U.S. patent application number 14/102976 was filed with the patent office on 2014-06-19 for methods and compositions for removing 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 | 20140166537 14/102976 |
Document ID | / |
Family ID | 50929702 |
Filed Date | 2014-06-19 |
United States Patent
Application |
20140166537 |
Kind Code |
A1 |
Kremer; Lawrence N. ; et
al. |
June 19, 2014 |
METHODS AND COMPOSITIONS FOR REMOVING 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 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 solids
for subsequent separation of the 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.; (Richmond, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Baker Hughes Incorporated |
Houston |
TX |
US |
|
|
Assignee: |
Baker Hughes Incorporated
Houston
TX
|
Family ID: |
50929702 |
Appl. No.: |
14/102976 |
Filed: |
December 11, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61736659 |
Dec 13, 2012 |
|
|
|
Current U.S.
Class: |
208/14 ;
208/188 |
Current CPC
Class: |
C10G 33/04 20130101 |
Class at
Publication: |
208/14 ;
208/188 |
International
Class: |
C10G 33/04 20060101
C10G033/04 |
Claims
1. A method for separating at least a portion of solids from a
hydrocarbon fluid having 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 solids from
the hydrocarbon fluid; wherein the demulsifying agent water-wets at
least a portion of the 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 the adding of 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 solids from the hydrocarbon fluid.
6. The method of claim 5, further comprising mixing at least a
portion of the water-wet solids into the water phase of the
emulsion after separating at least a portion of the water-wet
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 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 solids are inorganic solids
selected from the group consisting of metal oxides, metal dioxides,
metal sulfides, metal sulfates, metal carbonates, sand, silt, clay,
paraffin wax, dolomite, coke fines, zinc compounds and combinations
thereof.
12. A method for separating at least a portion of 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 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 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 solids are inorganic solids
selected from the group consisting of metal oxides, metal dioxides,
metal sulfides, metal sulfates, metal carbonates, sand, silt, clay,
paraffin wax, dolomite, coke fines, zinc compounds and combinations
thereof.
17. The method of claim 12, wherein the at least one maleic acid
derivative is selected from the group comprising 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 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 solids within the hydrocarbon fluid, wherein the
plurality of solids are more water-wet as compared to a plurality
of 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
comprising 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 Provisional Patent
Application No. 61/736,659 filed Dec. 13, 2012, which is
incorporated by reference herein in its entirety.
TECHNICAL FIELD
[0002] The present invention relates to methods and compositions
for separating 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 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, and the like.
These solids 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.
[0005] 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 solids, or at least reducing their
presence, is necessary prior to further processing since these
solids would otherwise cause fouling and deposits in downstream
heat exchanger equipment and/or the 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 solids that stabilize the emulsion, and this poses
a problem for removal of a high level of solids by the desalter
alone.
[0006] It would be desirable if methods were devised that would at
least partially remove 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
[0007] There is provided, in one form, a method for separating at
least a portion of solids from a hydrocarbon stream having a
plurality of solids therein. A demulsifying agent may be added to
the hydrocarbon stream for subsequent separation of the solids from
the hydrocarbon stream in an effective amount to water-wet at least
a portion of the solids. The demulsifying agent may be or include,
but is not limited to, at least one maleic acid derivative.
[0008] There is further provided in another non-limiting
embodiment, a method for separating at least a portion of solids
from an oil phase of an oil/water emulsion having a plurality of
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 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 solids may then separate
from the oil phase of the emulsion for subsequent removal of the
solids.
[0009] 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 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 solids are more water-wet as
compared to a plurality of solids within a hydrocarbon stream in
the absence of the demulsifying agent.
[0010] The demulsifying agent appears to water-wet the solids in
such a way to allow the solids to separate from a hydrocarbon
stream or oil phase of an emulsion, and then the solids may be
removed or incorporated into a water phase.
DETAILED DESCRIPTION
[0011] 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 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
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 solids and thereby better separation of
the solids as well as other functions, such as but not limited to
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.
[0012] 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 solids
separation from a 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.
[0013] `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.
[0014] 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.
[0015] The solids may be or include inorganic solids, such as but
not limited to metal oxides, metal dioxides, metal sulfides, metal
sulfates, metal carbonates, 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), 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, sulfates,
and carbonates may be or include iron sulfides (e.g. FeS,
FeS.sub.2, Fe.sub.3S.sub.4) and the like. The size of the solids
may be less than about 0.45 microns, alternatively from about 0.1
microns independently to about 5 microns.
[0016] 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 2A1TM, which is supplied by Dow Chemical Company.
[0017] 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.
[0018] 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.
[0019] 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.
[0020] The 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 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 solids
from the emulsion and affects rapid coalescence of water and
preferentially water wets the solids. The water-wet solids are then
carried into the water phase of the emulsion, thereby providing a
reduced amount of solids within the hydrocarbon stream or oil phase
of the emulsion. The water and the water-wet solids may then be
removed for proper recovery of the hydrocarbon components with
fewer solids. Overall, removal of the solids prior to the injection
of the hydrocarbon stream causes fewer problems in the refinery and
other processing downstream.
[0021] 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 solids, and the water
containing the water-wet 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.
[0022] 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 solids to
water-wet by the demulsifying agent. In the instance of sludge
removal, the water-wet solids may settle to the bottom of the crude
storage tank under the influence of gravity.
[0023] A goal of the method is to reduce the 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 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 solids are separated using
the demulsifying agent than in the absence of the demulsifying
agent.
[0024] In one non-limiting embodiment, the methods described are
considered successful if a majority of the solids are separated,
i.e. greater than 50 wt %, alternatively from about 60 wt %
independently to about 90 wt % of the solids are separated, or from
about 80 wt % independently to about 90 wt % in another
non-limiting embodiment. By "separating" solids from the
hydrocarbon stream is defined herein to mean any and all
partitioning, sequestering, removing, transferring, eliminating,
dividing, removing, dropping out of the solids from the hydrocarbon
or crude oil to any extent.
[0025] 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 solids content, types of solids,
and/or size of 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.
[0026] 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 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.
[0027] 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.
[0028] Settling agents may also be useful in facilitating the
settling of various 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.
[0029] 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.
[0030] 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 solids from a hydrocarbon stream having 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 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.
[0031] 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 solids from a hydrocarbon stream having 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 solids.
[0032] 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 solids within the hydrocarbon stream where
the plurality of solids are more water-wet as compared to a
plurality of solids within the hydrocarbon stream in the absence of
the demulsifying agent.
[0033] 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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