenic acid an aqueous solution or slurry
containing an oxide or hydroxide of an alkaline earth element while
heating to convert the naphthenic acid into alkaline earth
naphthenates, thereby generating an alkaline earth naphthenate
mixture; removing water from the alkaline earth naphthenate mixture
to generate a dewatered mixture; reacting the sulfur in the
dewatered mixture with an alkali metal and a radical capping gas to
convert the sulfur into alkali sulfides; and removing the alkali
sulfides.
10. The method of claim 9, wherein the alkaline earth mixture is
heated in a range of about 80.degree. C. to about 95.degree. C.
11. The method of claim 9, wherein the dewatered mixture is heated
in a range of about 300.degree. C. to about 400.degree. C.
12. The method of claim 9, wherein the alkali metal comprises
sodium and the alkaline earth element comprises one or more of
calcium, strontium, or barium.
13. The method of claim 9, further comprising regenerating the
alkali metal from the alkali metal sulfide.
14. The method of claim 7, wherein regenerating the alkali metal
from the solids comprises an electrolytic process using an alkali
metal ion conductive ceramic membrane.
15. A method for treating petroleum feedstock comprising: providing
a petroleum feedstock comprising naphthenic acids and sulfur;
reacting the naphthenic acid with an aqueous solution or slurry
containing an oxide or hydroxide of an alkaline earth element while
heating to convert the naphthenic acid into an alkaline earth
naphthenate, thereby generating an alkaline earth naphthenate
mixture; removing water from the alkaline earth naphthenate mixture
to generate a dewatered mixture; heating the dewatered mixture to
convert alkaline earth naphthenates into ketones and alkaline earth
oxides or alkaline earth carbonates, thereby generating a ketone
mixture; removing alkaline earth oxides or alkaline earth
carbonates from the ketone mixture; reacting the sulfur in the
ketone mixture with an alkali metal and a radical capping gas to
convert the sulfur into alkali sulfides; and removing the alkali
sulfide.
16. The method of claim 15, wherein the dewatered mixture is heated
in a range of about 166.degree. C. to about 312.degree. C.
17. The method of claim 15, wherein heating the dewatered mixture
to convert alkaline earth naphthenates into ketones and alkaline
earth oxides or alkaline earth carbonates and reacting the sulfur
with an alkali metal and a radical capping gas to convert the
sulfur into an alkali sulfide is carried out at the same time in a
single reaction vessel.
18. The method of claim 17, wherein the alkali metal comprises
sodium and the alkaline earth element comprises one or more of
calcium, strontium, or barium.
19. The method of claim 15, further comprising regenerating the
alkaline earth carbonates with heat to form alkaline earth
oxides.
20. The method of claim 15, wherein removing the alkaline earth
oxides or alkaline earth carbonates and the alkali sulfide
comprises filtration, centrifugation, hydrocyclonic separation, or
combinations thereof.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Provisional
Patent Application Ser. No. 61/909,092 filed Nov. 26, 2013,
entitled "Method to Reduce Alkali Metal Needed for Desulfurization
of High TAN Petroleum Feedstock." The disclosure of the application
to which the present application claims priority is incorporated by
reference.
[0002] Without claiming domestic priority, this application is
related to U.S. Pat. No. 8,828,220 filed Nov. 1, 2010, titled
"Upgrading of petroleum oil feedstocks using alkali metals and
hydrocarbons" and U.S. Pat. No. 8,828,221 filed Jul. 16, 2012,
titled "Upgrading platform using alkali metals." These prior patent
applications are expressly incorporated herein by reference.
TECHNICAL FIELD
[0003] The present disclosure relates to methods and systems for
treating petroleum feedstock containing organic acids and sulfur.
More specifically, the present disclosure relates to reducing the
amount of alkali metal needed for desulfurization of high TAN
petroleum feedstock by treating organic acids in high TAN petroleum
feedstock prior to desulfurization.
BACKGROUND
[0004] There is an ongoing demand for hydrocarbon fuels as an
energy source and newer sources of hydrocarbon raw materials are
being exploited. These newer sources of hydrocarbon raw materials
include shale oil, bitumen, heavy oils, and other similar
materials. However, these types of hydrocarbon raw materials often
contain high levels of difficult-to-remove sulfur and heavy metals.
The high level of nitrogen, sulfur, and heavy metals in these newer
sources of hydrocarbon raw materials (which may collectively or
individually be referred to as "petroleum feedstock") makes
processing these materials difficult. Typically, these petroleum
feedstock materials are refined to remove the sulfur, nitrogen and
heavy metals through processes known as "hydro-treating" or "alkali
metal desulfurization."
[0005] U.S. Pat. Nos. 8,828,820 and 8,828,821 to Gordon describe
methods for desulfurizing and demetallizing petroleum feedstock.
Gordon describes methods by which petroleum feedstock is reacted
with molten alkali metal in the presence of a radical capping gas.
In Gordon's process the molten alkali metal reacts with heavy
metals such as nickel and vanadium in the petroleum feedstock.
Alkali metal sulfides are also formed from sulfur in the petroleum
feedstock. The treated heavy metals and alkali metal sulfides can
then be separated from the oil by standard processes such as
gravimetric separation, filtration, or centrifugation.
[0006] However, these petroleum feedstocks that are high in sulfur
and heavy metals can often be high in total acid number (TAN) with
values in the range of 1 mg KOH/g. TAN is an important quality
measurement of crude oil and is a measurement of total acidity as
determined by the amount of potassium hydroxide needed to
neutralize the acids in one gram of oil. High TAN values can pose a
corrosion problem to machinery, piping, or other metal surfaces
that contact the high TAN petroleum. Due to this corrosion problem,
petroleum refineries will often restrict the amount of high TAN
petroleum feedstock that can be processed. Therefore, there is a
need to lower TAN levels in petroleum feedstock prior to refinery
processing.
[0007] Generally, the acidity in high TAN petroleum feedstock can
be attributed to organic acids, such as naphthenic acids. Havre
describes naphthenic acids in petroleum feedstock as carboxylic
monoacids of the general formula RCOOH where R represents any
cycloaliphatic structure. Havre, T. E. (2002). Formation of calcium
naphthenate in water/oil systems, naphthenic acid chemistry and
emulsion stability. Havre further describes naphthenic acids as
C.sub.10-C.sub.50 compounds with 0-6 fused saturated rings and with
the carboxylic acid group attached to a ring via a short side
chain.
[0008] The method of Gordon can remove organic acids, including
naphthenic acids, from petroleum feedstocks despite the varying
specific structure of the organic acids. While much of the
following discussion will refer specifically to naphthenic acids,
it is understood that the disclosed methods and systems may be used
to treat other organic acids present in petroleum feedstocks. In
Gordon, the molten alkali metal can react with the naphthenic acid
and allow for their removal. In the case where molten sodium is the
alkali metal added to petroleum feedstock containing naphthenic
acids, the reaction of Equation 1a is assumed to occur. A similar
reaction where molten lithium is the alkali metal is depicted in
Equation 1b:
RCOOH+Na.fwdarw.RCOONa+1/2H.sub.2 Equation 1a
RCOOH+Li.fwdarw.RCOOLi+1/2H.sub.2 Equation 1b
[0009] In Equations 1a and 1b, the naphthenic acids are converted
to sodium naphthenate and lithium naphthenate, respectively. The
method of Gordon can lower the TAN caused by naphthenic acids by
converting the naphthenic acids to naphthenate salts and thereby
lowering the corrosiveness of the treated petroleum feedstock.
Unfortunately, there are a number of drawbacks to using the method
of Gordon or similar methods to remove naphthenic acids from high
TAN petroleum feedstocks. These drawbacks include the consumption
of costly alkali metal in the process, the formation of amphiphilic
alkali naphthenate salts that can form stable emulsions that can be
difficult to remove, and the lack of an easy methodology for
recovering alkali metal from alkali naphthenates.
[0010] One drawback to the method of Gordon and similar methods is
that costly alkali metal is consumed to convert naphthenic acids to
alkali naphthenates. Alkali metal that reacts with naphthenic acids
is not available to react with and remove sulfur from the petroleum
feedstock. Also, alkali naphthenates can be difficult to remove
from the petroleum feedstock. The amphiphilic nature of alkali
naphthenates causes them to reside at water-oil interfaces and to
form stable emulsions that can be difficult to remove from the
petroleum feedstock and create problems with downstream processing.
Furthermore, it is undesirable for the alkali metal (in the form of
the alkali naphthenate) to remain in the petroleum feedstock with
amounts over about 100 ppm needing to be removed. Lastly, it is
difficult to regenerate the alkali metal from alkali naphthenates.
In contrast, alkali sulfide can be easily recovered from the
feedstock and the alkali metal from alkali sulfide can be
regenerated via electrolysis.
[0011] Therefore, there is a need in the industry for new methods
and systems to treat naphthenic acids in high TAN petroleum
feedstocks prior to treatment with alkali metal to remove sulfur
and heavy metals. Such methods and systems are disclosed
herein.
BRIEF SUMMARY
[0012] Methods and systems for treating petroleum feedstock are
disclosed. In some embodiments, the present application discloses
methods and systems for treating petroleum feedstock comprising
providing a petroleum feedstock comprising organic acids, such as
naphthenic acids, and sulfur, heating the petroleum feedstock to
decompose the organic acids, pressurizing the petroleum feedstock
to minimize a portion of the petroleum feedstock in a vapor phase,
sweeping water vapor and carbon dioxide from the petroleum
feedstock into a headspace with a non-oxidizing gas, removing water
vapor and carbon dioxide from the headspace to promote organic acid
decomposition, reacting the sulfur with an alkali metal and a
radical capping gas to convert the sulfur into alkali sulfides, and
removing the alkali sulfides.
[0013] In other embodiments, the present application discloses
methods and systems for treating petroleum feedstock comprising
providing a petroleum feedstock comprising organic acids, such as
naphthenic acids, and sulfur, reacting the organic acid with a
quantity of water and a stoichiometric excess of an oxide or
hydroxide of an alkaline earth element while heating to convert the
organic acid into alkaline earth carboxylates, such as
naphthenates, to generate an alkaline earth carboxylate
(naphthenate) mixture, removing water from the alkaline earth
carboxylate (naphthenate) mixture to generate a dewatered mixture,
reacting the sulfur in the dewatered mixture with an alkali metal
and a radical capping gas to convert the sulfur into alkali
sulfides, and removing the alkali sulfides
[0014] In yet other embodiments, the present application discloses
methods and systems for treating petroleum feedstock comprising
providing a petroleum feedstock comprising organic acids, such as
naphthenic acids, and sulfur, reacting the organic acid with a
quantity of water and a stoichiometric excess of an oxide or
hydroxide of an alkaline earth element while heating to convert the
organic acid into an alkaline earth carboxylate (naphthenate) to
generate an alkaline earth carboxylate (naphthenate) mixture,
removing water from the alkaline earth carboxylate (naphthenate)
mixture to generate a dewatered mixture, heating the dewatered
mixture to convert alkaline earth carboxylates (naphthenates) into
ketones and alkaline earth oxides or alkaline earth carbonates to
generate a ketone mixture, removing alkaline earth oxides or
alkaline earth carbonates from the ketone mixture, reacting the
sulfur in the ketone mixture with an alkali metal and a radical
capping gas to convert the sulfur into alkali sulfides, and
removing the alkali sulfide.
BRIEF DESCRIPTION OF THE DRAWINGS
[0015] In order to describe the manner in which the above-recited
and other advantages and features of the invention can be obtained,
a more particular description of the invention briefly described
above will be rendered by reference to specific embodiments thereof
which are illustrated in the appended drawings. Understanding that
these drawings depict only typical embodiments of the invention and
are not therefore to be considered to be limiting of its scope, the
invention will be described and explained with additional
specificity and detail through the use of the accompanying drawings
in which:
[0016] FIG. 1 illustrates a method and system for treating
petroleum feedstock by decomposing naphthenic acid by heat followed
by reaction with alkali metal and radical capping gas;
[0017] FIG. 2 illustrates a method and system for treating
petroleum feedstock by reacting the feedstock with oxides or
hydroxides of alkaline earth elements followed by reaction with
alkali metal and radical capping gas;
[0018] FIG. 3 illustrates a method and system for treating
petroleum feedstock by reacting the feedstock with oxides or
hydroxides of alkaline earth elements, dewatering, and
ketonization, followed by reaction with alkali metal and radical
capping gas; and
[0019] FIG. 4 illustrates a method and system for treating
petroleum feedstock by reacting the feedstock with oxides or
hydroxides of alkaline earth elements, dewatering, followed by
ketonization and reaction with alkali metal and radical capping
gas.
DETAILED DESCRIPTION OF THE INVENTION
[0020] The present application discloses methods and systems for
treating petroleum feedstock. More specifically, the present
disclosure relates to treating organic acids (including naphthenic
acids) in high TAN petroleum feedstock followed by treatment with
alkali metals to remove sulfur and optionally heavy metals. In some
embodiments, the present application discloses methods and systems
for thermally treating a liquid high TAN petroleum feedstock at a
temperature high enough and at a pressure sufficient to decompose
carboxylic acid groups of the organic acids while minimizing any
fraction of the feedstock from leaving the liquid phase. In other
embodiments, the thermal pretreatment of the petroleum feedstock
can lower or eliminate the amount of organic or naphthenic acids in
the petroleum feedstock, thereby requiring less alkali metal for
further processing and lessening the amount of naphthenate salts
that must be removed. In yet other embodiments, a high TAN
petroleum feedstock can be pretreated with water and oxides or
hydroxides of alkaline earth elements to generate alkaline earth
carboxylates or naphthenates before treatment with alkali metal for
desulfurization and demetallization. In some embodiments, high TAN
petroleum feedstock can be pretreated with water and a
stoichiometric excess of oxides or hydroxides of alkaline earth
elements to generate alkaline earth carboxylates or naphthenates,
dewatered, heated to form ketones, the ketones removed, and treated
with alkali metal. In other embodiments, the ketone formation and
the alkali metal treatment can be carried out at the same time in a
single reactor vessel. In yet other embodiments, the alkali metals
and/or the alkaline earth oxides or hydroxides can be
regenerated.
[0021] In some embodiments the present application discloses
methods and systems for treating petroleum feedstock containing
contaminants. In some embodiments, contaminants can comprise one or
more of organic acids, carboxylic acids, naphthenic acids, sulfur,
or heavy metals. In some embodiments, treating the petroleum
feedstock can comprise removing one or more contaminants from the
petroleum feedstock. In other embodiments, treating the feedstock
can comprise lowering the levels of one or more contaminants to
levels sufficient for further petroleum processing. In yet other
embodiments, treating the petroleum feedstock can comprise lowering
the TAN values to sufficient levels to lessen corrosion during
further processing of the petroleum feedstock.
[0022] In some embodiments, contaminants in petroleum feedstock can
comprise sulfur, sulfur compounds and/or sulfur containing
molecules and complexes. In other embodiments, sulfur contaminants
can comprise organic sulfur compounds, thiols, thiophenes, organic
sulfides, and/or organic disulfides. In yet other embodiments,
sulfur contaminants can include benzothiophenes and
dibenzothiophenes.
[0023] In some embodiments, heavy metal contaminants can comprise
any metal that interferes with any further processing or use of the
petroleum feedstock. In other embodiments, heavy metal contaminants
can comprise heavy metals such as nickel and vanadium. In yet other
embodiments, heavy metal contaminants can comprise iron, arsenic,
and vanadium. In some embodiments, heavy metal contaminants in
petroleum feedstock can comprise nickel, vanadium, copper, cadmium,
lead, chromium, iron, cobalt, cadmium, zinc, and mercury.
[0024] In some embodiments petroleum feedstock can comprise high
TAN petroleum feedstock. In other embodiments, petroleum feedstock
can comprise shale oil, bitumen, heavy oils, heavy crudes, and
other similar materials. In yet other embodiments, petroleum
feedstock can comprise shale oils such as those found in the Green
River Formation. In some embodiments, petroleum feedstock can
comprise bitumens such as those found in Alberta, Canada. In other
embodiments, petroleum feedstock can comprise heavy oils such as
those found in Venezuela. In yet other embodiments, petroleum
feedstock can comprise bitumens such as Athabasca bitumen found in
Northern Alberta, Canada.
[0025] In some embodiments, TAN values can comprise any substance
in a petroleum feedstock that contributes to total acid number. In
other embodiments, organic acids in a petroleum feedstock
contribute to TAN values. In yet other embodiments, organic acids
such as naphthenic acids in petroleum feedstock contribute to TAN
values. In other embodiments, TAN value is a measurement of acidity
of a petroleum feedstock as determined by the amount of potassium
hydroxide in milligrams that is needed to neutralize the acids in
one gram of the feedstock. In yet other embodiments, TAN value can
be calculated by potentiometric titration, color indicating
titration, spectroscopic methods, or combinations thereof. In some
embodiments, TAN value can be calculated by ASTM method D-664. In
other embodiments, a high TAN value can comprise values over 5. In
yet other embodiments, a high TAN value can comprise values over 3.
In some embodiments, a high TAN value can comprise values higher
than 1.
[0026] In some embodiments, petroleum feedstock comprises organic
acids. In other embodiments, the organic acids in petroleum
feedstock can comprise naphthenic acids. In other embodiments,
naphthenic acids can comprise a naphtha moiety with a carboxylic
acid group. In yet other embodiments, naphthenic acids can comprise
an unspecific mixture of carboxylic acids with five or six membered
carbon rings. In some embodiments, naphthenic acids can have a
molecular weight between about 120 to over 700 a.m.u. In other
embodiments, naphthenic acids can have a carbon backbone of between
about 9 to about 20 carbons. In yet other embodiments, naphthenic
acids in petroleum feedstock can cause corrosion known as
naphthenic acid corrosion.
[0027] In some embodiments, naphthenic acids in petroleum feedstock
can be decomposed. In other embodiments, naphthenic acids can be
decomposed by heating to generate a naphtha moiety, water and
carbon dioxide. In yet other embodiments, naphthenic acids can be
decomposed by heating under pressure to generate a naphtha moiety,
water and carbon dioxide. In some embodiments, during heating, the
pressure can be maintained to minimize the portion of the petroleum
feedstock that enters a vapor phase. In other embodiments, during
heating under pressure, a nonoxidizing gas can sweep the petroleum
feedstock to draw away generated water and/or water vapor. In yet
other embodiments, during heating under pressure, a nonoxidizing
gas can sweep the petroleum feedstock to draw away generated carbon
dioxide. In some embodiments, the generated water and/or water
vapor and/or carbon dioxide can be drawn into a headspace. In other
embodiments, the generated water and/or water vapor and/or carbon
dioxide can be bled from the headspace to promote decomposition of
the naphthenic acid. In yet other embodiments, the generated water
and/or water vapor and/or carbon dioxide can be bled from the
headspace to prevent inhibition of decomposition from a buildup of
decomposition products.
[0028] In some embodiments, the nonoxidizing gas can comprise any
inert gas that does not react with the petroleum feedstock. In
other embodiments, the nonoxidizing gas can comprise hydrogen,
light hydrocarbon gas, pyrolysis gas, fuel gas, nitrogen, or
combinations thereof. In yet other embodiments, light hydrocarbon
gas can comprise methane, ethane, propane, butane, pentane, hexane,
or combinations thereof. In some embodiments, light hydrocarbon gas
can comprise any hydrocarbon gas comprising between one and six
carbons.
[0029] In some embodiments, naphthenic acids can be decomposed by
heating the petroleum feedstock in the range of a lower
decomposition temperature of about 200.degree. C. and an upper
decomposition temperature of about 425.degree. C. In other
embodiments, the range can comprise a lower decomposition
temperature of about 300.degree. C. and an upper decomposition
temperature of about 400.degree. C. In yet other embodiments, the
range can comprise a lower decomposition temperature of about
232.degree. C. and an upper decomposition temperature of about
400.degree. C. In some embodiments, the range comprises a lower
decomposition temperature of about 260.degree. C. and an upper
decomposition temperature of about 385.degree. C. In other
embodiments, the lower decomposition temperature can be 200.degree.
C., 210.degree. C., 220.degree. C., 230.degree. C., 240.degree. C.,
250.degree. C., 260.degree. C., 270.degree. C., 280.degree. C., or
290.degree. C. In yet other embodiments, the upper decomposition
temperature can be 350.degree. C., 360.degree. C., 370.degree. C.,
380.degree. C., 390.degree. C., 400.degree. C., 410.degree. C.,
420.degree. C., 430.degree. C., 440.degree. C., 450.degree. C.,
460.degree. C., 470.degree. C., 480.degree. C., 490.degree. C., or
500.degree. C.
[0030] In some embodiments, naphthenic acids can be decomposed by
heating the petroleum feedstock under pressure in a pressure range
of a lower pressure limit of about one atmosphere and an upper
pressure limit of about 1000 psig. In other embodiments, the
pressure range can comprise a lower pressure limit of about 15 psig
and an upper pressure limit of about 500 psig. In yet other
embodiments, the pressure range can comprise a lower pressure limit
of about 30 psig and an upper pressure limit of about 300 psig. In
some embodiments, the lower pressure limit can be zero psig, 5
psig, 10 psig, 15 psig, 20 psig, 25 psig, or 30 psig. In some
embodiments, the upper pressure limit can be 300 psig, 400 psig,
500 psig, 600 psig, 700 psig, 800 psig, 900 psig, or 1000 psig.
[0031] In some embodiments, naphthenic acids can react with
alkaline earth oxides or hydroxides to generate alkaline earth
naphthenates. In other embodiments, naphthenic acids can react with
water and a stoichiometric excess of alkaline earth oxides or
hydroxides under heating to generate alkaline earth naphthenates.
Equations 2a-2b may describe this process where R is a naphtha
group, R' is another naphtha group, and Ae is an alkaline earth
element, and AeO is an alkaline earth oxide.
RCOOH+R'COOH+AeO.fwdarw.RCOOAeOOCR'.H.sub.2O Equation 2a
RCOOAeOOCR'.H.sub.2O.fwdarw.RCOOAeOOCR'+H.sub.2O Equation 2b
[0032] In some embodiments, Equation 2a may describe the formation
of a monohydrate salt of an alkaline earth naphthenate from
naphthenic acids and an alkaline earth oxide. In other embodiments,
an alkaline earth hydroxide can take the place of the alkaline
earth oxide. In yet other embodiments, the alkaline earth
naphthenate can comprise a coordination complex of naphthenate
groups complexed to the alkaline earth element. Equation 2b may
describe the formation of an anhydrous salt of an alkaline earth
naphthenate from the monohydrate salt.
[0033] In some embodiments, naphthenic acids can react with water
and a stoichiometric excess of alkaline earth oxides or hydroxides
to generate alkaline earth naphthenates by heating in the range of
a lower reaction temperature of about 80.degree. C. and an upper
reaction temperature of about 95.degree. C. In other embodiments,
the range can comprise a lower decomposition temperature of about
50.degree. C. and an upper decomposition temperature of about
150.degree. C. In yet other embodiments, the range can comprise a
lower reaction temperature of about 50.degree. C. and an upper
reaction temperature of about 400.degree. C. In some embodiments,
the lower reaction temperature can be 50.degree. C., 55.degree. C.,
60.degree. C., 65.degree. C., 70.degree. C., 75.degree. C., or
80.degree. C. In other embodiments, the upper reaction temperature
can be 90.degree. C., 95.degree. C., 100.degree. C., 105.degree.
C., 110.degree. C., 115.degree. C., 120.degree. C., 125.degree. C.,
130.degree. C., 135.degree. C., 140.degree. C., 145.degree. C.,
150.degree. C., 155.degree. C., 160.degree. C., or 165.degree.
C.
[0034] In some embodiments, alkaline earth naphthenates can be
heated to generate ketones. Equations 2c-2d may describe this
process where R is a naphtha group, R' is another naphtha group,
and Ae is an alkaline earth element, AeO is an alkaline earth
oxide, and AeCO.sub.3 is an alkaline earth carbonate:
RCOOAeOOCR'.fwdarw.RCOR'+AeCO.sub.3 Equation 2c
RCOOAeOOCR'.fwdarw.RCOR'+AeO+CO.sub.2 Equation 2d
[0035] Equation 2c may describe the formation of a ketone from the
anhydrous salt of an alkaline earth naphthenate with an alkaline
earth carbonate also produced. In some embodiments, the ketone may
be a ketone comprising two naphtha moieties. Equation 2d may
describe the formation of a ketone from the anhydrous salt of an
alkaline earth naphthenate with an alkaline earth oxide and carbon
dioxide also produced. In other embodiments, removal of the
alkaline earth carbonate, alkaline earth oxide, and/or carbon
dioxide can promote the ketonization reaction.
[0036] In some embodiments, alkaline earth naphthenates can be
heated to generate ketones in a range of a lower heating
temperature of about 100.degree. C. to an upper heating temperature
of about 400.degree. C. In other embodiments, the range can
comprise a lower heating temperature of about 166.degree. C. to an
upper heating temperature of about 312.degree. C. In some
embodiments, the lower reaction temperature can be 100.degree. C.,
110.degree. C., 120.degree. C., 130.degree. C., 140.degree. C.,
150.degree. C., 160.degree. C., 170.degree. C., 180.degree. C.,
190.degree. C., or 200.degree. C. In other embodiments, the upper
reaction temperature can be 290.degree. C., 300.degree. C.,
305.degree. C., 310.degree. C., 320.degree. C., 330.degree. C.,
340.degree. C., 350.degree. C., 360.degree. C., 370.degree. C.,
380.degree. C., 390.degree. C., or 400.degree. C.
[0037] In some embodiments, sulfur in the petroleum feedstock can
be reacted with an alkali metal and a radical capping gas to
convert the sulfur into alkali metal sulfides. In other
embodiments, sulfur in the petroleum feedstock can be reacted with
an alkali metal and a radical capping gas with heating to convert
the sulfur into alkali metal sulfides. In yet other embodiments,
sulfur in the petroleum feedstock can be reacted with an alkali
metal and a radical capping gas to convert the sulfur into alkali
metal sulfides according to the methods disclosed in U.S. Pat. Nos.
8,828,820 and 8,828,821 to Gordon. Equation 3 may describe this
process where S is a sulfur group, X is an first organic group, X'
is a second organic group, XSX' is an organic sulfur contaminant, H
is a radical capping gas, and A is an alkali element.
XSX'+2A+H.sub.2.fwdarw.A.sub.2S+HX+HX' Equation 3
[0038] In other embodiments, other reactions can describe reacting
sulfur in petroleum feedstock with an alkali metal and a radical
capping gas to convert the sulfur into alkali metal sulfides. In
yet other embodiments, the alkali metal can be added in
stoichiometric excess. In some embodiments, the radical capping gas
can be added in stoichiometric excess. In other embodiments,
reacting sulfur in petroleum feedstock with an alkali metal and a
radical capping gas to convert the sulfur into alkali metal
sulfides can further comprise a catalyst to help promote the
reaction. The catalysts may include by way of non-limiting example,
molybdenum, nickel, cobalt or alloys of molybdenum, alloys of
nickel, alloys of cobalt, alloys of molybdenum containing nickel
and/or cobalt, alloys of nickel containing cobalt and/or
molybdenum, molybdenum oxide, nickel oxide or cobalt oxides and
combinations thereof.
[0039] In some embodiments, reacting sulfur in petroleum feedstock
with an alkali metal and a radical capping gas to convert the
sulfur into alkali metal sulfides can be done with heating in the
range of a lower conversion temperature of about 150.degree. C. and
an upper conversion temperature of about 450.degree. C. In other
embodiments, the range can comprise a lower conversion temperature
of about 200.degree. C. and an upper conversion temperature of
about 400.degree. C. In yet other embodiments, the lower conversion
temperature can be 150.degree. C., 160.degree. C., 170.degree. C.,
180.degree. C., 190.degree. C., or 200.degree. C. In some
embodiments, the upper conversion temperature can be 400.degree.
C., 410.degree. C., 420.degree. C., 430.degree. C., 440.degree. C.,
450.degree. C., 460.degree. C., 470.degree. C., 480.degree. C.,
490.degree. C., or 500.degree. C. In other embodiments, reacting
sulfur in petroleum feedstock with an alkali metal and a radical
capping gas to convert the sulfur into alkali metal sulfides can be
carried out at a pressure greater than 250 psi. In yet other
embodiments, reacting sulfur in petroleum feedstock with an alkali
metal and a radical capping gas to convert the sulfur into alkali
metal sulfides can be carried out at a pressure below 2500 psi. In
some embodiments, reacting sulfur in petroleum feedstock with an
alkali metal and a radical capping gas to convert the sulfur into
alkali metal sulfides can be carried out at a pressure between
about 500 psi and about 3000 psi.
[0040] In some embodiments, the alkali metal can comprise lithium,
sodium, or potassium, or combinations thereof. In other
embodiments, the alkali metal can comprise alloys of lithium,
sodium, or potassium. In yet other embodiments, the alkali metal
may be molten to facilitate mixing with the petroleum feedstock. In
some embodiments, a powdered or other solid quantity of the alkali
metal can be introduced to the petroleum feedstock. Sodium is
preferred alkali metal because of its low cost, ready availability,
and ease of recovery and regeneration.
[0041] In some embodiments the radical capping gas can comprise a
hydrocarbon gas. In other embodiments, the radical capping gas can
comprise hydrogen gas. In yet other embodiments, radical capping
gas can comprise methane, ethane, propane, butane, pentane, hexane,
heptane, octane, ethene, propene, butene, pentene, hexene, heptane,
octene, and their isomers. In some embodiments, the radical capping
gas can comprise other hydrocarbons (such as octane, or other
carbon containing compounds containing one or more carbon atoms).
In other embodiments, the radical capping gas may comprise a
mixture of hydrocarbon gases. In yet other embodiments, the radical
capping gas may comprise natural gas or shale gas--the gas produced
by retorting oil shale. In some embodiments, the radical capping
gas may comprise one or more of the following: methane, ethane,
propane, butane, pentane, hexane, heptane, octane, ethene, propene,
butene, pentene, hexene, heptene, octene, and isomers of the
foregoing, natural gas, shale gas, liquid petroleum gas, ammonia,
primary, secondary, and tertiary ammines, thiols, mercaptans, and
hydrogen sulfide.
[0042] In some embodiments, alkali sulfide generated from the
petroleum feedstock can be processed to recover the elemental
alkali metal and sulfur. In other embodiments, recovery of
elemental alkali metal can comprise an electrolytic reaction
(electrolysis) of an alkali metal sulfide and/or polysulfide using
an alkali ion conductive ceramic membrane (such as, for example, a
NaSICON or LiSICON membrane that is commercially available from
Ceramatec, Inc. of Salt Lake City, Utah). In some embodiments,
processes for recovering elemental alkali metal can be found in
U.S. Pat. No. 3,787,315; U.S. Pat. No. 8,088,270; and U.S. Pat. No.
7,897,028 (which documents are incorporated herein by reference).
In yet other embodiments, the recovered elemental alkali metal can
be used to react with sulfur in the petroleum feedstock.
[0043] FIG. 1 illustrates a method 100 for treating petroleum
feedstock containing contaminants. In some embodiments, a petroleum
feedstock containing contaminants 102 can be transferred to a
decomposition reactor 110. A non-oxidizing gas 112 can sweep the
decomposition reactor 110. The decomposition reactor 110 can be
maintained at pressure to minimize an amount of the feedstock 102
that is in the vapor phase. The decomposition reactor 110 can be
maintained at a temperature between about 200.degree. C. and
425.degree. C. to decompose carboxylic acids. In some embodiments,
the carboxylic acids can comprise naphthenic acids. In other
embodiments, the decomposition reactor can be maintained at a
temperature between about 300.degree. C. and 400.degree. C. A gas
induction impeller can draw the non-oxidizing gas 112 through the
feedstock 102 to bubble through the feedstock to sweep water vapor
and carbon dioxide into the headspace. The headspace can be
continuously bled 114 to maintain water and carbon dioxide at
levels that are favorable to carboxylic acid decomposition. The
treated feedstock 116 can be transferred to an alkali metal reactor
120. In some embodiments, the temperature of the decomposition
reactor 110, the amount of non-oxidizing gas 112, the amount of
pressure maintained, and the speed and/or capacity of the gas
induction impeller can be varied to generate effective
decomposition of carboxylic acids. In other embodiments, the
temperature of the decomposition reactor 110, the amount of
non-oxidizing gas 112, the amount of pressure maintained, and the
speed and/or capacity of the gas induction impeller can be varied
to generate effective decomposition of carboxylic acids based on
the viscosity of the petroleum feedstock, the TAN values, and/or
the levels of contaminants.
[0044] In some embodiments, the treated feedstock 116 can be
transferred to the alkali metal reactor 120 to be further treated.
Radical capping gas 122 and alkali metal 124 can be added to the
alkali metal reactor 120. In other embodiments, radical capping gas
122 can comprise one or more of the following: methane, ethane,
propane, butane, pentane, hexane, heptane, octane, ethene, propene,
butene, pentene, hexene, heptene, octene, and isomers of the
foregoing, natural gas, shale gas, liquid petroleum gas, ammonia,
primary, secondary, and tertiary ammines, thiols, mercaptans, and
hydrogen sulfide. In yet other embodiments, radical capping gas 122
can comprise any suitable gas material. In some embodiments, alkali
metal 124 can comprise lithium, sodium, potassium, or combinations
thereof. In other embodiments, the sulfur contaminants in the
treated feedstock 116 can form alkali sulfides in the alkali metal
reactor 120. In yet other embodiments, the heavy metal contaminants
in the treated feedstock 116 can be changed in oxidation state to a
reduced metallic state. The alkali metal treated feedstock 126 can
be transferred to a solid-liquid separator 130.
[0045] In some embodiments, the alkali metal treated feedstock can
comprise one or more of decomposed carboxylic acids (and/or
decomposed naphthenic acids), alkali sulfides, and/or heavy metals
in a reduced metallic state. In other embodiments, one or more of
the decomposed carboxylic acids (and/or decomposed naphthenic
acids), alkali sulfides, and/or heavy metals in a reduced metallic
state can be in a solid and/or precipitated form. The solid-liquid
separator 130 can separate solids 132 from a liquid fraction 134.
The liquid fraction 134 can be transferred for further processing
140. In some embodiments, the solid-liquid separator 130 can
comprise filtration, centrifugation, and/or hydrocyclonic
separation. In other embodiments, the solid-liquid separator 130
can comprise gravimetric separation methods.
[0046] In some embodiments, the solids 132 can be transferred to
alkali regeneration 136. The alkali regeneration 136 can comprise
regenerating the alkali metal 124 from alkali sulfides or other
alkali salts. In other embodiments, alkali regeneration 136 can
comprise regenerating the alkali metal 124 by an electrolytic
process comprising an alkali ion conductive ceramic membrane. In
yet other embodiments, alkali regeneration 136 can comprise any
method or process suitable for regenerating alkali metal from
alkali sulfides or other alkali salts. In some embodiments,
regenerated alkali metal 128 can be transferred to the alkali metal
124 source for use in reactor 120.
[0047] FIG. 2 illustrates a method 200 for treating petroleum
feedstock containing contaminants. In some embodiments, a petroleum
feedstock containing contaminants 202 can be transferred to an
alkaline earth reactor 210. A quantity of water 212 can be added to
the alkaline earth reactor 210. A stoichiometric excess of an oxide
or a hydroxide of an alkaline earth element 214 can be added to the
alkaline earth reactor 210. The amount of water needed in the
process can be determined by Fourier Transform Infra Red analysis
looking for when the carbonyl peak is no longer detected. This
amount of water may be 1.5-5 times excess over the stoichiometric
amount needed. It is understood that the alkaline earth oxide or
hydroxide and water can be introduced into the reactor 210 as an
aqueous solution or slurry. It is also understood that less than
stoichiometric excess of an oxide or a hydroxide of an alkaline
earth element 214 can be added to the alkaline earth reactor 210
resulting in partial reduction in napthenic acid. In some
embodiments, a mixture of alkaline earth oxides and alkaline earth
hydroxides can be used. In other embodiments, alkaline earth oxides
can comprise magnesium oxide or calcium oxide. In yet other
embodiments, alkaline earth hydroxides can comprise magnesium
hydroxide or calcium hydroxide.
[0048] The alkaline earth reactor 210 can be maintained at a
temperature to facilitate the formation of alkaline earth
naphthenates. In one non-limiting embodiment, the temperature of
the alkaline earth reactor is maintained between about 50.degree.
C. and 150.degree. C. In other embodiments, the alkaline earth
reactor 210 can be maintained at a temperature between about
80.degree. C. and 95.degree. C. A mixer, an impellor, a stirrer or
other suitable device can be employed to facilitate formation of
alkaline earth naphthenates in the alkaline earth reactor 210. In
some embodiments, the temperature of the alkaline earth reactor
210, the amount of water 212 added, the amount of alkaline earth
oxide, the amount of alkaline earth hydroxide, an amount of
pressure maintained, and/or a speed and/or capacity of the mixer
can be varied to generate effective formation of alkaline earth
naphthenates.
[0049] In some embodiments, the treated feedstock 216 can be
transferred to a dewatering reactor 220. The dewatering reactor 220
can separate a dewatered treated feedstock 226 from a water
fraction 222. The dewatering reactor 220 can comprise any suitable
process for separating a dewatered treated feedstock 226 from a
water fraction 222. In some embodiments, the dewatering reactor 220
can comprise an evaporator or an electrostatic type dewatering
process. In some embodiments, the water fraction 222 can be
recycled and returned to the alkaline earth reactor 210.
[0050] In some embodiments, the dewatered treated feedstock 226 can
be transferred to an alkali metal reactor 230 to be further
treated. Radical capping gas 232 and alkali metal 234 can be added
to the alkali metal reactor 230. In other embodiments, radical
capping gas 232 can comprise one or more of the following: methane,
ethane, propane, butane, pentane, hexane, heptane, octane, ethene,
propene, butene, pentene, hexene, heptene, octene, and isomers of
the foregoing, natural gas, shale gas, liquid petroleum gas,
ammonia, primary, secondary, and tertiary ammines, thiols,
mercaptans, and hydrogen sulfide. In yet other embodiments, radical
capping gas 232 can comprise any suitable gas material. In some
embodiments, alkali metal 234 can comprise lithium, sodium,
potassium, or combinations thereof. In other embodiments, the
sulfur contaminants in the dewatered treated feedstock 226 can form
alkali sulfides in the alkali metal reactor 230. In yet other
embodiments, the heavy metal contaminants in the dewatered treated
feedstock 226 can be changed in oxidation state to a reduced
metallic state. In other embodiments, alkaline earth naphthenates
in the dewatered feedstock 226 can form ketones upon heating. In
some embodiments, reacting sulfur in petroleum feedstock with an
alkali metal and a radical capping gas to convert the sulfur into
alkali metal sulfides can be done with heating in the range of
about 150.degree. C. to about 450.degree. C. In other embodiments,
the temperature can range from about 200.degree. C. to about
400.degree. C. The alkali metal treated feedstock 236 can be
transferred to a solid-liquid separator 240.
[0051] In some embodiments, the alkali metal treated feedstock can
comprise one or more of alkaline earth naphthenates (and/or
naphthenate salts), alkaline earth carbonates, alkali sulfides,
and/or heavy metals in a reduced metallic state. In other
embodiments, one or more of the alkaline earth naphthenates (and/or
naphthenate salts), alkali sulfides, and/or heavy metals in a
reduced metallic state can be in a solid and/or precipitated form.
The solid-liquid separator 240 can separate solids 242 from a
liquid fraction 246. The liquid fraction 246 can be transferred for
further processing 250. In some embodiments, the solid-liquid
separator 240 can comprise filtration, centrifugation, and/or
hydrocyclonic separation. In other embodiments, the solid-liquid
separator 240 can comprise gravimetric separation methods.
[0052] In some embodiments, the solids 244 can be transferred to
regeneration cell 246. The regeneration cell 246 can comprise
equipment to regenerate the alkali metal 234 from alkali sulfides
or other alkali salts. In other embodiments, regeneration cell 246
can comprise an electrolytic process to regenerate the alkali metal
234 comprising an alkali ion conductive ceramic membrane. In yet
other embodiments, regeneration cell 246 can comprise any method or
process suitable for regenerating alkali metal 234 from alkali
sulfides or other alkali salts. In some embodiments, regenerated
alkali metal 248 can be transferred to the alkali metal 234 source
for use in reactor 230.
[0053] In other embodiments, alkaline earth carbonates can be
regenerated to form alkaline earth oxides or alkaline earth
hydroxides. In yet other embodiments, alkaline earth carbonates can
be regenerated to form alkaline earth oxides by heating the
alkaline earth carbonates in regeneration cell 246. In some
embodiments, regenerated alkaline earth oxides and/or alkaline
earth hydroxides can be returned 249 to the alkaline earth reactor
210. In other embodiments, if the alkali metal 234 comprises sodium
then the alkaline earth element comprises an alkaline earth metal
that is not reduced by sodium, such as calcium. In such cases,
magnesium would not be preferred because it is reduced by
sodium.
[0054] FIG. 3 illustrates a method and system 300 for treating
petroleum feedstock containing contaminants. In some embodiments, a
petroleum feedstock containing contaminants 302 can be transferred
to an alkaline earth reactor 310. A stoichiometric excess of an
oxide or a hydroxide of an alkaline earth element 312 in a water
solution or slurry can be added to the alkaline earth reactor 310.
In some embodiments, a mixture of alkaline earth oxides and
alkaline earth hydroxides can be used. In other embodiments,
alkaline earth oxides can comprise magnesium oxide or calcium
oxide. In yet other embodiments, alkaline earth hydroxides can
comprise magnesium hydroxide or calcium hydroxide. A quantity of
water 314 can be added to the alkaline earth reactor 310. It is
understood that the alkaline earth oxide or hydroxide and water can
be introduced into the reactor 310 as an aqueous solution or
slurry. It is also understood that less than stoichiometric excess
of an oxide or a hydroxide of an alkaline earth element 312 can be
added to the alkaline earth reactor 310 resulting in partial
reduction in napthenic acid
[0055] The alkaline earth reactor 310 can be maintained at a
temperature between about 50.degree. C. and 150.degree. C. to
facilitate the formation of alkaline earth naphthenates. In other
embodiments, the alkaline earth reactor can be maintained at a
temperature between about 80.degree. C. and 95.degree. C. A mixer,
stirrer or other suitable device can be employed to facilitate
formation of alkaline earth naphthenates in the alkaline earth
reactor 310. In some embodiments, the temperature of the alkaline
earth reactor 310, the amount of water 314 added, the amount of
alkaline earth oxide, the amount of alkaline earth hydroxide, an
amount of pressure maintained, and/or a speed and/or capacity of
the mixer can be varied to generate effective formation of alkaline
earth naphthenates.
[0056] In some embodiments, a treated feedstock from the alkaline
earth reactor 310 can be transferred to a dewatering reactor 320.
The dewatering reactor 320 can separate a dewatered treated
feedstock from a water fraction 322. In other embodiments, the
dewatering reactor 320 can comprise any suitable process for
separating a dewatered treated feedstock from a water fraction 322.
In some embodiments, the dewatering reactor 320 can comprise an
evaporator or an electrostatic type dewatering process. In yet
other embodiments, the water fraction 322 can be recycled and
returned to the alkaline earth reactor 310.
[0057] In some embodiments, the dewatered treated feedstock can be
transferred to a ketonization reactor 330. The ketonization reactor
330 can be maintained at a temperature between about 100.degree. C.
and 400.degree. C. to facilitate decomposition of alkaline earth
naphthenates to form ketones and alkaline earth oxides and/or
alkaline earth carbonates. In other embodiments, the alkaline earth
reactor 310 can be maintained at a temperature between about
166.degree. C. and about 312.degree. C. In some embodiments,
alkaline earth naphthenates can react in the ketonization reactor
330 to form ketones and/or ketones of naphthenates. A mixer,
stirrer or other suitable device can be employed to facilitate
formation of ketones in the ketonization reactor 330. In some
embodiments, a temperature of the ketonization reactor 330, an
amount of pressure maintained, and/or a speed and/or capacity of
the mixer can be varied to generate effective formation of
ketones.
[0058] In some embodiments, the feedstock from the ketonization
reactor 330 can be transferred to a first solid-liquid separator
340. In other embodiments, the feedstock from the ketonization
reactor 330 can comprise ketones, alkaline earth oxides, and/or
alkaline earth carbonates. In yet other embodiments, some or all of
the ketones, alkaline earth oxides, and/or alkaline earth
carbonates can be in a solid and/or precipitated form. The first
solid-liquid separator 340 can separate first solids 342 from a
first liquid fraction. In some embodiments, the solid-liquid
separator 340 can comprise filtration, centrifugation, and/or
hydrocyclonic separation. In other embodiments, the solid-liquid
separator 340 can comprise gravimetric separation methods.
[0059] In some embodiments, the first solids 342 can comprise
alkaline earth carbonates, alkaline earth oxides or alkaline earth
hydroxides. In some embodiments, alkaline earth carbonates can
undergo thermal decomposition to form alkaline earth oxides and
carbon dioxide. In yet other embodiments, alkaline earth carbonates
can be regenerated to form alkaline earth oxides by heating the
alkaline earth carbonates as part of a regeneration process. In
some embodiments, regenerated alkaline earth oxides and/or alkaline
earth hydroxides can be returned to the alkaline earth reactor
310.
[0060] In some embodiments, the first liquid fraction can be
transferred to an alkali metal reactor 350 to be further treated.
Radical capping gas 352 and alkali metal 354 can be added to the
alkali metal reactor 350. In other embodiments, radical capping gas
352 can comprise one or more of the following: methane, ethane,
propane, butane, pentane, hexane, heptane, octane, ethene, propene,
butene, pentene, hexene, heptene, octene, and isomers of the
foregoing, natural gas, shale gas, liquid petroleum gas, ammonia,
primary, secondary, and tertiary ammines, thiols, mercaptans, and
hydrogen sulfide. In yet other embodiments, radical capping gas 352
can comprise any suitable gas material. In some embodiments, alkali
metal 354 can comprise lithium, sodium, potassium, or combinations
thereof. In other embodiments, the sulfur contaminants in the first
liquid fraction can form alkali sulfides in the alkali metal
reactor 350. In yet other embodiments, the heavy metal contaminants
in the first liquid fraction can be changed in oxidation state to a
reduced metallic state. After reacting in the alkali metal reactor,
the alkali metal treated feedstock can be transferred to a second
solid-liquid separator 360.
[0061] In some embodiments, the alkali metal treated feedstock can
comprise one or more of alkali sulfides and optionally heavy metals
in a reduced metallic state. In yet other embodiments, one or more
of the alkali sulfides and heavy metals in a reduced metallic state
can be in a solid and/or precipitated form. The second solid-liquid
separator 360 can separate second solids from a second liquid
fraction. The second liquid fraction can be transferred for further
processing 370. In some embodiments, the solid-liquid separator 360
can comprise filtration, centrifugation, and/or hydrocyclonic
separation. In other embodiments, the solid-liquid separator 360
can comprise gravimetric separation methods.
[0062] In some embodiments, the second solids can be transferred to
regeneration cell 362. The regeneration cell 362 can comprise
equipment to regenerate the alkali metal 354 from alkali sulfides
or other alkali salts. In other embodiments, regeneration cell 362
can comprise an electrolytic process to regenerate the alkali metal
354 comprising an alkali ion conductive ceramic membrane. In yet
other embodiments, regeneration cell 362 can comprise any method or
process suitable for regenerating alkali metal 354 from alkali
sulfides or other alkali salts. In some embodiments, regenerated
alkali metal 354 can be returned to the alkali metal reactor 350.
In other embodiments, if the alkali metal 354 comprises sodium then
the alkaline earth element comprises an alkaline earth metal that
is not reduced by sodium, such as calcium. In such cases, magnesium
would not be preferred because it is reduced by sodium.
[0063] FIG. 4 illustrates a method and systems 400 for treating
petroleum feedstock containing contaminants. In some embodiments, a
petroleum feedstock containing contaminants 402 can be transferred
to an alkaline earth reactor 410. A stoichiometric excess of an
oxide or a hydroxide of an alkaline earth element 412 can be added
to the alkaline earth reactor 410. In some embodiments, a mixture
of alkaline earth oxides and alkaline earth hydroxides can be used.
In other embodiments, alkaline earth oxides can comprise magnesium
oxide or calcium oxide. In yet other embodiments, alkaline earth
hydroxides can comprise magnesium hydroxide or calcium hydroxide. A
quantity of water 414 can be added to the alkaline earth reactor
410. It is understood that the alkaline earth oxide or hydroxide
and water can be introduced into the reactor 410 as an aqueous
solution or slurry. It is also understood that less than
stoichiometric excess of an oxide or a hydroxide of an alkaline
earth element 412 can be added to the alkaline earth reactor 410
resulting in partial reduction in napthenic acid
[0064] The alkaline earth reactor 410 can be maintained at a
temperature between about 50.degree. C. and 150.degree. C. to
facilitate the formation of alkaline earth naphthenates. In other
embodiments, the alkaline earth reactor 410 can be maintained at a
temperature between about 80.degree. C. and 95.degree. C. A mixer,
stirrer or other suitable device can be employed to facilitate
formation of alkaline earth naphthenates in the alkaline earth
reactor 410. In some embodiments, the temperature of the alkaline
earth reactor 410, the amount of water 414 added, the amount of
alkaline earth oxide, the amount of alkaline earth hydroxide, an
amount of pressure maintained, and/or a speed and/or capacity of
the mixer can be varied to generate effective formation of alkaline
earth naphthenates.
[0065] In some embodiments, a treated feedstock from the alkaline
earth reactor 410 can be transferred to a dewatering reactor 420.
The dewatering reactor 420 can separate a dewatered treated
feedstock from a water fraction 422. In some embodiments, the
dewatering reactor 420 can comprise an evaporator or an
electrostatic type dewatering process. In other embodiments, the
dewatering reactor 420 can comprise any suitable process for
separating a dewatered treated feedstock from a water fraction 422.
In yet other embodiments, the water fraction 422 can be returned to
the alkaline earth reactor 410.
[0066] In some embodiments, the dewatered treated feedstock can be
transferred to an alkali metal reactor 430 to be further treated.
Radical capping gas 432 and alkali metal 434 can be added to the
alkali metal reactor 430. In other embodiments, radical capping gas
432 can comprise one or more of the following: methane, ethane,
propane, butane, pentane, hexane, heptane, octane, ethene, propene,
butene, pentene, hexene, heptene, octene, and isomers of the
foregoing, natural gas, shale gas, liquid petroleum gas, ammonia,
primary, secondary, and tertiary ammines, thiols, mercaptans, and
hydrogen sulfide. In yet other embodiments, radical capping gas 432
can comprise any suitable gas material. In some embodiments, alkali
metal 434 can comprise lithium, sodium, potassium, or combinations
thereof. In other embodiments, sulfur contaminants in the dewatered
treated feedstock can form alkali sulfides in the alkali metal
reactor 430. In yet other embodiments, heavy metal contaminants in
the dewatered treated feedstock can be changed in oxidation state
to a reduced metallic state. In some embodiments, alkaline earth
naphthenates can react in the alkali metal reactor 430 to form
ketones and/or ketones of naphthenates.
[0067] The alkali metal reactor 430 can be maintained at a
temperature between about 100.degree. C. and 400.degree. C. to
facilitate decomposition of alkaline earth naphthenates to form
ketones and alkaline earth oxides and/or alkaline earth carbonates.
In other embodiments, the alkali metal reactor 430 can be
maintained at a temperature between about 166.degree. C. and about
312.degree. C. In yet other embodiments, the alkali metal reactor
can first be heated to a temperature range to promote ketonization
of the alkaline earth naphthenates and then subsequently heated to
a temperature range to promote formation of alkali sulfides. In
some embodiments, a temperature range can be selected to promote
ketonization of the alkaline earth naphthenates and formation of
alkali sulfides.
[0068] After reacting in the alkali metal reactor, the alkali metal
treated feedstock can be transferred to a solid-liquid separator
440. In some embodiments, the alkali metal treated feedstock can
comprise one or more of ketones, alkaline earth naphthenates
(and/or naphthenate salts), alkaline earth oxides, alkaline earth
carbonates, alkali sulfides, and/or heavy metals in a reduced
metallic state. In other embodiments, the alkali metal treated
feedstock can comprise ketones, alkali sulfides and/or heavy metals
in a reduced metallic state. In yet other embodiments, one or more
of the alkali sulfides and/or heavy metals in a reduced metallic
state can be in a solid and/or precipitated form. The solid-liquid
separator 440 can separate solids from a liquid fraction. The
liquid fraction can be transferred for further processing 450. In
some embodiments, the solid-liquid separator 440 can comprise
filtration, centrifugation, and/or hydrocyclonic separation. In
other embodiments, the solid-liquid separator 440 can comprise
gravimetric separation methods.
[0069] In some embodiments, the solids can be transferred to
regeneration cell 442. The regeneration cell 442 can comprise
equipment to regenerate the alkali metal 434 from alkali sulfides
or other alkali salts. In other embodiments, regeneration cell 442
can comprise an electrolytic process to regenerate the alkali metal
434 comprising an alkali ion conductive ceramic membrane. In yet
other embodiments, regeneration cell 442 can comprise any method or
process suitable for regenerating alkali metal from alkali sulfides
or other alkali salts. In some embodiments, regenerated alkali
metal can be transferred to the alkali metal 434 source for use in
the alkali metal reactor 430. In other embodiments, if the alkali
metal 434 comprises sodium then the alkaline earth element
comprises an alkaline earth metal that is not reduced by sodium,
such as calcium. In such cases, magnesium would not be preferred
because it is reduced by sodium.
[0070] In yet other embodiments, the solids can comprise alkaline
earth oxides or alkaline earth hydroxides. In some embodiments,
alkaline earth carbonates can be regenerated to form alkaline earth
oxides or alkaline earth hydroxides. In yet other embodiments,
alkaline earth carbonates can be regenerated to form alkaline earth
oxides by heating the alkaline earth carbonates as part of a
regeneration process in regeneration cell 442. In some embodiments,
regenerated alkaline earth oxides and/or alkaline earth hydroxides
can be returned to the alkaline earth reactor 410.
[0071] The terms "a," "an," "the" and similar referents used in the
context of describing the invention (especially in the context of
the following claims) are to be construed to cover both the
singular and the plural, unless otherwise indicated herein or
clearly contradicted by context. Recitation of ranges of values
herein is merely intended to serve as a shorthand method of
referring individually to each separate value falling within the
range. Unless otherwise indicated herein, each individual value is
incorporated into the specification as if it were individually
recited herein. All methods described herein can be performed in
any suitable order unless otherwise indicated herein or otherwise
clearly contradicted by context. The use of any and all examples,
or exemplary language (e.g., "such as") provided herein is intended
merely to better illuminate the invention and does not pose a
limitation on the scope of the invention otherwise claimed. No
language in the specification should be construed as indicating any
non-claimed element essential to the practice of the invention.
[0072] It is contemplated that numerical values, as well as other
values that are recited herein are modified by the term "about",
whether expressly stated or inherently derived by the discussion of
the present disclosure. As used herein, the term "about" defines
the numerical boundaries of the modified values so as to include,
but not be limited to, tolerances and values up to, and including
the numerical value so modified. That is, numerical values can
include the actual value that is expressly stated, as well as other
values that are, or can be, the decimal, fractional, or other
multiple of the actual value indicated, and/or described in the
disclosure.
[0073] Groupings of alternative elements or embodiments of the
invention disclosed herein are not to be construed as limitations.
Each group member may be referred to and claimed individually or in
any combination with other members of the group or other elements
found herein. It is anticipated that one or more members of a group
may be included in, or deleted from, a group for reasons of
convenience and/or patentability. When any such inclusion or
deletion occurs, the specification is deemed to contain the group
as modified thus fulfilling the written description of all Markush
groups used in the appended claims.
[0074] Certain embodiments of this invention are described herein,
including the best mode known to the inventors for carrying out the
invention. Of course, variations on these described embodiments
will become apparent to those of ordinary skill in the art upon
reading the foregoing description. The inventor expects skilled
artisans to employ such variations as appropriate, and the
inventors intend for the invention to be practiced otherwise than
specifically described herein. Accordingly, this invention includes
all modifications and equivalents of the subject matter recited in
the claims appended hereto as permitted by applicable law.
Moreover, any combination of the above-described elements in all
possible variations thereof is encompassed by the invention unless
otherwise indicated herein or otherwise clearly contradicted by
context.
[0075] It is to be understood that the embodiments of the invention
disclosed herein are illustrative of the principles of the present
invention. Other modifications that may be employed are within the
scope of the invention. Thus, by way of example, but not of
limitation, alternative configurations of the present invention may
be utilized in accordance with the teachings herein. Accordingly,
the present invention is not limited to that precisely as shown and
described.
* * * * *