U.S. patent application number 11/292532 was filed with the patent office on 2007-06-07 for method for removing calcium from crude oil.
This patent application is currently assigned to General Electric Company. Invention is credited to David Birenbaum Engel, Alan E. Goliaszewski, Roger C. May.
Application Number | 20070125685 11/292532 |
Document ID | / |
Family ID | 37876965 |
Filed Date | 2007-06-07 |
United States Patent
Application |
20070125685 |
Kind Code |
A1 |
Goliaszewski; Alan E. ; et
al. |
June 7, 2007 |
Method for removing calcium from crude oil
Abstract
Methods for reducing calcium deposition along surfaces in
contact with the water phase of a resolved water/oil emulsion are
disclosed. High calcium crude oil and the like are contacted with a
sequestrant to form a sequestered calcium containing complex that
partitions to the water phase in the resolved emulsion. A
specifically formulated polymeric deposit control agent is added to
the water phase to inhibit calcium deposit formation therein and
along surfaces in contact with the water phase.
Inventors: |
Goliaszewski; Alan E.; (The
Woodlands, TX) ; Engel; David Birenbaum; (The
Woodlands, TX) ; May; Roger C.; (Warminster,
PA) |
Correspondence
Address: |
WEGMAN, HESSLER & VANDERBURG
6055 ROCKSIDE WOODS BOULEVARD
SUITE 200
CLEVELAND
OH
44131
US
|
Assignee: |
General Electric Company
Schenectady
NY
|
Family ID: |
37876965 |
Appl. No.: |
11/292532 |
Filed: |
December 2, 2005 |
Current U.S.
Class: |
208/251R |
Current CPC
Class: |
C10G 21/12 20130101;
C10G 29/20 20130101; C10G 21/27 20130101; C10G 53/02 20130101; C10G
53/10 20130101; C10G 53/04 20130101 |
Class at
Publication: |
208/251.00R |
International
Class: |
C10G 17/00 20060101
C10G017/00; C10G 45/00 20060101 C10G045/00 |
Claims
1. Method for reducing calcium content in a liquid
hydrocarbonaceous medium comprising: a. contacting said liquid
hydrocarbonaceous medium with a metal sequestering agent to form a
sequestered calcium containing complex; b. contacting said liquid
hydrocarbonaceous medium with an aqueous medium to form an emulsion
whereby upon resolution of said emulsion at least a portion of said
sequestered calcium containing complex remains in said aqueous
medium; and c. contacting said aqueous medium with a water soluble
or water dispersible polymer having the formula I to inhibit
calcium deposit formation therein or along surfaces in contact with
said aqueous medium, wherein said polymer has the formula: ##STR3##
wherein E is the repeat unit remaining after polymerization of an
ethylenically unsaturated compound; R.sub.1 is H or lower
(C.sub.1-C.sub.6) alkyl; G is lower (C.sub.1-C.sub.6) alkyl or
carbonyl; Q is O or NH; R.sub.2 is lower (C.sub.1-C.sub.6) alkyl;
hydroxy lower (C.sub.1-C.sub.6) alkyl, lower (C.sub.1-C.sub.6)
alkyl sulfonic acid -(Et-O)--.sub.n ---(iPr-O)--.sub.n or
--(Pr--O--).sub.n wherein n ranges from about 1 to 100 alkyl, and
R.sub.3 is H or XZ wherein X is an anionic radical selected from
the group consisting of SO.sub.3, PO.sub.3 or COO; Z is H or
hydrogens or any other water soluble cationic moiety which
counterbalances the valence of the anionic radical X; F, when
present, is a repeat unit having the Formula II: ##STR4## wherein X
and Z are the same as in Formula I; R.sub.4 is H or
(C.sub.1-C.sub.6) lower alkyl, R.sub.5 is a hydroxy substituted
alkyl or alkylene having from 1 to 6 atoms, and XZ may or may not
be present; c and d are positive integers, e is a non-negative
integer, and j is 0 or 1.
2. Method as recited in claim 1 wherein from about 1 to 300 ppm of
said polymer (I) is brought into contact with said aqueous medium,
based on one million parts of said aqueous medium.
3. Method a recited in claim 2 wherein from about 1 to 100 ppm of
said polymer (I) is brought into contact with said aqueous
medium.
4. Method as recited in claim 3 wherein said liquid
hydrocarbonaceous medium has a calcium content of greater than
about 30 ppm calcium based upon one million parts of said liquid
hydrocarbonaceous medium.
5. Method as recited in claim 4 wherein said liquid
hydrocarbonaceous medium is crude oil.
6. Method as recited in claim 5 wherein said metal sequestering
agent is citric acid or salt thereof and wherein said sequestered
calcium containing complex is calcium citrate.
7. Method as recited in claim 6 wherein said polymer I is a member
or members selected from the group consisting of 1) AA/AHPSE; 2)
AA/APES; 3) AA/AMPS; 4) AA/APES/AHPSE 5) AA/MA/APES 6)
AA/AMPS/APES
8. Method as recited in claim 7 wherein said polymer I is 1)
AA/AHPSE; 2) AA/APES; or 3) AA/AMPS
9. Method as recited in claim 8 wherein said polymer I is
AA/AHPSE.
10. Method as recited in claim 8 wherein said polymer I is
AA/APES.
11. Method as recited in claim 8 wherein said polymer I is
AA/AMPS.
12. Method as recited in claim 8 further comprising contacting said
emulsion with an emulsion breaker.
13. Method as recited in claim 12 further comprising adding a
corrosion inhibitor to said liquid hydrocarbonaceous medium or to
said aqueous medium.
14. Method as recited in claim 8 wherein said emulsion is heated to
a temperature of about 100.degree. F.-300.degree. F.
15. Method as recited in claim 14 wherein said resolution of said
emulsion is performed in a desalter apparatus.
16. Method as recited in claim 15 wherein n in Formula I is from 1
to 20 and X in Formula I is selected from Na, K, Ca, and
NH.sub.4.
17. A method for reducing calcium deposition along surfaces in
contact with a water phase formed as a result of resolution of an
emulsion in a petroleum refinery desalter of the type wherein crude
oil containing calcium therein is contacted with a sequestrant and
a water wash to form said emulsion having a sequestered calcium
complex in said emulsion, wherein at least a portion of said
sequestered calcium complex partitions to said water phase upon
said resolution, said method comprising contacting said sequestered
calcium complex with a water soluble or water dispersible polymer
having the Formula I: ##STR5## wherein E is the repeat unit
remaining after polymerization of an ethylenically unsaturated
compound; R.sub.1 is H or lower (C.sub.1-C.sub.6) alkyl; G is lower
(C.sub.1-C.sub.6) alkyl or carbonyl; Q is O or NH; R.sub.2 is lower
(C.sub.1-C.sub.6) alkyl; hydroxy lower (C.sub.1-C.sub.6) alkyl,
lower (C.sub.1-C.sub.6) alkyl sulfonic acid; -(Et-O)--.sub.n
--(iPr-O)--.sub.n or --(Pr--O--).sub.n wherein n ranges from about
1 to 100, and R.sub.3 is H or XZ wherein X is an anionic radical
selected from the group consisting of SO.sub.3, PO.sub.3 or COO; Z
is H or hydrogens or any other water soluble cationic moiety which
counterbalances the valence of the anionic radical X; F, when
present, is a repeat unit having the Formula II: ##STR6## wherein X
and Z are the same as in Formula I. R.sub.4 is H or
(C.sub.1-C.sub.6) lower alkyl, R.sub.5 is a hydroxy substituted
alkyl or alkylene having from 1 to 6 atoms, and XZ may or may not
be present; c and d are positive integers, e is a non-negative
integer, and j is 0 or 1.
18. Method as recited in claim 17 wherein said crude oil comprises
about 100 ppm calcium and greater.
19. Method is recited in claim 18 wherein said sequestrant is
citric acid and wherein said sequestered calcium complex is calcium
citrate, and wherein about 1 to 300 ppm of said polymer I is added
to said water phase based on one million parts of said water phase,
said polymer comprising a member or members selected from the group
consisting of 1) AA/AHPSE 2) AA/APES 3) AA/AMPS 4) AA/APES/AHPSE 5)
AA/MA/APES 6) AA/AMPS/APES
20. Method as recited in claim 19 wherein said polymer I is 1)
AA/AHPSE; 2) AA/APES; or 3) AA/AMPS.
21. Method as recited in claim 1 wherein said liquid
hydrocarbonaceous medium is crude oil produced at an oil production
site and wherein said steps (a) through (c) are performed proximate
said site.
Description
FIELD OF INVENTION
[0001] The invention pertains to improved methods for removing
calcium from a hydrocarbonaceous medium via extraction by a
sequestrant. The sequestrant, when added to the hydrocarbonaceous
medium, results in the formation of a calcium complex that
partitions to the water phase as the hydrocarbonaceous medium is
brought in contact with an aqueous wash phase. A specifically
formulated deposit control agent is brought into contact with the
water phase to control calcium based deposit formation.
BACKGROUND OF THE INVENTION
[0002] All crude oil contains impurities which contribute to
corrosion, heat exchanger fouling, furnace coking, catalyst
deactivation, and product degradation in refinery and other
processes. These contaminants are broadly classified as salts,
bottom sediment, and water (BS+W), solids, and metals. The amounts
of these impurities vary, depending upon the particular crude.
Generally, crude oil salt content ranges between about 3-200 pounds
per 1,000 barrels (ptb).
[0003] Brines present in crude include predominately sodium
chloride with lesser amounts of magnesium chloride and calcium
chloride being present. Chloride salts are predominantly the source
of highly corrosive HCl, which is severely damaging to refinery
tower trays and other equipment. Additionally, carbonate and
sulfate salts may be present in the crude in sufficient quantities
to promote crude preheat exchanger scaling.
[0004] Solids other than salts are equally harmful. For example,
sand, clay, volcanic ash, drilling muds, rust, iron sulfide, metal,
and scale may be present and can cause fouling, plugging, abrasion,
erosion and residual product contamination. As a contributor to
waste and pollution, sediment stabilizes emulsions in the form of
oil-wetted solids and can carry significant quantities of oil into
the waste recovery systems.
[0005] Metals in crude may be inorganic or organometallic compounds
which consist of hydrocarbon combinations with arsenic, vanadium,
nickel, copper, and iron. These materials promote fouling and can
cause catalyst poisoning in subsequent refinery processes, such as
catalytic cracking methods, and they may also contaminate finished
products. The majority of the metals carry as bottoms in refinery
processes. When the bottoms are fed, for example, to coker units,
contamination of the end-product coke is most undesirable. For
example, in the production of high grade electrodes from coke, iron
contamination of the coke can lead to electrode degradation and
failure in processes, such as those used in the chlor-alkali
industry.
[0006] Desalting is, as the name implies, a process that is adapted
to remove primarily inorganic salts from the crude prior to
refining. The desalting step is provided by adding and mixing with
the crude a few volume percentages of fresh water to contact the
brine and salt. In crude oil desalting, a water in oil (W/O)
emulsion is intentionally formed with the water admitted being on
the order of about 4-10 volume % based on the crude oil. Water is
added to the crude and mixed intimately to transfer impurities in
the crude to the water phase. Separation of the phases occurs due
to coalescence of the small water droplets into progressively
larger droplets and eventual gravity separation of the oil and
underlying water phase.
[0007] Demulsification agents are added, usually upstream from the
desalter, to help in providing maximum mixing of the oil and water
phases in the desalter, and gently increase the speed of water
break. Known demulsifying agent include water soluble salts,
sulfonated glycerides, sulfonated oils, alkoxylated phenol
formaldehyde resins, polyols, copolymers of ethylene oxide and
propylene oxide, a variety of polyester materials, and many other
commercially available compounds.
[0008] Desalters are also commonly provided with electrodes to
impart an electrical field in the desalter. This serves to polarize
the dispersed water molecules. The so-formed dipole molecules exert
an attractive force between oppositely charged poles with the
increased attractive force increasing the speed of water droplet
coalescence by from ten to one hundred fold. The water droplets
also move quickly in the electrical field, thus promoting random
collisions that further enhance coalescence.
[0009] Upon separation of the phases from the W/O emulsions, the
crude is commonly drawn off the top of the desalter and sent to the
fractionator tower in crude units or other refinery processes. The
water phase may be passed through heat exchanges or the like and
ultimately is discharged as effluent.
[0010] Calcium removal has become an important concern over the
last few years due to increasing use of crudes with very high
levels of calcium (such as some from the African continent that
contain over 200 ppm, and some nearly 400 ppm of calcium).
Previously, the highest calcium content was only 50 ppm. Extraction
of the calcium salts via the desalting process is stymied when the
calcium is associated with naphthenic acids (high TAN (Total Acid
Number) crudes). These calcium naphthenates are not water extracted
and stay with the oil phase. Problems for the refiners associated
with high calcium include exceeding metal specs for fuels oils that
have resids blended in, poisoning catalysts for residual catalytic
crackers, adversely affecting coke specs for metals, and
contributing to crude unit fouling and delayed coker furnace
fouling.
[0011] Several methods have been disclosed for the removal of
calcium from crude oil, essentially using the desalter. All involve
the use of organic carboxylic acids (supposedly to protonate the
naphthenic acids and extract the calcium into the wash water).
Reynolds (U.S. Pat. No. 4,778,589) teaches the use of
hydroxycarboxylic acids, such as citric acid, added to the wash
water to effect the calcium extraction in the desalter. Roling
(U.S. Pat. No. 5,078,858) improved on this process by the addition
of citric acid to the crude oil phase for enhanced extraction rates
of metals. Both patents discuss the modification of the wash water
pH for better extraction. Lindemuth (U.S. Pat. No. 5,660,717)
describes the use of functionalized polymers of acrylic acid for
cation removal. Nguyen (U.S. Published Patent Application
2004/0045875) describes the use of alpha-hydroxy carboxylic acid
(particularly glycolic acid) for the removal of calcium and
amines.
[0012] The method of Reynolds, while likely successful at the
extraction of low levels of calcium (<30 ppm), has two
significant drawbacks which make it impractical for use with the
high calcium crudes. One is that since the extraction process is
stoichiometric, at the high levels of citric acid needed in the
wash water, its pH drops significantly (to below 3) and causes a
corrosion issue in the wash water circuit. This can be alleviated
by the use of corrosion inhibitors.
[0013] A second concern is that the concentration of the resultant
calcium citrate has a solubility limitation of approximately 1000
ppm at room temperature, and pH of 6-8 with solubility inversely
correlated with temperature. Thus, one can see that deposition of
calcium citrate is an issue at typical desalter temperatures
(250.degree. F.-300.degree. F.) and concentrations encountered when
extracting higher levels of calcium with the typical 5% wash water
rate. In fact, both of these concerns were verified through field
experience with citric acid at a refinery processing significant
levels of a high calcium crude. Deposition in the brine heat
exchanger and transfer piping was one of the problems that was
experienced.
SUMMARY OF THE INVENTION
[0014] The invention pertains to a combination of treatment
chemistries to overcome the deficiencies of the Reynolds patent. In
one aspect, the invention pertains to the use of a sequestrant to
effect sequestration of the calcium from the hydrocarbonaceous
medium to the water phase of the W/O emulsion combined with contact
of the water phase by a specifically formulated deposited control
polymer to thereby inhibit the formation of calcium based scales
and deposits in the water phase and along refinery system surfaces
in contact with the water phase. Examples of such surfaces include
drains, drain lines, desalter vessels, mix valves, static mixers,
and heat exchangers that are in contact with the brine (i.e., water
phase).
[0015] In a more specific aspect of the invention, citric acid or
its salts are used as the sequestrant, and the sequestered calcium
containing complex is calcium citrate. The deposit control polymer
inhibits calcium citrate scale formation in the water phase and
along surfaces that contact the water phase. While calcium citrate
scale control is important, the treatment should also not adversely
affect desalter operation (longer water drop rates, etc.).
DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS
[0016] Although the present invention is primarily described in
conjunction with its use in a conventional desalter operation, the
artisan will appreciate that other extraction techniques will also
benefit from the invention. One example is countercurrent
extraction, wherein an aqueous phase is brought into contact with
an oppositely flowing hydrocarbonaceous medium.
[0017] Further, although the invention is particularly advantageous
in removing calcium from crude oil, the phrase "liquid
hydrocarbonaceous medium" should be construed to include other
media such as bitumens, atmospheric or vacuum residia or solvent
deasphalted oils derived from crudes and residua that are
hydroprocessed or cracked into useable products such as gas oils,
gasolines, diesel fuel, and shale oil, liquefied coal, beneficiated
tar sand, etc. Also, emulsions including such hydrocarbonaceous
media or any hydrocarbonaceous product are included within the
ambit of this phrase.
[0018] High calcium containing crudes are, as used herein, crudes
containing greater than about 30 ppm calcium therein relative to
one million parts of the crude or other liquid hydrocarbonaceous
media. The invention will be particularly beneficial to those
crudes having greater than about 100 ppm calcium and higher.
[0019] Also, the phrase "sequestered calcium containing complex" as
used throughout the specification and claims covers a host of
chelated, complexed, or sequestered complexes or ligands, or other
species including ionic or covalent compounds in which calcium is
extracted from the oil phase and, at least in part, partitions to
the water phase in a desalter or other extraction process. For
example, when citric acid or one of its salt forms is used as the
sequestering agent, calcium citrate is the resulting sequestered
calcium containing complex that at least partially partitions to
the water phase upon resolution of the W/O emulsion.
[0020] As to the sequestrants that are to be added either to the
oil phase or water phase to contact the high calcium crude, these
are fed in at least stoichiometric amounts relative to the moles of
calcium in the crude. Exemplary sequestrants include the carboxylic
acid sequestrants with more preferred sequestrants including those
containing plural COOH functionality such as the dibasic carboxylic
acids including oxalic, malonic, succinic, maleic, and adipic acid.
Most preferred are the hydroxycarboxylic acids such as citric and
tartaric acids and their salts.
[0021] In one exemplary embodiment of the invention, the liquid
hydrocarbon medium is intimately and thoroughly mixed with an
aqueous solution of citric acid or its salt. The calcium in the
liquid hydrocarbon combines with the sequestrant to form a water
soluble or dispersible complex in the aqueous phase. A deposit
control polymer I, as described hereinafter, is brought into
contact with the complex, such as by adding it to the water phase.
The aqueous phase and hydrocarbon phase separate upon resolution of
the W/O emulsion, with the separated hydrocarbon phase being
available for distillation or hydroprocessing.
[0022] Turning now to the copolymer and terpolymers that are used
to inhibit calcium based scale and deposit formation, these are
represented by the following Formula I: ##STR1## wherein E is the
repeat unit remaining after polymerization of an ethylenically
unsaturated compound; preferably a carboxylic acid, sulfonic acid,
phosphonic acid, or amide form thereof; R.sub.1 is H or lower
(C.sub.1-C.sub.6) alkyl; G is lower (C.sub.1-C.sub.6) alkyl or
carbonyl; Q is O or NH; R.sub.2 is lower (C.sub.1-C.sub.6) alkyl;
hydroxy lower (C.sub.1-C.sub.6) alkyl, lower (C.sub.1-C.sub.6)
alkyl sulfonic acid, -(Et-O)--.sub.n, -(iPr-O)--.sub.n or
--(Pr--O)--.sub.n wherein n ranges from about 1 to 100, preferably
1 to 20, and R.sub.3 is H, or XZ wherein X is an anionic radical
selected from the group consisting of SO.sub.3, PO.sub.3 or COO; Z
is H or hydrogens or any other water soluble cationic moiety which
counterbalances the valence of the anionic radical X, including but
not limited to Na, K, Ca, NH.sub.4; j is 0 or 1.
[0023] F, when present, is a repeat unit having the Formula II:
##STR2## wherein X and Z are the same as in Formula I. R.sub.4 is H
or (C.sub.1-C.sub.6) lower alkyl, R.sub.5 is a hydroxy substituted
alkyl or alkylene radical having from 1 to 6 atoms, and XZ may or
may not be present.
[0024] Subscripts c, d, and e in Formula I are the molar ratio of
the monomeric repeating unit. The ratio is not critical to the
present invention provided that the copolymer or terpolymer is
water soluble or water dispersible. Subscripts c and d are positive
integers, while subscript e is a non-negative integer. That is, c
and d are integers of 1 or more, while e can be 0, 1, 2, etc.
[0025] With respect to E of Formula I, it may comprise the repeat
unit obtained after polymerization of a carboxylic acid, sulfonic
acid, phosphonic acid, or amide form thereof or mixtures thereof.
Exemplary compounds include but are not limited to the repeat unit
remaining after polymerization of acrylic acid, methacrylic acid,
acrylamide, methacrylamide, N-methyl acrylamide, N,N-dimethyl
acrylamide, N-isopropylacrylamide, maleic acid or anhydride,
fumaric acid, itaconic acid, styrene sulfonic acid, vinyl sulfonic
acid, isopropenyl phosphonic acid, vinyl phosphonic acid,
vinylidene di-phosphonic acid, 2-acrylamido-2-methylpropane
sulfonic acid and the like and mixtures thereof. Water-soluble salt
forms of these acids are also within the purview of the present
invention. More than one type of monomer unit E may be present in
the polymer of the present invention.
[0026] Exemplary copolymers and terpolymers encompassed by the
formula include: [0027] 1) acrylic acid/allyl-2-hydroxy propyl
sulfonate ether, (i.e., AA/AHPSE); [0028] 2) acrylic acid/allyl
polyethyleneoxide sulfate ether, (i.e., AA/APES); [0029] 3) acrylic
acid/2-acrylamido-2-methyl-1-propane sulfonic acid, (i.e.,
AA/AMPS); [0030] 4) acrylic acid/ammonium allylpolyethoxy
sulfate/alloxy-2-hydroxypropane-3-sulfonic acid terpolymer (i.e.,
AA/APES/AHPSE); [0031] 5) acrylic acid/methacrylic acid/ammonium
allylpolyethyoxy (10) sulfate terpolymers (i.e., AA/MA/APES);
[0032] 6) acrylic acid/2-acrylamido-2-methylpropane sulfonic
acid/ammonium allylpolyethoxy sulfate terpolymers (i.e.,
AA/AMPS/APES).
[0033] The polymerization of the copolymer and/or terpolymer (I)
may proceed in accordance with solution, emulsion, micelle or
dispersion polymerization techniques. Conventional polymerization
initiators such as persulfates, peroxides, and azo type initiators
may be used. Polymerization may also be initiated by radiation or
ultraviolet mechanisms. Chain transfer agents including alcohols,
such as isopropanol or allyl alcohol, amines, mercapto compounds or
hypophosphorous acid may be used to regulate the molecular weight
of the polymer. One particularly preferred method is to employ
hypophosphorous acid as the chain transfer agent in amount such
that a small portion thereof remains in the polymer backbone (i.e.,
from about 0.01-5 wt %). Branching agents, such as methylene
biscrylamide, or polyethylene glycol diacrylate and other
multifunctional crosslinking agents may be added. The resulting
polymer may be isolated by precipitation or other well-known
techniques. If polymerization is in the aqueous solution, the
polymer may simply be used in the aqueous solution form.
[0034] The molecular weight of the water-soluble copolymer of
Formula I is not critical but preferably falls within the range Mw
of about 1,000 to 1,000,000; more preferably, from about 1,000 to
50,000 and most preferably from about 1,500 to 25,000. The
essential criteria is that the polymer be water-soluble or water
dispersible.
[0035] The metal sequestering agent may be brought into contact
with the liquid hydrocarbon medium either by adding the sequestrant
to the liquid hydrocarbon medium or to the water wash in the
desalter. As above indicated, contact of the hydrocarbon medium
with the sequestrant forms a sequestered calcium containing complex
that, at least in part, partitions to the water phase upon
resolution of the water in oil emulsion in the desalter or other
extraction process.
[0036] The polymer I may be brought into direct contact with the
resolved water phase or it can be intimately dispersed in the
hydrocarbon medium so as to effect contact with the aqueous phase
upon the mixing of the liquid hydrocarbon medium and the aqueous
medium in the desalter. From about 1-300 ppm of the polymer are
admitted based upon one million parts of the water phase. More
preferably, from about 1-100 ppm of polymer I are admitted to the
aqueous medium.
[0037] As in conventional desalter apparatuses, the emulsion may be
heated to about 100.degree. F.-300.degree. F., an and electrical
potential may be impressed across the emulsion to enhance the
separation. Utilization of the polymer I helps to inhibit calcium
based deposition or scale that would otherwise form in the water
phase or along surfaces in contact therewith, such as drains,
conduit lines, brine heat exchangers, desalter vessel, mix valves,
static mixers, and the like.
[0038] As mentioned, the removal of salts and solids from crude oil
is traditionally performed at a refinery site that has installed
the appropriate equipment for washing the crude oil with water
(i.e., the desalter). Oil production sites generally only have
separation equipment to separate native or produced water and leave
the final salts removal to the refineries. In accordance with the
invention, salt removal can also be advantageously performed at the
site of the oil production. This may involve installation of
equipment such as desalters, but would result in a uniform
improvement of the produced oil and generation of a higher value
product.
[0039] Conventional emulsion breakers may be added to the crude so
as to enhance resolution of the emulsion. These emulsion breakers
are, in most part, surfactants that migrate to the oil/water
interface and alter the surface tension of the interfacial layer
allowing droplets of water or oil to coalesce more readily. These
emulsion breakers reduce the residence time required for good
separation of oil and water. Addition of scale inhibitor should
additionally not materially interfere with the performance of the
emulsion breaker. Additionally, conventional corrosion inhibiting
agents may be added to either the water or oil phase or both to
inhibit desalter corrosion and corrosion that may otherwise occur
in downstream hydroprocessing and/or water treatment processes.
[0040] It is not obvious that the polymers (I) would be effective
in inhibiting calcium citrate scale. For example, as will be shown
in the following examples, several known calcium carbonate scale
inhibition agents, such as polyacrylic acid, HEDP
(1-hydroxyethyl-1,1-diphosphonic acid) and NTA (nitrilo triacetic
acid), had little or no effect on inhibiting calcium citrate
formation.
[0041] It is thus been discovered that a family of polymers, namely
polymer (I), inhibits the deposition of calcium citrate and allows
significantly higher levels to be formed at elevated temperatures
prior to deposition. The invention represents complementary
technology that allows citric acid or other sequestrants to be used
in extracting high concentrations of calcium from crude oil.
[0042] The invention will now be further described with reference
to the following specific examples which are to be regarded solely
as illustrative and not as restricting the scope of the
invention.
EXAMPLES
Example 1
[0043] In order to assess the efficacy of various candidate
materials in inhibiting calcium citrate crystal formation, a
solution (solution A) of 1,000 ppm (as solids) calcium chloride,
and 1,000 ppm (as solids) citric acid was prepared. NaOH was added
to bring the pH up to 7.1. Treated and untreated solutions were
heated at 100.degree. C. for 1-1.5 hours. Results are shown in
Table 1. TABLE-US-00001 TABLE 1 Treatment Observations 1 100 ml
solution A: untreated A lot of fine crystals precipitated on bottom
(assumed 100%). The water is clear. 2 100 ml solution A + sulfuric
acid dilution About 25% (compare to the untreated) to have pH 5.1
crystallize growing. The water is clear. 3 100 ml solution A +
sulfuric acid dilution About 40% (compare to the untreated) to have
pH 6.1 crystallize growing. The water is clear. 4 100 ml solution A
+ 50 ppm active A lot of fine and floc precipitate. HEDP (DeQuest
2010) The water is cloudy. 5 100 ml solution A + 50 ppm active NTA
A few (<2-5%) crystals on bottom. The water is clear. 6 100 ml
solution A + 50 ppm Comparative A lot of fine and floc precipitate.
Product AA The water is cloudy. HEDP = hydroxy ethylidene
diphosphonic acid NTA = nitrilotriacetic acid Comparative Product
AA = polyacrylic acid homopolymer nominal molecular weight about
5,000.
Example 2
[0044] Additional tests utilizing the procedure of Example 1 were
conducted. Results are reported in Table 2. TABLE-US-00002 TABLE 2
Treatment Observations 2.1 100 ml solution A: untreated A lot of
fine crystals precipitated on bottom (assumed 100%). The water is
clear. 2.2 100 ml solution A + 10 ppm active NTA A lot of fine
crystals precipitated on bottom (about 100%). The water is clear.
2.3 100 ml solution A + 20 ppm active NTA A lot of fine crystals
precipitated on bottom (about 60%). The water is clear. 2.4 100 ml
solution A + 30 ppm active NTA Lesser fine crystals precipitated on
bottom (about 30%). The water is clear. 2.5 100 ml solution A + 40
ppm active NTA About 5% crystals on bottom. The water is clear. 2.6
100 ml solution A + 50 ppm active NTA Very few crystals on bottom.
The water is clear.
Example 3
[0045] Further tests utilizing the procedure of Example 1 were
undertaken. Results are shown in Table 3. TABLE-US-00003 TABLE 3
Treatment Observations 3.1 100 ml solution A: untreated A lot of
fine crystals precipitated on bottom (assumed 100%), the water is
clear water. 0.0595 g crystals 3.2 100 ml solution A + 35 ppm
active NTA About 5-10% crystals on bottom. The water is clear. 3.3
100 ml solution A + 35 ppm active EDTA- About 5-10% crystals on
bottom. free acid The water is clear. 3.4 100 ml solution A + 70
ppm Product A Clean and clear water. No crystals. 3.5 100 ml
solution A + 70 ppm Product B Clean and clear water. No crystals.
3.6 100 ml solution A + 70 ppm Product PBTC About 5-10% crystals on
bottom. The water is clear. 3.7 100 ml solution A + 70 ppm Product
No crystals observed, but the water is DeQuest 2060 cloudy. 3.10
100 ml solution A + 30 ppm Product A Clean and clear water. No
crystals. 3.11 100 ml solution A + 50 ppm Product A Clean and clear
water. No crystals. 3.12 100 ml solution A + 70 ppm Product A Clean
and clear water. No crystals. 3.13 100 l solution A + 30 ppm
Product B Clean and clear water. No crystals. 3.14 100 ml solution
A + 50 ppm Product B Clean and clear water. No crystals. 3.15 100
ml solution A + 70 ppm Product B Clean and clear water. No
crystals. 3.16 100 ml untreated Solution A A lot of fine crystals
precipitated on bottom (assumed 100%), the water is clear water.
0.0644 g crystals PBTC = 2-phosphonobutane 1,2,4-tricarboxylic acid
DeQuest 2060 = dietheylene triaminopenta(methylene phosphonic acid)
Product A = acrylic acid/allyl-2-hydroxypropylsulfonate ether
(AHPSE); 36.5% active; nominal mw about 25,000 AA:AAPSE = 3 to 1
Product B = acrylic acid/allyl polyethoxy (10) sulfate ether
(APES); % active about 30%; nominal mw about 15,000, AA:APES =
3:1
Example 4
[0046] Additional tests were undertaken using the procedure of
Example 1. Test results are shown in Table 4. TABLE-US-00004 TABLE
4 Treatment Observations 1* 100 ml of solution A: untreated A lot
of fine crystals precipitated on bottom (assumed 100%), the water
is clear water. 0.0692 g crystals 2 100 ml solution A + 5 ppm
Product A About 5% crystal on bottom. The water is clear. 3 100 ml
solution A + 10 ppm Product A No crystals. Clear water. 4 100 ml
solution A + 20 ppm Product A No crystals. Clear water. 5 100 ml
solution A + 5 ppm Product B About 5-10% crystals on bottom. The
water is clear. 6 100 ml solution A + 10 ppm Product B About 2-5%
crystals on bottom. The water is clear 7 100 ml solution A + 20 ppm
Product B No crystals. Clear water. 8 100 ml solution A + 20 ppm
active EDTA- About 10-20% crystals on bottom. free acid Clear
water. 9 100 ml solution A + 20 ppm active NTA About 10-20%
crystals on bottom. Clear water. 1* The solution was filtered
through a Teflon filter and submitted to oil lab for Ca citrate
determination. The analysis has confirmed that it was calcium
citrate.
Example 5
[0047] In order to assess the impact of the calcium citrate deposit
inhibition chemistry on desalter operations, simulations were
conducted on high Ca.sup.2+ test crudes in a simulated desalter
apparatus.
[0048] The simulated desalter comprises an oil bath reservoir
provided with a plurality of test cell tubes disposed therein. The
temperature of the oil bath can be varied to about 300.degree. F.
to simulate actual field conditions. Electrodes are operatively
connected to each test cell to impart an electric field of variable
potential through the test emulsions contained in the test cell
tubes.
[0049] 95 ml of high calcium containing crude oil (110 ppm
Ca.sup.2+) and 5 ml D.I. water were admitted to each test cell
along with the candidate treatment materials. The
crude/water/treatment mixtures were homogenized by mixing at 13 psi
(13,000 rpm/2 sec) and the crude/water/treatment mixtures were
heated to about 250.degree. F. After 32 minutes, 75 ml of the top
crude was collected from each cell for calcium analysis. Water drop
(i.e., water level) in ml was observed for each sample after
predetermined time intervals.
[0050] Results are shown in Table 5. TABLE-US-00005 TABLE 5 Water
Drop Reading in MI Interface (I/F) Ca Result in 1 min 2 min 4 min 8
min 16 min 32 min Mean WD & Brine Oil Phase 5.1 8 ppm 2W158 to
oil 40 .mu.l (2%) 3.5 4 4.5 5 5 5 4.50 Good I/F, clear 10.9 ppm
1000 ppm citric acid to water 50 .mu.l (10%) water 5.2 8 ppm 2W158
to oil 40 .mu.l (2%) 3.7 4 4.5 5 5 5 4.53 1 ml emulsion 11.7 ppm
1600 ppm citric acid to water 80 .mu.l (10%) clear water 5.3 8 ppm
2W158 to oil 40 .mu.l (2%) 0.4 1 1.6 2.5 3.5 4 2.17 2 ml emulsion
12.3 ppm 1000 ppm citric acid to water 50 .mu.l (10%) clear water
300 ppm Product A to water 75 .mu.l (2%) 5.4 8 ppm 2W158 to oil 40
.mu.l (2%) 0.4 0.8 1.4 2 2.5 3 1.68 2 ml emulsion 11.0 ppm 1600 ppm
citric acid to water 80 .mu.l (10%) clear water 300 ppm Product A
to water 75 .mu.l (2%) 5.5 8 ppm 2W158 to oil 40 .mu.l (2%) 0.4 0.6
1.2 2.5 3 3.5 1.87 2 ml emulsion 12.2 ppm 1000 ppm citric acid to
water 50 .mu.l (10%) clear water 400 ppm Product B to water 100
.mu.l (2%) 5.6 8 ppm 2W158 to oil 40 .mu.l (2%) 0.2 0.4 1 1.6 1.8
2.5 1.25 2 ml emulsion 13.6 ppm 1600 ppm citric acid to water 80
.mu.l (10%)3 clear water 400 ppm Product B to water 100 .mu.l (2%)
5.7 8 ppm 2W158 to oil 40 .mu.l (2%) 3 3.5 4.5 5 5 5 4.33 Good I/F,
clear 13.3 ppm 1000 ppm citric acid to water 50 .mu.l (10%) Water
800 ppm NTA to water 200 .mu.l (2%) 5.8 8 ppm 2W158 to oil 40 .mu.l
(2%) 3.5 4 4.5 5 5 5 4.50 Good I/F, clear 9.9 ppm 1000 ppm citric
acid to water 50 .mu.l (10%) Water 800 ppm EDTA to water 200 .mu.l
(2%) 5.9 10 ppm 2W158 to oil 50 .mu.l (2%) 0.4 0.6 1.2 2.7 3.5 3.7
2.02 2 ml emulsion N/A 1000 ppm citric acid to water 50 .mu.l (10%)
clear water 300 ppm Product A to water 75 .mu.l (2%) 5.10 20 ppm
2W158 to oil 100 .mu.l (2%) 0.8 1.2 2.5 3.7 4.5 5 2.95 Good I/F,
clear 10.4 ppm 1000 ppm citric acid to water 50 .mu.l (10%) Water
300 ppm Product A to water 75 .mu.l (2%) 5.11 30 ppm 2W158 to oil
150 .mu.l (2%) 1 2 3.5 4.5 5 5 3.50 Good I/F, clear 10.4 ppm 1000
ppm citric acid to water 50 .mu.l (10%) Water 300 ppm Product A to
water 75 .mu.l (2%) 5.12 40 ppm 2W158 to oil 200 .mu.l (2%) 2.5 3.5
4.7 5 5 5 4.28 Good I/F, clear 12.4 ppm 1000 ppm citric acid to
water 50 .mu.l (10%) Water 300 ppm Product A to water 75 .mu.l (2%)
5.13 8 ppm 2W158 to oil 40 .mu.l (2%) 4 4.5 5 5 5 5 4.75 Good I/F
1000 ppm citric acid to water 50 .mu.l (10%) Clear water 5.14 8 ppm
2W158 to oil 40 .mu.l (2%) 4 4.5 5 5 5 5 4.75 Good I/F 1000 ppm
citric acid to water 50 .mu.l (10%) Slightly cloudy 150 ppm WS 55
to water 37.5 .mu.l (2%) water 5.15 8 ppm 2W158 to oil 40 .mu.l
(2%) 4 4.5 5 5 5 5 4.75 Good I/F 1000 ppm citric acid to water 50
.mu.l (10%) Slightly cloudy 300 ppm WS 55 to water 75 .mu.l (2%)
water 5.16 8 ppm 2W158 to oil 40 .mu.l (2%) 4 4.5 5 5 5 5 4.75 Good
I/F 1000 ppm citric acid to water 50 .mu.l (10%) Clear water 15 ppm
Product A to water 3.75 .mu.l (2%) 5.17 8 ppm 2W158 to oil 40 .mu.l
(2%) 4 4.5 5 5 5 5 4.75 Good I/F 1000 ppm citric acid to water 50
.mu.l (10%) Slightly cloudy 15 ppm Product A to water 3.75 .mu.l
(2%) water 150 ppm WS 55 to water 37.5 .mu.l (2%) 5.18 8 ppm 2W158
to oil 40 .mu.l (2%) 4 4.5 5 5 5 5 4.75 Good I/F 1000 ppm citric
acid to water 50 .mu.l (10%) Slightly cloudy 15 ppm Product A to
water 3.75 .mu.l (2%) water 300 ppm WS 55 to water 75 .mu.l (2%)
5.19 25 ppm 2W158 to oil 125 .mu.l (2%) 4 4.5 5 5 5 5 4.75 Good I/F
1000 ppm citric acid to water 50 .mu.l (10%) Slightly cloudy 15 ppm
Product A to water 3.75 .mu.l (2%) water 300 ppm WS 55 to water 75
.mu.l (2%) 2W158 = Emulsion Breaker; available GE Betz WS55 =
corrosion inhibitor; available GE Betz In runs 5.1-5.12 Products A
& B affected the water drops at these very high (unrealistic)
concentrations. At these high concentrations, increased levels of
about 20-30 2W158 were needed to completely resolve the emulsion.
NTA and EDTA did not affect the water drop. With 40 ppm active
treated at water phase to control the crystal precipitate, it
needed only 8 ppm of 2W158 to break out all the added water.
Conclusion: At typical treatment dosages (i.e., 15 ppm to the
water) of Product A, no deleterious effect or desalter operation is
seen.
Example 6
[0051] Additional tests using the procedure of Example 1 were
undertaken. Results are reported in Table 6. TABLE-US-00006 TABLE 6
Observations Treatment Ambient Temperature 100.degree. C. After
1-1.5 hours 6.1 100 ml of solution A: Clear water A lot of fine
crystals untreated No precipitate precipitated on bottom (assumed
100%), the water is clear 6.2 100 ml solution A Clear water Very
few fine crystals on 10 ppm Product A No precipitate bottom (50
.mu.l of 2% in water) (<1% compare to the blank) Clear water 6.3
100 ml solution A Cloudy water About 10% crystals stuck on 10 ppm
Product A No precipitate wall and on bottom (50 .mu.l of 2% in
water) (compare to the blank). 200 ppm WS-55 (200 .mu.l Cloudy
water of 10% in water) 6.4 100 ml solution A Cloudy water Very few
fine crystals on 20 ppm Product A No precipitate bottom (100 .mu.l
of 2% in (<1% compare to the blank - water) same as # 2) 200 ppm
WS-55 (200 .mu.l Cloudy water of 10% in water) Conclusion: 1. 200
ppm of WS-55 caused the cloudiness of the water. It also decreased
the performance of Product A. 2. 20 ppm of Product A (instead of 10
ppm) resulted in the disappearance of the crystals in 100 ml the
solution A, if 200 ppm of WS-55 was treated.
Example 7
[0052] Another series of tests using the protocol set forth in
Example 1 were completed. Results are shown in Table 7.
TABLE-US-00007 TABLE 7 Observations Treatment Ambient Temperature
100.degree. C. After 1-1.5 hours 7.1 100 ml of solution A:
untreated Clear water A lot of fine crystals No precipitate
precipitated on bottom; the water is clear. 7.2 100 ml solution A +
2.5 ppm Clear water No precipitate observed, Active Product A. No
precipitate clear water. 7.3 100 ml solution A + 5 ppm Clear water
No precipitate observed, Active Product A. No precipitate clear
water. 7.4 100 ml solution A + 10 ppm Clear water No precipitate
observed, Active Product A. No precipitate clear water. 7.5 100 ml
solution A + 2.5 ppm Clear water No precipitate observed, Active
Product C. No precipitate clear water. 7.6 100 ml solution A + 5
ppm Clear water No precipitate observed, Active Product C. No
precipitate clear water. 7.7 100 ml solution A + 10 ppm Clear water
No precipitate observed, Active Product C. No precipitate clear
water. Product C is acrylic
acid/2-acrylamido-2-methylpropane-3-sulfonic acid mw
.apprxeq.4,500.
[0053] It is noted that as used throughout the specification and
ensuing claims when the liquid hydrocarbonaceous medium or aqueous
medium is said to be contacted by an agent, this should not be
narrowly construed to imply that the agent is added directly to the
medium said to be contacted. Instead, the agent could be added to
another medium or emulsion containing the intended medium provided
that somewhere in the process, the agent, wherever its point of
addition to the process may be, ultimately mixes with or contacts
the intended medium.
[0054] While we have shown and described herein certain embodiments
of the present invention, it is intended that there be covered as
well any change or modification therein which may be made without
departing from the spirit and scope of the invention as defined in
the appended claims.
* * * * *