U.S. patent application number 14/225027 was filed with the patent office on 2014-07-24 for methods and compositions for removing phosphorous-containing solids from hydrocarbon streams.
This patent application is currently assigned to BAKER HUGHES INCORPORATED. The applicant listed for this patent is BAKER HUGHES INCORPORATED. Invention is credited to Gerald O. Hoffman, Lawrence N. Kremer, Jerry J. Weers.
Application Number | 20140202923 14/225027 |
Document ID | / |
Family ID | 51206904 |
Filed Date | 2014-07-24 |
United States Patent
Application |
20140202923 |
Kind Code |
A1 |
Kremer; Lawrence N. ; et
al. |
July 24, 2014 |
METHODS AND COMPOSITIONS FOR REMOVING PHOSPHOROUS-CONTAINING SOLIDS
FROM HYDROCARBON STREAMS
Abstract
A demulsifying agent may be added to a hydrocarbon stream in an
effective amount where the hydrocarbon stream includes a plurality
of phosphorous-containing solids. The demulsifying agent may be
added to the hydrocarbon stream at a location that is upstream from
a desalter. The demulsifying agent may water-wet at least a portion
of the phosphorous-containing solids for subsequent separation of
the phosphorous-containing solids from the hydrocarbon stream. The
demulsifying agent may be or include but is not limited to at least
one maleic acid derivative, such as di-lauryl succinate, dioctyl
succinate, di-hexyl succinate, octyl pheno succinate, dodecyl
diphenyl succinate, ditridecyl succinate, dioctyl sulfosuccinate,
disodium laureth sulfosuccinate, diammonium 1-icosyl 2
sulfosuccinate, ammonium 1,4 didecyl sulfosuccinate, dihexyl sodium
sulfosuccinate, sodium dinonyl sulfosuccinate, sodium lauryl
sulfoacetate, salts thereof, and combinations thereof.
Inventors: |
Kremer; Lawrence N.; (The
Woodlands, TX) ; Hoffman; Gerald O.; (Houston,
TX) ; Weers; Jerry J.; (Richmand, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
BAKER HUGHES INCORPORATED |
Houston |
TX |
US |
|
|
Assignee: |
BAKER HUGHES INCORPORATED
Houston
TX
|
Family ID: |
51206904 |
Appl. No.: |
14/225027 |
Filed: |
March 25, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
14102976 |
Dec 11, 2013 |
|
|
|
14225027 |
|
|
|
|
61736659 |
Dec 13, 2012 |
|
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Current U.S.
Class: |
208/14 ;
208/188 |
Current CPC
Class: |
C10G 31/08 20130101;
C10G 33/04 20130101; C10G 53/02 20130101 |
Class at
Publication: |
208/14 ;
208/188 |
International
Class: |
C10G 21/22 20060101
C10G021/22 |
Claims
1. A method for separating at least a portion of
phosphorous-containing solids from a hydrocarbon fluid having
phosphorous-containing solids therein comprising: adding a
demulsifying agent to the hydrocarbon fluid in an effective amount
for subsequent separation of at least a portion of the
phosphorous-containing solids from the hydrocarbon fluid; wherein
the demulsifying agent water-wets at least a portion of the
phosphorous-containing solids; wherein the demulsifying agent
comprises at least one maleic acid derivative.
2. The method of claim 1, wherein the adding the demulsifying agent
occurs upstream from a desalter.
3. The method of claim 1, wherein the demulsifying agent further
comprises a second component selected from the group consisting of
naphthalene sulfonate, alkyl diphenyloxide disulfonate, and
combinations thereof.
4. The method of claim 1, wherein an emulsion comprises an oil
phase and a water phase; and wherein the oil phase comprises the
hydrocarbon fluid; and wherein in the adding of the demulsifying
agent, the demulsifying agent is added to a phase selected from the
group consisting of the oil phase, the water phase, and
combinations thereof.
5. The method of claim 4, further comprising separating at least a
portion of the water-wet phosphorous-containing solids from the
hydrocarbon fluid.
6. The method of claim 5, further comprising mixing at least a
portion of the water-wet phosphorous-containing solids into the
water phase of the emulsion after separating at least a portion of
the water-wet phosphorous-containing solids from the hydrocarbon
fluid.
7. The method of claim 1, wherein the at least one maleic acid
derivative is a C.sub.6-C.sub.18 sulfosuccinate.
8. The method of claim 1, wherein the at least one maleic acid
derivative is selected from the group consisting of di-lauryl
succinate, dioctyl succinate, di-hexyl succinate, octyl phenyl
succinate, dodecyl diphenyl succinate, ditridecyl succinate,
dioctyl sulfosuccinate, disodium laureth sulfosuccinate, diammonium
1-icosyl 2 sulfosuccinate, ammonium 1,4 didecyl sulfosuccinate,
dihexyl sodium sulfosuccinate, sodium dinonyl sulfosuccinate,
sodium lauryl sulfoacetate, salts thereof, and combinations
thereof.
9. The method of claim 1, wherein the effective amount of the
demulsifying agent ranges from about 0.1 ppm to about 200 ppm based
on the hydrocarbon fluid.
10. The method of claim 1, wherein the adding the demulsifying
agent is added to the hydrocarbon fluid at a location selected from
the group consisting of a crude storage tank, the suction of a
transfer pump for subsequent injection into a crude storage tank,
and combinations thereof.
11. The method of claim 1, wherein the phosphorous-containing
solids are selected from the group consisting of metal phosphates,
metal phosphites, metal phosphides, phosphonium containing solids,
organophosphates, organophosphites, and combinations thereof.
12. A method for separating at least a portion of
phosphorous-containing solids from an oil phase of an emulsion,
wherein the method comprises: adding a demulsifying agent to the
emulsion in an amount ranging from about 0.1 ppm to about 200 ppm
based on the emulsion; wherein the demulsifying agent water-wets a
plurality of phosphorous-containing solids within the emulsion;
wherein the demulsifying agent comprises at least one maleic acid
derivative; and wherein the demulsifying agent is added to the
emulsion at a location upstream from a desalter; and separating the
water-wet phosphorous-containing solids from the oil phase of the
emulsion.
13. The method of claim 12, wherein the demulsifying agent further
comprises a second component selected from the group consisting of
naphthalene sulfonate, alkyl diphenyloxide disulfonate, and
combinations thereof.
14. The method of claim 12, wherein the demulsifying agent is added
to the oil phase of the emulsion.
15. The method of claim 12, wherein the hydrocarbon stream is
selected from the group consisting of crude oil, asphalt, bitumen,
shale condensates, decant oil, and combinations thereof.
16. The method of claim 12, wherein the phosphorous-containing
solids are selected from the group consisting of metal phosphates,
metal phosphites, metal phosphides, phosphonium containing solids,
organophosphates, organophosphites, and combinations thereof.
17. The method of claim 12, wherein the at least one maleic acid
derivative is selected from the group consisting of di-lauryl
succinate, dioctyl succinate, di-hexyl succinate, octyl phenyl
succinate, dodecyl diphenyl succinate, ditridecyl succinate,
dioctyl sulfosuccinate, disodium laureth sulfosuccinate, diammonium
1-icosyl 2 sulfosuccinate, ammonium 1,4 didecyl sulfosuccinate,
dihexyl sodium sulfosuccinate, sodium dinonyl sulfosuccinate,
sodium lauryl sulfoacetate, salts thereof, and combinations
thereof.
18. A treated hydrocarbon fluid in a crude storage tank comprising:
a demulsifying agent comprising at least one maleic acid
derivative, wherein the amount of the demulsifying agent ranges
from about 0.1 ppm to about 30 ppm based on the hydrocarbon fluid;
and a plurality of water-wet phosphorous-containing solids within
the hydrocarbon fluid, wherein the plurality of
phosphorous-containing solids are more water-wet as compared to a
plurality of phosphorous-containing solids within the hydrocarbon
fluid in the absence of the demulsifying agent.
19. The treated hydrocarbon stream of claim 18, wherein the
demulsifying agent further comprises a second component selected
from the group consisting of naphthalene sulfonate, alkyl
diphenyloxide disulfonate, and combinations thereof.
20. The treated hydrocarbon stream of claim 18, wherein the at
least one maleic acid derivative is selected from the group
consisting of di-lauryl succinate, dioctyl succinate, di-hexyl
succinate, octyl phenyl succinate, dodecyl diphenyl succinate,
ditridecyl succinate, dioctyl sulfosuccinate, disodium laureth
sulfosuccinate, diammonium 1-icosyl 2 sulfosuccinate, ammonium 1,4
didecyl sulfosuccinate, dihexyl sodium sulfosuccinate, sodium
dinonyl sulfosuccinate, sodium lauryl sulfoacetate, salts thereof,
and combinations thereof.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims the benefit of U.S. patent
application Ser. No. 14/102,976 filed Dec. 11, 2013, which claims
the benefit of Provisional Patent Application No. 61/736659 filed
Dec. 13, 2012, all of which are incorporated by reference herein in
its entirety.
TECHNICAL FIELD
[0002] The present invention relates to methods and compositions
for separating phosphorous-containing solids from a hydrocarbon
stream, and more particularly relates, in one non-limiting
embodiment, to a demulsifying agent added to a hydrocarbon stream
for separating at least a portion of the phosphorous-containing
solids from the hydrocarbon stream where the demulsifying agent may
be or include at least one maleic acid derivative.
BACKGROUND
[0003] Hydrocarbon streams, such as crude oils, asphalt, bitumens,
etc typically carry varying amounts of solids within the
hydrocarbon stream. Additional solids from the sludge of a crude
storage tank may also be incorporated into the hydrocarbon stream
once the hydrocarbon stream enters the crude storage tank. The
solids and/or sludge include inorganic solids, paraffin wax, and
the like. Depending on the quality of the crude oils and the length
of time and/or whether the crude storage tank has been in storage,
the amount of solids may vary from about 20 pounds per thousand
barrels (ptb) to about 2500 ptb, or in the case of sludge, the
sludge accumulation may range from several centimeters to over one
meter deep. A layer of sludge typically forms at the bottom of a
crude storage tank as crude oil is discharged into the crude
storage tank and later discharged from the crude storage tank. This
sludge appears to be a complex emulsion stabilized by inorganic
and/or organic solids within the emulsion. The salty sludge is
picked up from the bottom of the crude storage tank by the velocity
of the crude oil. The specific gravity of the sludge within the
crude storage tank is lighter than water and is easily dispersed
into the hydrocarbon stream.
[0004] As noted, the sludge is a complex emulsion of hydrocarbon,
brine, and inorganic solids, and paraffin wax. The inorganic solids
may include iron oxides, sulfides, sand, silt, clay, phosphorous
containing compounds, and the like. The phosphorous-containing
compounds may arise from viscosifying a hydrocarbon fracturing
fluid in one non-limiting instance. A phosphate ester may be
neutralized by potassium hydroxide to be activated by an activator.
The activator may include iron sulfate, dibutyl amino ethanol, and
a phosphate surfactant, such as but not limited to, a phosphate
ester of ethoxylated dodecylalcohol, a polyoxyethylene
dinonylphenyl ether phosphate, and combinations thereof as
described in U.S. Pat. No. 6,004,908, which is herein incorporated
by reference in its entirety. The phosphate surfactants may be
ethyoxylated phosphate esters, and their alkali metal salts of mono
and disubstituted phenols.
[0005] Other inorganic solids, including phosphorous-containing
compounds, may arise from several sources, such as brine
contamination as a result of the brine associated with the oil in
the formation. Most minerals, clay, silt, and sand come from the
formation around the oil wellbore. The iron oxides and iron
sulfides are a result of corrosion during production, transport,
and/or storage of the crude oil. The sludge poses several problems,
such as reducing the volume of the working crude storage tank and
crude unit upsets. When the crude storage tank is taken off-line
for inspection and/or needs to be repaired, the sludge poses
additional concerns related to worker safety, environmental release
of the sludge, disposal costs, cost to remove the sludge, downtime,
etc.
[0006] Regardless of the source of the solids within the
hydrocarbon stream, several treatment approaches have been made to
reduce or remove the total amount of solids, but these have
traditionally centered on the removal of solids at the desalter
unit. Desalting or removing the phosphorous containing solids, or
at least reducing their presence, is necessary prior to further
processing since the phosphorous containing solids would otherwise
cause fouling and deposits in downstream heat exchanger equipment
and/or the phosphorous containing solids would be detrimental to
crude oil processing equipment. Effective crude oil desalting can
help minimize the effects of these contaminants on the crude unit
and downstream operations. However, some types of crude oil have
higher levels of phosphorous containing solids that stabilize the
emulsion, and this poses a problem for removal of a high level of
solids by the desalter alone.
[0007] It would be desirable if methods were devised that would at
least partially remove phosphorous containing solids from the
hydrocarbon stream prior to the injection of the hydrocarbon stream
into the desalter, which would allow for better efficiency and use
of the desalter.
SUMMARY
[0008] There is provided, in one form, a method for separating at
least a portion of phosphorous-containing solids from a hydrocarbon
stream having a plurality of phosphorous-containing solids therein.
A demulsifying agent may be added to the hydrocarbon stream for
subsequent separation of the phosphorous-containing solids from the
hydrocarbon stream in an effective amount to water-wet at least a
portion of the phosphorous-containing solids. The demulsifying
agent may be or include, but is not limited to, at least one maleic
acid derivative.
[0009] There is further provided in another non-limiting
embodiment, a method for separating at least a portion of
phosphorous-containing solids from an oil phase of an oil/water
emulsion having a plurality of phosphorous-containing solids
therein. A demulsifying agent may be added to the emulsion in an
amount ranging from about 0.1 ppm to about 30 ppm to water-wet at
least a portion of the phosphorous-containing solids. The
demulsifying agent may be or include at least one maleic acid
derivative. The demulsifying agent may be added to the emulsion at
a location upstream from a desalter. The water-wet
phosphorous-containing solids may then separate from the oil phase
of the emulsion for subsequent removal of the
phosphorous-containing solids.
[0010] In another non-limiting embodiment, a treated hydrocarbon
stream in a crude storage tank is described. The treated
hydrocarbon stream may include a plurality of water-wet
phosphorous-containing solids and a demulsifying agent. The
demulsifying agent may be or include, but is not limited to at
least one maleic acid derivative. The amount of the demulsifying
agent may range from about 0.1 ppm to about 30 ppm. The plurality
of water-wet phosphorous-containing solids are more water-wet as
compared to a plurality of phosphorous-containing solids within a
hydrocarbon stream in the absence of the demulsifying agent.
[0011] The demulsifying agent appears to water-wet the
phosphorous-containing solids in such a way to allow the solids to
separate from a hydrocarbon stream or oil phase of an emulsion, and
then the phosphorous-containing solids may be removed or
incorporated into a water phase.
DETAILED DESCRIPTION
[0012] It has been discovered that adding a chemical, such as a
demulsifying agent, as a pre-treatment or preconditioning for a
hydrocarbon stream when the chemical is added to the hydrocarbon
stream for better mixing of the demulsifying agent with the
hydrocarbon stream, and therefore better separation of the
phosphorous-containing solids by the time the hydrocarbon stream
reaches the desalter. The demulsifying agent may be added to a tank
having the hydrocarbon stream; alternatively, the demulsifying
agent may be added to the hydrocarbon stream at a location upstream
from a desalter. The chemical may be added directly to the desalter
for separating phosphorous-containing solids from the hydrocarbon
stream; however, the chemical has more contact time and therefore
better performance by the chemical when it is added as a
pre-treatment to the hydrocarbon stream upstream from the desalter.
Such a pre-treatment allows the chemical to have more contact time
with the phosphorous-containing solids and thereby better
separation of the phosphorous-containing solids as well as other
functions, such as but not limited to phosphorous-containing solids
wetting capabilities, better surface tension and improved oil-water
partition, etc. `Upstream from the desalter` means the demulsifying
agent may be added to the hydrocarbon stream at any point prior to
feeding the hydrocarbon stream into the desalter.
[0013] The added amount of time by using the chemical as a
pre-treatment instead of adding the chemical directly to a desalter
allows for improved resolution of micro-emulsions that can be
present within the hydrocarbon stream, as well as provide
phosphorous-containing solids separation from a
phosphorous-containing solids laden sludge that is carried with the
normal crude feed. Many potential secondary benefits include fewer
crude unit upsets, better desalter operation, less crude unit
preheat system fouling, improved crude unit corrosion control,
reduced water slugs, and combinations thereof. This type of
pre-treatment allows for reduced time for crude storage tank
maintenance, lower sludge disposal costs, and better quality raw
crude oil charged to the crude storage tank.
[0014] `Pre-treatment` is defined herein to mean that the chemical
is added to the hydrocarbon stream and the chemical rests with the
hydrocarbon stream for a specified amount of time prior to the
injection of the hydrocarbon stream into the desalter. For example,
the pre-treatment chemical may rest with the hydrocarbon stream for
a period of about 10 minutes independently to about 7 days prior to
the injection of the pre-treated hydrocarbon stream into the
desalter, alternatively from about 30 minutes independently to
about 5 days, or from about 30 minutes independently to about 120
hours. Similarly, a `pre-treated` hydrocarbon stream is defined
herein to be a hydrocarbon stream that has the chemical therein
where the chemical has rested with the hydrocarbon stream for a
period of time that falls within at least one of the given ranges
above. As used herein with respect to a range, "independently"
means that any lower threshold may be used together with any upper
threshold to give a suitable alternative range.
[0015] The hydrocarbon stream may be part of an oil-in-water
emulsion and/or a water-in-oil emulsion (hereinafter referred to as
the `emulsion`), and the demulsifying agent may be added to either
the oil phase, the water phase, or both of the emulsion. The amount
of water within the emulsion may be greater than 50 vol %, or range
from about 2 vol % independently to about 95 vol %, alternatively
from about 0.01 vol % independently to about 20 vol %. The
hydrocarbon stream may be or include, but is not limited to crude
oil, asphalt, bitumen, shale condensates, decant oil (also known as
treated slop oil), and combinations thereof. The types of crude oil
may be or include heavy Canadian crudes, bitumen, shale oils, heavy
Californian crudes, South American crudes, Russian crudes, topped
crudes, West Texas intermediate crude(WTI), and combinations
thereof. For example, specific crudes may include crudes produced
by Steam Assisted Gravity Drainage (SAGD) or PFT, Dillbit (diluted
bitumen also known as Synbit), and conventional crudes. `Heavy` as
used in the context of crudes is a crude that has an API gravity
less than about 30; API gravity is a measure of how heavy or light
a petroleum liquid is when compared to water.
[0016] The solids may be or include inorganic solids, such as but
not limited to metal oxides, metal dioxides, metal sulfides, metal
sulfates, metal carbonates, metal phosphorous-containing solids,
sand, silt, clay, paraffin wax, dolomite, coke fines, zinc
compounds and combinations thereof. Particular non-limiting
examples of the metal oxides may be or include iron oxides (FeO,
Fe.sub.2O.sub.3, Fe.sub.3O.sub.4, Fe.sub.2O.sub.3), copper oxides
(Cu.sub.2O and/or CuO), manganese oxides (MnO, Mn.sub.3O.sub.4,
Mn.sub.2O.sub.3, MnO.sub.2, and Mn.sub.2O.sub.7), calcium oxides,
magnesium oxides, zinc oxides, nickel oxides, and combinations
thereof; a non-limiting example of metal dioxides may be or include
titanium dioxide. Non-limiting examples of the sulfides may be or
include iron sulfides (e.g. FeS, FeS.sub.2, Fe.sub.3S.sub.4),
magnesium sulfides, calcium sulfides, and the like. In a
non-limiting embodiment, a phosphorous-containing solid may be an
inorganic solid, such as one described above, where at least a
portion of the inorganic solid is covered by a phosphate surfactant
(e.g. organophosphate).
[0017] Alternatively, the phosphorous-containing solids may be or
include inorganic solids, such as but not limited to metal
phosphates, metal phosphites, metal phosphides, phosphonium
containing solids, organophosphates (e.g. phosphate esters),
organophosphites, and combinations thereof. Phosphorous containing
solids are defined herein as a solid composition that includes
phosphorous in some form, as well as solids where a phosphorous
compound is physically or chemically attached to the solid. In the
instance of the phosphorous compound being attached to the solid,
the phosphorous compound may be an acid or other fluid phosphorous
containing compound, such as but not limited to an organic acid or
non-organic acid. Phosphonium containing solids are those
containing phosphonium salts where phosphorous is a cation as
opposed to an anion.
[0018] Particular non-limiting examples of the metal phosphates may
be or include iron phosphates (Fe.sub.3(PO.sub.4).sub.2,
FePO.sub.4), copper phosphates (Cu.sub.3(PO.sub.4).sub.2),
manganese phosphates (Mn.sub.3(PO.sub.4).sub.2) zinc phosphates
(Zn.sub.3(PO.sub.4).sub.2), nickel phosphates
(Ni.sub.2(PO.sub.4).sub.2), calcium phosphates, magnesium
phosphates, and combinations thereof; non-limiting examples of
metal phosphites may be or include iron phosphites (FePO.sub.3),
copper phosphites (Cu.sub.3PO.sub.3), manganese phosphites
(MnPO.sub.3), zinc phosphites (Zn.sub.3(PO.sub.3).sub.2), nickel
phosphites (Ni.sub.3(PO.sub.3).sub.2), calcium phosphites,
magnesium phosphites, and combinations thereof. Non-limiting
examples of the metal phosphides may be or include iron phosphides,
copper phosphides, manganese phosphides, zinc phosphides, nickel
phosphides, calcium phosphides, magnesium phosphides, and
combinations thereof. Other non-limiting examples of
phosphorous-containing compounds include hydroxyethylidene 1,1
diphosphonic acid (HEDP); and amino tris(methylene phosphonic acid)
(AMP); and mixtures thereof. The size of the phosphorous containing
solids may be less than about 0.45 microns, alternatively from
about 0.1 microns independently to about 5 microns.
[0019] The demulsifying agent may be injected into the hydrocarbon
stream as it enters into the crude storage tank, e.g. one injection
location may be the suction of the crude transfer pump or injection
pump, or the demulsifying agent may be added to the hydrocarbon
stream once the hydrocarbon stream is already in the crude storage
tank. The demulsifying agent may be or include, but is not limited
to maleic acid derivatives, which may be used in conjunction with
naphthalene sulfonates, alkyl diphenyloxide disulfonate, and
combinations thereof. The naphthalene sulfonates may have from 1
aromatic ring to 4 aromatic rings; alternatively, the naphthalene
sulfonate may have 2 aromatic rings. Non-limiting examples of the
naphthalene sulfonate include mono-alkyl substituted naphthalene
sulfonates, di-alkyl substituted naphthalene sulfonates (e.g.
di-isopropyl naphthalene sulfonate), methanolamine dibutyl
naphthalene sulfonate, sodium benzyl naphthalene sulfonate, and the
like. A non-limiting example of the alkyl diphenyloxide disulfonate
is Dowfax 2A1.TM., which is supplied by Dow Chemical Company.
[0020] In one non-limiting embodiment, at least one maleic acid
derivative may be used as the demulsifying agent; in one
non-limiting embodiment, two or more maleic acid derivatives may be
used as the demulsifying agent. The maleic acid derivative may be a
sulfosuccinate having a C.sub.6-C.sub.18 sulfosuccinate, and the
maleic acid derivative may be a sodium salt, an amine salt, a
potassium salt, an ammonium salt, and combinations thereof. Maleic
acid derivatives include, but are not necessarily limited to,
di-lauryl succinate, dioctyl succinate, di-hexyl succinate, octyl
pheno succinate, dodecyl diphenyl succinate, ditridecyl succinate,
dioctyl sulfosuccinate, disodium laureth sulfosuccinate, diammonium
1-icosyl 2 sulfosuccinate, ammonium 1,4 didecyl sulfosuccinate,
dihexyl sodium sulfosuccinate, sodium dinonyl sulfosuccinate,
sodium lauryl sulfoacetate, salts thereof, and combinations
thereof. In one non-limiting embodiment, the succinate may be a
sulfosuccinate. The maleic acid derivative may be used in
conjunction with an alkali salt, such as sodium, in one
non-limiting embodiment.
[0021] In one non-limiting embodiment, the demulsifying agent
includes at least one maleic acid derivative, e.g. dioctyl
sulfosuccinate, and at least one naphthalene sulfonate, even though
the maleic acid derivative is effective when used alone. Particular
ratios of the maleic acid derivative and the naphthalene sulfonate
that are beneficial range from about a 50/50 ratio of maleic acid
derivative to naphthalene sulfonate independently to about a 95/5
ratio of maleic acid derivative to naphthalene sulfonate.
Alternative ratios may include an 80/20 ratio of maleic acid
derivative to naphthalene sulfonate, a 90/10 ratio of maleic acid
derivative to naphthalene sulfonate, and the like.
[0022] A primary demulsifier may also be used with the demulsifying
agent to promote the activity by the demulsifying agent. The
primary demulsifier may be mixed with the demulsifying agent for
injection of the primary demulsifier at the same time as the
demulsifying agent. Alternatively, the primary demulsifier may be
injected at a different location altogether from the demulsifying
agent. As long as a primary demulsifier is used with the
demulsifying agent, regardless of whether it is injected at the
same time or a different time as the demulsifying agent, the
demulsifying agent will be capable of performing its functions.
Non-limiting examples of primary demulsifiers may be or include
alkoxylated resins, alkoxylated dipropylene glycols, maleic esters,
cross-linked alkoxylated resins, alkoxylated glycols, alkoxylated
glycerins, and trisaminoemethane alkoxylates, and combinations
thereof. However, the specific primary demulsifier to be used will
depend on the composition and amount of the demulsifying agent
used.
[0023] The phosphorous-containing solids may be suspended in the
hydrocarbon stream or oil phase of the emulsion. Adding the
demulsifying agent to the hydrocarbon stream or oil phase of the
emulsion allows for the demulsifying agent to rest with the
hydrocarbon stream and separate the phosphorous-containing solids
therefrom prior to the injection of the hydrocarbon stream into a
desalter, even if there is no sludge present in the crude storage
tank. The demulsifying agent destabilizes the
phosphorous-containing solids from the emulsion and affects rapid
coalescence of water and preferentially water wets the
phosphorous-containing solids. The water-wet phosphorous-containing
solids are then carried into the water phase of the emulsion,
thereby providing a reduced amount of phosphorous-containing solids
within the hydrocarbon stream or oil phase of the emulsion. The
water and the water-wet phosphorous-containing solids may then be
removed for proper recovery of the hydrocarbon components with
fewer phosphorous-containing solids. Overall, removal of the
phosphorous-containing solids prior to the injection of the
hydrocarbon stream causes fewer problems in the refinery and other
processing downstream.
[0024] One non-limiting example of this occurs in the crude storage
tank where the hydrocarbon stream or crude oil in the top of the
crude storage tank is sufficiently low in phosphorous-containing
solids, and the water containing the water-wet
phosphorous-containing solids may be drained from the crude storage
tank. Over a period of weeks to months, significant reductions in
sludge volume may be achieved. Exposure of the bottom sludge from
the crude storage tank to a crude oil treated with the demulsifying
agent slowly reduces the level of sludge in the crude storage
tank.
[0025] The introduction of the demulsifying agent into the
hydrocarbon stream by itself may be sufficient mixing, or there may
be an additional process for intentional mixing, such as a paddle
stirrer or the like as one non-limiting example. Subsequently, the
hydrocarbon stream is kept still or held quiescent in the crude
storage tank for enough time to allow or permit the
phosphorous-containing solids to become water-wet by the
demulsifying agent. In the instance of sludge removal, the
water-wet phosphorous-containing solids may settle to the bottom of
the crude storage tank under the influence of gravity.
[0026] A goal of the method is to reduce the phosphorous-containing
solids content in the hydrocarbon stream to an acceptable level for
the hydrocarbon stream to be processed in a refinery. Said
differently, complete separation of the phosphorous-containing
solids from the hydrocarbon stream is desirable, but it should be
appreciated that complete separation is not necessary for the
methods discussed herein to be considered effective. Success is
obtained if more phosphorous-containing solids are separated using
the demulsifying agent than in the absence of the demulsifying
agent.
[0027] In one non-limiting embodiment, the methods described are
considered successful if a majority of the phosphorous-containing
solids are separated, i.e. greater than 50 wt %, alternatively from
about 60 wt % independently to about 90 wt % of the
phosphorous-containing solids are separated, or from about 80 wt %
independently to about 90 wt % in another non-limiting embodiment.
By "separating" phosphorous-containing solids from the hydrocarbon
stream is defined herein to mean any and all partitioning,
sequestering, removing, transferring, eliminating, dividing,
removing, dropping out of the phosphorous-containing solids from
the hydrocarbon or crude oil to any extent.
[0028] In one non-limiting embodiment, the hydrocarbon stream would
be treated with the demulsifying agent until a predetermined target
concentration is reached. In another non-restrictive version, there
may be a fixed amount of time before the hydrocarbon stream must be
processed in the refinery. Thus, the dosage of the demulsifying
agent would be adjusted to accomplish yielding a hydrocarbon stream
with the necessary amount of phosphorous-containing solids content,
types of phosphorous-containing solids, and/or size of
phosphorous-containing solids threshold in the time required.
However, it should be realized that the exact dosage will be very
dependent upon the particular hydrocarbon stream and the needs of
the particular refinery. Optimum dosages will have to be developed
with experience and would be very difficult to predict in
advance.
[0029] The amount of the demulsifying agent may range from about
0.1 ppm independently to about 200 ppm, alternatively from about 2
ppm independently to about 100 ppm, or from about 3.5 ppm
independently to about 25 ppm in another non-limiting embodiment.
However, it is difficult to determine the exact amount of the
demulsifying agent to be added for optimum separation of the
phosphorous-containing solids from the hydrocarbon stream because
the amount depends on many variables, such as but not limited to
the type of results desired, the type of hydrocarbon stream being
processed, the amount of mixing, the temperature of the crude
storage tank, the amount of settling time, the geometry of the
crude storage tank, injection points, and constituency of the
emulsion, etc. For example, if the treated hydrocarbon stream is to
be stored in the crude storage tank for several hours, e.g. 10
hours, the treatment dosage of the demulsifying agent may be much
lower than the treatment dosage for a hydrocarbon stream that is to
be stored in a crude storage tank for about 3-5 hours. A higher
dosage may provide better resolution of the emulsion in a shortened
time period.
[0030] The amount of the demulsifying agent may also depend on the
rate at which it is injected into the hydrocarbon stream and/or the
crude storage tank. This amount may be adjusted as the crude flow
rate changes to assure the refiner that all of the hydrocarbon
stream receives the correct amount of demulsifying agent. One
method of doing this is to use a variable speed chemical injection
pump where a signal from an in-line flow sensor automatically
adjusts the chemical injection rate as the flow rate of the
hydrocarbon stream changes.
[0031] Settling agents may also be useful in facilitating the
settling of various phosphorous-containing solids to the bottom of
the crude storage tank. Suitable settling agents include, but are
not necessarily limited to alkyoxylated phenolic resins;
oxyalkylated polyamines, including, but not necessarily limited to
ethoxylated and/or propoxylated 1,2-ethanediamine,
N1-(2-aminoethyl)-N2-[2[(2-aminoethyl)amino]ethyl]-, and polymers
with 2-methyloxirane and oxirane; oxyalkylated alkanol amines,
including, but not necessarily limited to, ethoxylated and/or
propoxylated 1,3-propanediol,
2-amino-2-(hydroxymethyl)-1,3-propanediol, and again polymers with
2-methyloxirane and oxirane; Mannich reaction condensation products
of alkyl phenols and polyamines and mixtures thereof. Amines
suitable to make these settling agents may range from ethylene
diamine to tetraethylene pentamine or higher. Suitable alkyl
phenols for use in these settling agents may be those having one or
more R group substituent, where R may be defined from C1 to C36
linear, branched, cyclic alkyl groups and combinations of these.
The amounts of such settling agents may range from about 5 ppm
independently to about 1000 ppm; alternatively from about 50 ppm
independently to about 250 ppm.
[0032] Other additives may be added to the hydrocarbon stream
including, but not necessarily limited to, corrosion inhibitors,
demulsifiers, pH adjusters, metal chelants, scale inhibitors,
hydrocarbon solvents, and mixtures thereof. As noted, in one
non-limiting embodiment, the method is practiced ahead of a
refinery desalting process that involves washing the crude emulsion
with wash water.
[0033] The invention will be further described with respect to the
following Example, which is not meant to limit the invention, but
rather to further illustrate the various embodiments.
EXAMPLE
[0034] An alkoxylated phenol resin demulsifier was injected into a
hydrocarbon fluid stream, i.e. a continuously moving hydrocarbon
fluid, in an amount of 8 ppm. 6 ppm of a di-alkyl sulfo-succinate
and 1.5 ppm of naphthalene sulfonate was injected into the
hydrocarbon fluid, which was a West Texas Intermediate (WTI) crude
oil. Prior to treatment, the total amount of solids measured in the
effluent brine was about 8 pounds per thousand barrels (PTB), and
the amount of phosphorous was 0.76 ppm. After initiating treatment,
the total amount of solids measured in the effluent brine increased
to 30 PTB, and the amount of phosphorous was 1.92 ppm, which
indicated an increased removal of phosphorus from the crude
oil.
[0035] A greater amount of phosphorous present in the effluent
brine indicated an increased amount of phosphorous separated from
the crude oil. Thus, during the initial period of treatment, the
amount of phosphorous measured in the effluent brine increased from
about 0.76 ppm to about 1.92 ppm.
[0036] In the foregoing specification, the invention has been
described with reference to specific embodiments thereof, and has
been described as effective in providing methods and compositions
for separating phosphorous-containing solids from a hydrocarbon
stream having phosphorous-containing solids therein. However, it
will be evident that various modifications and changes can be made
thereto without departing from the broader spirit or scope of the
invention as set forth in the appended claims. Accordingly, the
specification is to be regarded in an illustrative rather than a
restrictive sense. For example, hydrocarbon streams, crude oils,
demulsifying agents, and phosphorous-containing solids falling
within the claimed parameters, but not specifically identified or
tried in a particular composition or method, are expected to be
within the scope of this invention.
[0037] The present invention may suitably comprise, consist or
consist essentially of the elements disclosed and may be practiced
in the absence of an element not disclosed. For instance, the
method may consist of or consist essentially of separating at least
a portion of phosphorous-containing solids from a hydrocarbon
stream having phosphorous-containing solids therein by adding a
demulsifying agent to the hydrocarbon stream in an effective
amount, where the demulsifying agent may be or include at least one
maleic acid derivative, and the demulsifying agent water-wets at
least a portion of the phosphorous-containing solids.
[0038] Alternatively, the composition may consist of or consist
essentially of a treated hydrocarbon stream in a crude storage tank
including, but not limited to a demulsifying agent comprising at
least one maleic acid derivative, in an amount ranging from about
0.1 ppm to about 200 ppm. The treated stream may further include a
plurality of water-wet phosphorous-containing solids within the
hydrocarbon stream where the plurality of phosphorous-containing
solids are more water-wet as compared to a plurality of
phosphorous-containing solids within the hydrocarbon stream in the
absence of the demulsifying agent.
[0039] The words "comprising" and "comprises" as used throughout
the claims, are to be interpreted to mean "including but not
limited to" and "includes but not limited to", respectively.
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