U.S. patent application number 11/146914 was filed with the patent office on 2006-12-07 for processing unconventional and opportunity crude oils using zeolites.
Invention is credited to Charlotte R. Droughton, Wenping Li.
Application Number | 20060272983 11/146914 |
Document ID | / |
Family ID | 37493082 |
Filed Date | 2006-12-07 |
United States Patent
Application |
20060272983 |
Kind Code |
A1 |
Droughton; Charlotte R. ; et
al. |
December 7, 2006 |
Processing unconventional and opportunity crude oils using
zeolites
Abstract
The disclosed process removes or reduces impurities such as
asphaltenes, solids (especially solid fines), sulfur, metals,
chlorides, water, salts, and acids from bitumen, oil sands, and
crude oils with a wide range of gravities. A crude source
composition is contacted with one or more zeolite materials to
remove asphaltenes, solids, sulfur, NSO, metals, chlorides, water,
salts, and/or acids from the composition. The crude source is
typically diluted with a hydrocarbon solvent such as naphtha before
contacting the zeolite(s). The disclosed processes represent an
improvement over prior and presently available processes because
the disclosed processes are capable of processing emulsions.
Inventors: |
Droughton; Charlotte R.;
(Houston, TX) ; Li; Wenping; (Pearland,
TX) |
Correspondence
Address: |
WONG, CABELLO, LUTSCH, RUTHERFORD & BRUCCULERI,;L.L.P.
20333 SH 249
SUITE 600
HOUSTON
TX
77070
US
|
Family ID: |
37493082 |
Appl. No.: |
11/146914 |
Filed: |
June 7, 2005 |
Current U.S.
Class: |
208/177 ;
208/187; 208/208R; 208/251R |
Current CPC
Class: |
C10G 25/003
20130101 |
Class at
Publication: |
208/177 ;
208/187; 208/208.00R; 208/251.00R |
International
Class: |
C10G 31/00 20060101
C10G031/00; C10G 33/00 20060101 C10G033/00; C10G 45/00 20060101
C10G045/00; C10G 17/00 20060101 C10G017/00; C10G 29/00 20060101
C10G029/00; C10G 19/00 20060101 C10G019/00; C10G 21/00 20060101
C10G021/00 |
Claims
1. A process for removing an impurity from a petroleum composition,
comprising: contacting the composition with one or more zeolite
materials.
2. The process of claim 1, wherein the petroleum composition
comprises acidic crude oil, extra heavy oil, heavy oil, high
salinity crudes, acidic residuum, gas oil, oil sand, diluted
bitumen, undiluted bitumen, or a mixture thereof.
3. The process of claim 1, wherein the impurity comprises
asphaltenes, solids, sulfur, NSO, metals, chlorides, water, salts,
surfactants or a combination thereof.
4. The process of claim 1, wherein the zeolite is a type Z
zeolite.
5. The process of claim 1, wherein the zeolite is a chabazite
zeolite.
6. The process of claim 1, wherein the zeolite material is
surface-modified to have a positive surface potential.
7. The process of claim 1, wherein the composition is co-currently
contacted with the zeolite material.
8. The process of claim 1, wherein the composition is
counter-currently contacted with the zeolite material.
9. The process of claim 1, wherein the zeolite material is
contained in a static bed, a fluidized bed, or an expandable
bed.
10. The process of claim 1, further comprising adding one or more
reagents to the composition, wherein the reagent is selected from
the group consisting of acids, demulsifiers, caustic agent, and
coagulants.
11. The process of claim 1, further comprising recovering zeolite
material from the composition.
12. The process of claim 1, further comprising the steps of: adding
a hydrocarbon solvent to the composition to provide a
density-modified composition; removing a portion of water and/or
solids from the composition; adding to the density-modified
composition one or more reagents selected from the group consisting
of acids, caustics, demulsifiers, coagulants, and viscosity
modifiers; contacting the density-modified composition with a first
zeolite material and substantially removing the first zeolite
material from the density-modified composition; contacting the
composition with a second zeolite material and substantially
removing the second zeolite material from the density-modified
composition; and evaporating the density-modified composition
mixture in one or more evaporation stages to provide a solvent
stream and a product stream.
13. A process for removing an impurity from a petroleum
composition, comprising: contacting the petroleum composition with
a first zeolite material; contacting the petroleum composition with
a second zeolite material; wherein one of the zeolite materials has
a positive surface potential and the other zeolite material has a
negative surface potential.
14. The process of claim 13, wherein the petroleum composition
comprises acidic crude oil, extra heavy oil, heavy oil, high
salinity crudes, acidic residuum, gas oil, oil sand, diluted
bitumen, undiluted bitumen, or a mixture thereof.
15. The process of claim 13, wherein the impurity comprises
asphaltenes, solids, sulfur, NSO, metals, chlorides, water, salts,
surfactants, or a combination thereof.
16. The process of claim 13, wherein the petroleum composition
comprises an emulsion.
17. A process for removing an impurity from a petroleum
composition, comprising: adding a hydrocarbon solvent to the
petroleum composition; removing a portion of water and/or solids
from the petroleum composition; contacting the petroleum
composition with a first zeolite material and substantially
removing the first zeolite material from the petroleum composition;
and contacting the petroleum composition with a second zeolite
material and substantially removing the second zeolite material
from the petroleum composition; wherein one of the zeolite
materials has a positive surface potential and the other zeolite
material has a negative surface potential.
Description
BACKGROUND
[0001] 1. Field of the Invention
[0002] The invention relates to separation processes and systems to
remove or reduce impurities from unconventional and opportunity
petroleum resources.
[0003] 2. Description of the Related Art
[0004] Opportunity petroleum resources such as acidic crude oil,
extra heavy oil, heavy oil, high salinity crudes, acidic residuum,
gas oils, oil sand, diluted bitumen, and undiluted bitumen are
typically treated to remove impurities such as asphaltenes, solids,
sulfur, NSO, metals, chlorides, water, salts, and acids before
sending the resource upstream for additional processing. One
currently available treatment is solvent deasphalting (SDA). This
process takes advantage of the fact that maltenes are more soluble
in light paraffinic solvents than asphaltenes. This solubility
increases with solvent molecular weight and decreases with
temperature. There are constraints with respect to how deep a SDA
unit can cut into the residue or how much deasphalted oil (DAO) can
be produced. These constraints are typically due to the DAO quality
specifications required by downstream conversion units; and the
final high-sulfur residual fuel oil stability and quality.
[0005] Solvent deasphalting has the advantage of being a relatively
low cost process that has the flexibility to meet a wide range of
DAO qualities. The process has very good selectivity for
asphaltenes and metals rejection, some selectivity for carbon
rejection and less selectivity for sulfur and nitrogen. It is best
suited for the more paraffinic vacuum residues as opposed to the
high asphaltenes, high metals, and high carbon containing vacuum
residues. The disadvantages of the process are that it performs no
conversion, produces a very high-viscosity byproduct pitch, and
where high quality DAO is required, SDA is limited in the quality
of feedstock that can be economically processed.
[0006] Delayed coking has been the preferred choice of many
refiners for bottom of the barrel upgrading, due to the inherent
flexibility of the process to handle highly contaminated residues.
Delayed coking provides partial to complete conversion to naphtha
and diesel, and almost complete rejection of carbon and metals. In
the past, many cokers were designed to provide complete conversion
of atmospheric residue to diesel and lighter, and today several
cokers still operate in this mode. Most recently, cokers have been
designed to produce heavy coker gas oil for catalytic upgrading,
and minimize the production of coke. The economics of delayed
coking are driven by the differential between transportation fuels
and high-sulfur residual fuel oil. The yield slate for a delayed
coker can be varied to meet a refiner's objectives through the
selection of operating parameters. Coke yield and the conversion of
heavy coker gas oil are reduced, as the operating pressure and
recycle are reduced and to a lesser extent as temperature is
increased. The disadvantages of delayed coking are that it is a
thermal cracking process and it is a more expensive process than
SDA although still less expensive than other conversion processes
on heavier crudes. One common misconception of delayed coking is
that the product coke is a disadvantage. Although coke is a low
valued byproduct, compared to transportation fuels, there is a
significant worldwide trade and demand even for high-sulfur petcoke
from delayed cokers as coke is a very economical fuel. In the past,
most of the fuel coke produced in the US has been exported to
Europe and Japan, however, many of the coal burning power producers
in the U.S. have now installed scrubbers and are now using or
considering the use of petcoke as part of the fuel to their plant.
In addition, there have been several 100% petcoke based power
plants installed and many more are being considered. Several of
these petcoke burning power plants utilize Foster Wheeler's
Circulating Fluid-Bed Boiler Technology. In these plants a
circulating bed of limestone captures the sulfur. One concern of
the power producing companies in the U.S. has been "is there enough
low value petcoke?"
[0007] One existing process integrates solvent deasphalting and
delayed coking technologies. See, McGrath et al, "Upgrading Options
for Heavy Crude Processing", presented at AlChE Spring 1999
Meeting. The process purportedly provides synergistic application
of the two base technologies for increased liquid yield and energy
utilization. The increased liquid yields are mainly attributable to
the extraction of the high-valued DAO prior to coking. The heat
integration between the solvent deasphalting and delayed coking
sections features utilization of both high and low level coker
waste heat sources in the SDA section. Removing the DAO fraction
prior to delayed coking has two benefits. In the coking process
this fraction is thermally cracked to extinction, degrading this
material as an FCC feedstock. In addition, in thermally cracking
this material to extinction, a significant portion will convert to
coke. The process purportedly operates with deasphalted oil, both
virgin and hydrotreated, and produces as much as 20 wt % coke at
higher pressures and recycle rates. A delayed coker pilot plant has
also been modified to operate on SDA pitch. This pilot plant has
purportedly operated on feedstocks having ring and ball softening
points as high as 295.degree. F. With this process there is a
significant reduction in byproduct fuel as compared to either
solvent deasphalting or delayed coking. The operation can be
tailored to meet the ability of a refinery to process a specific
quantity or quality of cracking stock.
[0008] Production of usable hydrocarbons from unconventional and
opportunity crudes has been the subject of much research since the
oil crisis of 1973, and even before. The EIA has indicated there
are 301.0 BBO of heavy oil and 531.0 BBO of bitumen currently
recoverable in the Western Hemisphere. High acid crude processing
(as a percent of total crude processed) is expected to grow from
about 8.5% in 2004 to about 10.3% in 2009.
[0009] The traditional application of in situ production techniques
involved drilling a well into the oil sands and extracting the
bitumen almost as if it were conventional crude oil. The maturation
of horizontal well technology and the development of steam assisted
gravity drainage (SAGD) extraction techniques have revolutionized
the in situ production industry. With the SAGD technology, two
horizontal wells are drilled into the same reservoir, one directly
above the other. Steam is injected into the top well, which heats
up the surrounding tar-like bitumen and causes it to drain with the
aid of gravity into the well bore of the lower well.
[0010] A separation train for producing and upgrading heavy oil and
bitumen was reported by Kerr et al., "The Long Lake Project--The
First Field Integration of SAGD and Upgrading", Soc. of Pet.
Engrs., SPE/PS-CIM/CHOA, 2002 SPE International Thermal Operations
and Heavy Oil Symposium and International Horizontal Well
Technology Conference, Calgary, Alberta, Canada, 4-7 November 2002
(herein after Kerr et al.). This publication describes a process
for upgrading heavy oil and bitumen. The process produces a light,
sweet synthetic crude from SAGD and an upgrading process that
includes distillation combined with solvent deasphalting to
partially upgrade bitumen and produce an asphaltene by-product. The
partially upgraded bitumen is then processed in a hydrocracker to
produce what is termed a premium synthetic crude. The asphaltenes
are fed to an asphaltene gasification system to produce hydrogen
for the hydrocracker and syn gas fuel for the SAGD process.
[0011] With the depletion of conventional oil supplies, bitumen
extracted from oil sands has become a more attractive source of
unconventional crude. The USA and Canada have the world's largest
oil sand reserves, which are estimated to be 58.1 billion barrels
and 1.6 trillion barrels, respectively. Bitumen contained in the
oil sand is highly viscous with API gravities from 1 to 10. Bitumen
is made up primarily of distillate and vacuum gas oil cuts in
addition to contaminants such as solids, asphaltenes, carboxylic
and other organic acids, salts, heteroatoms such as sulfur,
nitrogen, and oxygen, and heavy metals. Bitumen must first be
separated from the oil sand, and then upgraded before it can be
used as a refinery feedstock.
[0012] The three major bitumen recovery technologies are surface
mining, SAGD, and thermal treatment. SAGD is commercially proven
and is used to recover bitumen that is not accessible by surface
mining. However, SAGD requires large amounts of steam and is quite
energy intensive. Thermal treatments such as vacuum pyrolysis are
presently under investigation and development. This process
produces less environmental pollution than the other two processes
but consumes large amounts of energy. The surface mining process is
widely used commercially.
[0013] Surface mining is currently used to recover bitumen from oil
sands and includes process steps such as oil sands mining, bitumen
extraction, and bitumen separation. The bitumen product is then
sent to upgrading. Two major procedures for extraction and
separation involves 1) water extraction, which uses hot water and
caustic to wash and float the bitumen from the sand, and 2) organic
solvent extraction, which employs an organic solvent to dissolve
the bitumen from the surface of the oil sand. The disadvantages of
the solvent extraction process are: environmental pollution due to
the loss of solvent; storage of solvent inventories; large
quantities of water are required to remove the solvent from the
sand after extraction; and difficulties in process scale up.
[0014] In a currently practiced hot water extraction process oil
sand is first washed by hot water and caustic to form a three-phase
suspension made up of bitumen, water, and solids. The suspension
(which may or may not also include an emulsion layer), which has
been diluted with naphtha, enters a separation system involving
gravity separation, flotation, centrifugation, and distillation
where bitumen, solids, water, and naphtha are separated from each
other. If the hot water extraction and the separation operations
are successful, the bitumen product will contain very low
concentrations of solids and water, and will be ready for
downstream upgrading by coking or hydrocracking. A synthetic crude
oil is produced by the upgrading process. However, various problems
exist in the extraction and separation steps, which may lead to
ineffective separation of the bitumen, solids, and water that may
result in: large quantities of water usage and disposal in the
tailings pond; environmental pollution; high energy consumption;
unacceptable bitumen quality.
[0015] Available extraction and separation processes are encumbered
with several problems. One problem is low bitumen extraction rate
due to the existence of asphaltenes, salts, acids, and extra fine
particles at the silica-water interface, and water-oil interface,
the bitumen strongly adheres to the sand particles. The
displacement efficiency of removing bitumen from the sand is low by
hot water extraction alone. The remaining bitumen in the oil sand
tailings is not only an issue with regard to bitumen yield, but
also may be an environmental problem.
[0016] Emulsions present another problem. After the bitumen is
displaced from the sand by hot water and caustic, a stable
bitumen-water emulsion may form. The emulsion is stabilized by
asphaltenes, salts, fine particles, and acids (specifically
carboxylic and other organic acids with the previous referred to
herein as naphthenic acids) at the bitumen-water interface. The
emulsion is difficult to break by the conventional separation
techniques in the existing process and will be either disposed of
in the tailings pond or carried over in the bitumen product. The
emulsion that is carried over may cause serious problems in the
downstream processes, such as corrosion, fouling, catalyst
deactivation, and decreased operating efficiency.
[0017] Likewise, suspended fine particles smaller than 10 microns
are very difficult to remove by flotation, gravity separation, or
centrifugation. The fine particles are also responsible in part for
formation and stabilization of emulsions, and will cause plugging
problems in downstream processes. Fines may also prohibit bitumen
droplet coalescence.
[0018] Furthermore, asphaltenes have higher aromaticity, low H/C
molar ratio, high heteroatoms content (e.g. N, S, and 0, commonly
referred to as "NSO"), and contain heavy metals such as V and Ni.
Asphaltenes have a higher molecular weight as compared with lighter
petroleum fractions, and are the most difficult portion of the
feedstock to upgrade. The dispersed colloidal asphaltene particles
play an important role in emulsion stabilization. Asphaltenes at
the surface of bitumen droplets may also inhibit coalescence.
[0019] Additionally, heavy metals such as vanadium and nickel are
normally associated with asphaltenes while NSO in the bitumen are
associated with both resins and asphaltenes. Heavy metals may
deteriorate catalyst activity in downstream operations, and may
cause serious environmental problems if handled improperly. NSO are
also important elements for air pollution generation. To remove
some of these heteroatoms prior to SO.sub.X and NO.sub.x production
would be beneficial. However, the processes discussed above
typically do not to remove the heavy metals or NSO contained in
asphaltenes and resins. These contaminants are sent downstream with
the bitumen for pollutant generation.
[0020] Carboxylic acids, commonly referred to as naphthenic acids,
which are in the bitumen are another important surfactant to
stabilize bitumen-water emulsions. These acids may also cause
serious environmental pollution if released with water. Naphthenic
acids, which are actually classified as resins, also contain a high
level of heteroatoms. The current hot water extraction and
separation process is not designed for naphthenic acid removal,
except as salts which may contribute to emulsion stabilization.
[0021] The above problems are characteristic deficiencies of the
current hot water extraction technology. In order to solve the
problems, an effective and efficient bitumen extraction,
separation, and upgrading technology needs to be developed.
[0022] U.S. Pat. No. 6,357,526 (Abdel-Halim, et al), discusses
field upgrading of heavy oil and bitumen. Additionally, the
following patents assigned to Ormat, Inc., are related to
deasphalting technology: 5,804,060; 5,814,286; 5,843,302;
5,914,010; 5,919,355; 5,944,984; 5,976,361; 6,183,627; 6,274,003;
6,274,032; and 6,365,038.
[0023] Lindemuth, P.M., et al, "Improve Desalter Operations"
Hydrocarbon Processing, (September 2001) discusses adding
dispersant to a desalter to prevent asphaltene precipitation. This
was referred to as desalter instability and can lead to shorter run
lengths. Thus this paper suggests deasphalting ahead of the
desalter contributes to increased run lengths. The same paper
purports that asphaltene removal upstream of the desalter allows
the utilization of crudes that traditionally would present problems
in blending. Additionally, a reduction in the load of asphaltenes,
salt, and solids challenging the existing desalter is reduced,
potentially increasing throughput.
[0024] Therefore, notwithstanding existing processes for producing
synthetic crude oils, what is needed in the art are processes and
systems for: carboxylic acid removal to eliminate requirement of
opening naphthenic rings; removal of solids, especially solid
fines, and carbon residue; asphaltene removal and viscosity
reduction, i.e. deasphalting; water, salts, and metals removal;
and/or removal of heteroatoms as found in naphthenic acids and
asphaltenes.
[0025] Stable emulsions and asphaltenes cause serious problems for
oil refiners. Emulsions complicate refinery operations and lead to
operational upsets and production losses. A cost effective way to
break emulsions and separate the two liquid phases would be
valuable to all companies operating process plants, especially to
refining companies. Asphaltenes, the heaviest and most contaminated
component of petroleum, in addition to salts, and organic acid
(specifically the carboxylic acid family of which naphthenic acids
are a part) prevent refiners from using very much of the heavier,
and cheaper, grades of petroleum as feedstocks. Cost effective and
efficient removal of asphaltenes, salts, and naphthenic acids could
upgrade the petroleum, turning the heavy crude into a valuable and
lighter refinery feedstock, and potentially reducing our country's
dependence on foreign oil.
SUMMARY
[0026] An aspect of the disclosure provides a process for removing
one or more impurities from a petroleum composition. Such
impurities can include asphaltenes, solids (especially solid
fines), sulfur, metals, chlorides, water, salts, and acids.
Petroleum compositions can include opportunity crude oil sources
such as bitumen, oil sands, and crude oils with a wide range of
gravities. An aspect of the process is that it does not require a
catalytic chemical process to remove one or more impurities.
However, such chemical processes can be implemented in conjunction,
i.e., upstream or downstream, with the disclosed process. An
advantage of the disclosed process is that it represents an
improvement over presently available technologies for treating
opportunity petroleum sources because the disclosed process is
capable of processing emulsions.
[0027] According to the disclosed process, a crude source
composition is contacted with one or more zeolite materials to
remove contaminants such as asphaltenes, solids, sulfur, NSO,
metals, chlorides, water, salts, and/or acids from the composition.
The crude source is typically diluted with a hydrocarbon solvent
such as naphtha before contacting the zeolite(s). The zeolites used
in the disclosed processes can have negative surface charge or may
be surface-modified to have a positive surface. In various
embodiments, the crude source composition is contacted both with
zeolites having negative surface charge and with zeolites having
positive surface charge. The zeolites are used in the disclosed
process to facilitate the removal of asphaltenes, solids, sulfur,
NSO, metals, chlorides, water, salts, and/or acids from the
composition and are not present as supports for catalysts, for
example for cracking.
BRIEF DESCRIPTION OF THE DRAWINGS
[0028] FIG. 1 illustrates a process for treating opportunity crude
embodying aspects of the disclosure.
DETAILED DESCRIPTION
[0029] As used herein, the terms "heavy oil" and "bitumen" follow
those definitions provided by The United Nations Information Centre
for Heavy Crude and Tar Sands, which defines bitumen as petroleum
having a viscosity >10,000 centipoise (cP); petroleum with
viscosity less than 10,000 cP and a density between 10.degree. API
and 20.degree. API is defined as heavy oil; and extra heavy oil has
a density <10.degree. API. As used herein, solids fines means
solid particles having an average particle size in their largest
dimension as follows (Tiller, F.M., and Li, W., Theory and Practice
of Solid/Liquid Separation, 4.sup.th Ed., (2002)): 0.1 micron--10
microns is defined as a fine particle; 0.001-0.1 micron is
colloidal; and <0.001 micron is molecular.
[0030] Untreated heavy oil or bitumen may have the characteristics
reported by Schucker, U.S. Pat. No. 6,524,469, and reported in
Table 1. TABLE-US-00001 TABLE 1 Petroleum Characteristics (Heavy
Oils and Bitumen) Conradson Carbon 5 to 40 wt. % (ASTM D189-165)
Sulfur 1.5 to 8 wt. % Hydrogen 9 to 11 wt. % Nitrogen 0.2 to 2 wt.
% Carbon 80 to 86 wt. % Metals 1 to 2000 wppm Boiling Point 340 C.+
to 566 C.+ Gravity 10 to 20.degree. API
[0031] In addition, salts in these petroleum sources may contain
from about 50 pounds per thousand barrels (ptb) up to about 1000
ptb or higher, solids fines ranging from 1 to 90 percent of the
solids. Fines may be dispersed in the oil phase or carried in
suspension in the brine droplets. In addition to the fines in the
oil sands themselves, occurring as finely divided siliceous matter,
such as silt, and the like, the solids may be entrained drilling
mud used in drilling the well or in its rehabilitation, or still
firther they may be iron rust, scale, and other such type of
material, picked up by the oil during the course of its passage
through pipelines, tanks, valves, and the like. These materials can
contribute to the plugging of distillation towers and heat
exchangers, in addition to eroding equipment and contaminating
residual products if not reduced or eliminated.
[0032] The following abbreviations are used herein:
SAGD--steam-assisted gravity drainage; CDC--crude distillation
complex; ACDU--atmospheric crude distillation unit; VDU--vacuum
distillation unit; DAU--deasphalting unit; DAO--deasphalted oil;
ASU--air separation unit (cryogenic, adsorption, or membrane);
FCC--fluidized catalytic cracking unit; HT--hydrotreating unit;
TSS--total suspended solids; and HC--hydrocracking unit.
[0033] The present disclosure provides a process for treating
petroleum-containing compositions such as acidic crude oil, extra
heavy oil, heavy oil, high salinity crudes, acidic residuum, gas
oils, oil sand, diluted bitumen, undiluted bitumen, or a
combination thereof to remove one or more impurities such as
asphaltenes, solids, sulfur, NSO, metals, nitrogen, chlorides,
water, salts, and/or acids. According to one embodiment, a feed
stream containing one or more of these petroleum compositions is
treated to remove a portion of free water and bulk solids from the
stream. For example, the stream can be contained in a vessel such
as a separator unit to allow a portion of the water and solids in
the stream to settle to the bottom of the vessel. The stream can
then be separated from the settled water and/or solids.
[0034] According to one embodiment, a liquid hydrocarbon solvent is
added to the feed stream to adjust the density and/or viscosity of
the feed stream. Suitable solvents include naphtha, normal alkanes,
and kerosene. Straight run naphtha is a particularly suitable
solvent. The amount of solvent generally required is typically less
than that required in conventional processes, due to the subsequent
steps, as explained firther below. The amount of naphtha required
depends on the viscosity and density of the feed. Additionally, the
separation process can be operated at a temperature of about
ambient to about 100.degree. F. The system can be operated at
higher temperatures, but this may not be economically optimal.
Likewise, in a low pressure system i.e., about ambient to about 150
psi; the system can also be operated under higher pressure (above
150 psi), but this might be cost prohibitive. Temperature elevation
typically results in reduced solvent requirement. According to one
embodiment, at ambient conditions about a 1:2 solvent to feed ratio
for heavy crude is used to provide separation of heavy crude, which
also contains a stable emulsion. Higher diluent to feed ratios, for
example, up to about 3-4:1 or higher, may be desirable. For
comparison, some commercial SDA units run diluent to feed ratios
ranging up to 12:1. However, these units are for deasphalting only
and the commercial SDA units do not process emulsions. Contrarily,
the disclosed process is ideally suitable of processing emulsions.
The naphtha is not required to be a pure hydrocarbon. The boiling
range of the naphtha might be, for example, about 20.degree. C. to
about 80.degree. C. According to one embodiment, a naphtha cut is
taken from a diluent recovery unit, as explained further below.
[0035] According to one embodiment, an acid can be added to the
feed stream. It may be desirable to add acid to the pH of the feed
stream greater than about 9. Suitable acids include sulfuric acid,
hydrochloric acid, and nitric acid. Sulfuric acid is particularly
suitable. According to one embodiment, acid is added to the feed
stream to achieve a pH of about 7 to about 9.
[0036] According to one embodiment, a caustic agent can be added to
the feed stream. At high caustic concentrations, acids can be drawn
from the oil phase to the oil/water interface where they can be
ionized. Subsequently, the acid ions enter the water phase due to
differences in concentration and polarity. When the oil phase
contains no acids, the interfacial tension (IFT) increases. As the
emulsion's IFT increases, the stability of the emulsion decreases,
ultimately resulting in phase separation. Suitable caustic agents
include, for example, sodium hydroxide and calcium hydroxide.
Sodium hydroxide is a particularly suitable caustic agent.
According to one embodiment, caustic agent is added to the feed
stream to achieve a pH of about 8 to about 9.
[0037] According to one embodiment, a demulsifier can be added to
the feed stream. It is within the ability of one of skill in the
art to select an appropriate demulsifier based on their particular
petroleum composition. One of skill in the art will appreciate that
individual demulsifiers can be extremely crude oil- or
region-specific. Exemplary demulsifiers include high molecular
weight polymeric emulsifiers. Demulsifiers can be cationic,
anionic, or non-ionic and can be commercially obtained (e.g., Baker
Hughes Incorporated, Houston, TX).
[0038] According to an embodiment, a coagulant or flocculent can be
added to the feed. Also, an asphaltene precipitant can be added to
the feed. Exemplary asphaltene precipitants include alkanes such as
hexanes and pentanes, possibly mixed with light aromatic compounds
such as trimethyl benzene.
[0039] An aspect of the disclosed method involves contacting the
composition with one or more zeolite materials to remove one or
more impurities such as asphaltenes, solids, sulfur, NSO, metals,
chlorides, water, salts, and acids from the composition.
Particularly useful zeolites include natural or synthetic
crystalline aluminosilicates. The zeolites are "mesopore-structured
materials", meaning that they are crystalline or amorphous metal
oxides having essentially regularly structured pore systems wherein
the average size of the pores is, for example, in the range of
about 1.5 to about 5 nanometers. Exemplary zeolites are the Z-type
zeolites, which may be natural, synthetic, or combinations thereof
and typically have the chabazite structure. These may be used alone
or in conjunction with other zeolite types, such as the A, X, and Y
types. In some cases it may be advantageous to blend the zeolite
with other filter aids such as bentonites, or diatomaceous earth.
The natural or synthetic material can be ground to achieve a
particular particle size distribution, and may be chemically and/or
physically modified, for example, through ion exchange, to achieve
optimal separation characteristics for a given heavy oil or bitumen
being treated. Examples of zeolites having asphaltene adsorption
properties that are useful include natural and synthetic zeolites
belonging to the following structural classification families: BEA,
CHA, EMT, ERI, FAU, FER, GIS, HEU, LTA, LTL, MAZ, MEI, MEL, MFI,
MOR, MTW, OFF, ZSM-2, ZSM-18, ZSM-48 and mixtures thereof. Specific
zeolites as members of these classes are BEA: beta, tschernichite,
etc.; CHA: chabazite, Linde D, Linde R, phi, etc.; EMT: ZSM-3,
ZSM-20, hexagonal faujasite, etc.; ERI: erionite, LZ-220, etc.;
FAU: faujasite, type X zeolite, type Y zeolite, etc.; FER: ZSM-35,
Fu-9, etc.; GIS; synthetic zeolite P, TMA-gismondine, etc.; HEU:
clinoptilolite, heulandite, LZ-219, etc.; LTA: type A zeolite,
alpha, ZK-4, etc.; LTL: Linde type L, LZ-212, perlialite, etc.;
MAZ: ZSM-4, omega, etc.; MEL: silicalite-II, TS-2, etc.; MFI:
ZSM-5, silicalite-I, etc.; MOR: large port mordenite, LZ-211,
zeolon, etc.; MTW: Nu-13, theta-3, etc.; and OFF: offretite, Linde
type T, LZ-217 etc. For more information on those structures, cf.,
W. M. Meier, D. H. Olson, and Ch. Baerlocher, Atlas of Zeolite
Structure Types, Elsevier, London, Boston, 1996. Specific examples
of zeolites that are preferred for use in producing the adsorbent
compositions disclosed herein are natural zeolites, such as
mordenite, erionite, clinoptilolite and chabazite, and synthetic
zeolites, such as type X zeolite, type A zeolite, type Y zeolite,
mordenite, chabazite and ZSM-5. A particularly preferred zeolite is
type Z zeolite, known under the trade designation Z-1, and is
preferably used in dehydrated form. Exemplary zeolites include the
ZS500 zeolites, available from GSA Resources, Inc. (Tucson,
AZ).
[0040] Some of the zeolites, herein termed Z2, have a positive
surface charge. The positive surface charge is obtained by surface
modification using, for example, long carbon chained surfactant
molecules with a cation at the head. The Z2 zeolites are
particularly effective for enhancing the adsorption of asphaltenes
by adsorbents that weakly adsorb other hydrocarbons from crude
hydrocarbon/water mixtures. Thus, the adsorbents are particularly
effective for separating asphaltenes from crude or pretreated oil
mixtures, such as degassed, dewatered, density modified heavy oils
and bitumens. The anions and hydrocarbons are attracted to the
positive surface charge of the Z2 zeolites. This makes it possible
to operate downstream upgrading units much more effectively than
was formerly possible.
[0041] Z2 zeolites also function as a cationic coagulant.
Asphaltene molecules become adsorbed in multiple pores of multiple
zeolite particles, and the portions of the asphaltene molecules not
adsorbed function to attract and collect further charged species
(ions, molecules, portions of molecules, and the like). Networks of
zeolite particles held together with asphaltenes and other crude
oil impurities are formed. The networks are held together through
hydrogen, van der Waals, ionic and, in some cases, covalent bonds.
Exemplary Z2 zeolites include the SMZ line of zeolites available
from GSA Resources, Inc. (Tucson, AZ).
[0042] Other zeolites, termed Z1, have a negative surface charge.
It is possible for anions to become trapped in the pore of Z1
zeolites due to a local electro static field resulting from an
imbalance in charge (net positive) due to the oxygen molecules at
the corners of the tetrahedron cage. However this can only happen
from impaction of the anion close to the cage, which allows the
anion to get past the natural negative surface charge of Z1. As
long as the species are able to fit into the pores, they have the
possibility of being adsorbed, if they have the correct chemical
and physical properties, primarily size and charge. A second
function of Z1, is to serve as an anionic coagulant.
[0043] Z1affects surfactant behavior at the oil-water interface and
influences water induction and coalescence. For example, an
emulsion treated with Z1 breaks as much as ten times faster than an
untreated emulsion.
[0044] Contacting a petroleum composition with a combination of
zeolite and demulsifier can cause oil to dehydrate under conditions
at which demulsifier alone does not work because salts and/or
cations desorb into the water phase or adsorb to the surface of the
zeolite. Enough of the surfactants such as acids, salts,
asphaltenes, and resins are removed by the zeolite such that water
does not remain dispersed in the oil phase. Exposure to the zeolite
surface/pores and demulsifier causes films around the water droplet
to drain, rupture, and coalesce. Surfactants are adsorbed from the
oil-water interface to the zeolite and/or into the water phase.
[0045] It may desirable to process zeolite(s) Z1/Z2, for example by
grinding or the like, to achieve a particular particle size
distribution (PSD). The PSD can be adjusted, depending on the
particular petroleum composition and conditions, to achieve optimum
settling velocity of the zeolite(s).
[0046] FIG. 1 illustrates an embodiment of the disclosed process.
Referring to FIG. 1, fluid streams flow in conduits between the
unit operations. Typically, the conduits are designated with odd
numbers or are not numbered. Stream 3 designates a previously
diluted, extra heavy crude or bitumen such as Athabasca entering an
existing refinery. Previously diluted extra heavy crude or bitumen
2 is routed via conduit 3 to a heated surge tank 4 and then to a
bulk separator 8. The contents of stream 3 can be blended with
naphtha from tank 46. This stream can optionally undergo in-line
injection of additional naphtha, for example, via a flow through a
static mixer unit. The mixture is then routed to a mixer tank 12
and then to extractor 6 for surfactant removal. Mixer tank 12 can
be heated. Prior to entering extractor 6, demulsifier can be added
to the stream or into the first top few stages of the extractor 6.
The flow arrangement of extractor 6 can be countercurrent or
co-current depending on the crude and based on the best arrangement
determined in laboratory testing. FIG. 1 illustrates a co-current
arrangement. Extractor 6 preferably removes a substantial amount of
bulk solids having particles size greater than or equal to fines,
wash water containing salt and other ions, and zeolite particles
containing salts, acids, fines, asphaltenes, ions and other
surfactants.
[0047] The amount of naphtha generally required in extractor 6 is
typically less than that required in conventional processes, due to
the subsequent steps in the process explained below. The amount of
naphtha required depends on the viscosity and density of the extra
heavy crude mixture which arrives at the refinery previously
diluted. The separation process is typically operated at a
temperature of about ambient to about 100.degree. F. The system can
be operated at higher temperatures, but doing so may not be
economically optimal. Likewise, in a low pressure system i.e.,
about ambient to about 150 psi; the system can also be operated
under higher pressure (above 150 psi), but this might be cost
prohibitive. This temperature elevation also results in reduced
diluent requirement. Addition of zeolite particles further reduces
diluent requirement. For example, at ambient conditions, a 1:2
diluent to feed ratio for heavy crude accomplishes separation of
heavy crude containing a stable emulsion. Alternatively higher
diluent to feed ratios such as 3-4:1 can be used.
[0048] The aqueous feed mixture used in extractor 6 can be prepared
by mixing several components with water and the heated extra heavy
crude/bitumen and diluent in mixing tank 12. For example,
optionally a coagulant 120, a base 14, or acid 16 can be routed to
tank 12 for particle size and/or pH manipulation. One or more
zeolites can also be added to mixing tank 12 (FIG. 1 illustrates Z1
being added to the mixing tank). Alternatively, zeolite(s) can be
added directly to extractor column 6 (FIG. 1 illustrates Z2 being
added to the extraction column). Depending on crude contaminant
load, zeolites Z1 and Z2 are combined in specific ratios ranging
from 10:1 or 1:10 to provide optimum removal of fines, salts,
acids, ions, other surfactants, and small amounts of asphaltenes
which are also functioning as surfactants. According to one
embodiment, only one of Z1 or Z2 is used during the surfactant
removal extraction. The oil/water/slurry is then routed from tank
12 to extractor 6.
[0049] The zeolite is originally in particulate form, and can be
formed into a slurry, for example with naphtha, an aliphatic
hydrocarbon, naphtha, or naphtha spiked with additional treatment
chemicals. Slurried zeolite can be transferred to an agitated surge
tank through a conduit, or directly to the next few stages directly
beneath the demulsifier injection stages. Transferring can be done
by one or more units selected from rotary pump, air pump,
reciprocating pump, centrifugal pump, gravity feed, gas pressure,
blower, compressor, and the like. The amount of zeolite added
depends on the suspect or known amount of asphaltene molecules and
other impurities in the composition.
[0050] In extractor 6, there may be mixing at each stage of the
column. There can be a quiet zone at the top of the column above
the mixing section where product accumulates as column extract, and
a settling zone at the bottom of the column, below the mixing
section, where water, solids, and other contaminates accumulate as
raffinate. Due to density differences, the crude feed/diluent rises
up in the column as the water and solids fall to the bottom into
the settling zone. There is intimate mixing at each stage of
extractor 6 taking advantage of the co-current arrangement,
resulting in efficient removal of water, salt, solids, and
contaminants from the crude. Extractor 6 represents a process of
multiple steps of mixing and settling carried out in one vessel.
Additives such as the demulsifier and zeolite can maintain
interfacial tension so that emulsions break and are difficult to
reform.
[0051] Optionally, with some heavy or extra heavy crudes, a
countercurrent extractor configuration may result in better extract
quality. In this case, the heated feed (possibly with a small
amount of diluent) is routed to a surge tank 10, and it is fed into
the extractor 6. Slurry of zeolites Z1 and/or Z2 can be added to
extractor 6 via tank 12 or directly to the column. The naphtha can
be added into the system via the bottom entry into the extractor 6.
If the demulsifier is aqueous based, it can be injected in-line to
and be added with the zeolite (Z1 and Z2) slurry. If it is
hydrocarbon based, it can be injected in-line to and added with the
naphtha.
[0052] Water coming off the bottom of extractor 6 is routed to a
water separation unit (not shown). For example, the aqueous stream
coming off the bottom of extractor 6 can be chemically treated as
necessary, for example with a coagulant, a flocculent, and/or
possible pH adjusting reagents. Some zeolite can optionally be
added to the stream. The aqueous stream can then be routed into a
clarifier for separation. The solids in the bottom of extractor 6
can be pulled off and routed directly to a surge tank (not shown)
and/or a filter press unit for recovery and/or purification.
[0053] Returning to the co-current option, extract from extractor 6
overflows into a surge tank 18 where it accumulates and can
optionally be pumped to solid/liquid hydrocyclone 20 to remove
entrained solids from the liquid phase. Manufacturers of
hydrocyclones report removal of 5 micron material in the correct
fluid viscosity and density differences between the solid and
liquid phase (e.g. sand in water). Lighter solids such as silt and
clay are more difficult to remove on their own, however, the
zeolite Z2 has a positive surface charge and contributes to
"coagulation" of these finer, less dense particulate, facilitating
their removal. As a result, much of the finer, less dense material
undergoes a change in size and density, and will fall to the bottom
of extractor 6, and will most probably never pass to hydrocyclone
20. However, if there is carryover, solid/liquid hydrocyclone 20
can act as a "slug catcher".
[0054] The underflow of the solid/liquid hydrocyclone 20 can be
routed via a conduit (not shown) to the bottom of extractor 6, at
about the interface between the hydrocarbon layer and water layer,
so that solids are not re-contaminating the crude and have a
minimum distance to settle out.
[0055] The overflow from solid/liquid hydrocyclone 20 can be routed
to a liquid/liquid hydrocyclone 22, for removal of any entrained
free water in order to minimize water concentration in the feed to
extractor 24. Hydrocyclone 22 can be seen as a "slug catcher"for
water.
[0056] The overflow from liquid/liquid hydrocyclone 22, which is a
naphtha-modified, dewatered, desalted, de-metallized, solids-free,
acid-free crude stream, is then routed to second extractor 24. The
underflow from the liquid/liquid hydrocyclone 22, which is
primarily water, can be routed back and injected at the level of
the water layer in extractor 6 through a conduit (not shown).
[0057] The naphtha modified, dewatered, desalted, de-metallized,
solids-free, acid-free crude stream can be combined with zeolites
Z1 and/or Z2, ranging from about 10:0 to about 0:10. The ratio of
zeolites can be adjusted depending on the crude. After mixing in an
in-line mixer 26, the naphtha-modified, dewatered, desalted,
de-metallized, solids-free, acid-free crude and zeolite mixture is
routed to extractor 24. The extractor can be operated
counter-currently or co-currently.
[0058] In extractor 24 there maybe a multi-stage mixing and
settling with a phase separation zone under the mixing stages for
raffinate accumulation and a phase separation zone on top of the
mixing stages for extract accumulation.
[0059] The solvent used in extractor 24 can be, for-example,
naphtha, which can be fed from an accumulator 28. A high
performance asphaltene precipitator can be selected dependent on
crude and injected in-line from a tank 30 prior to the combined
stream entering the extractor 24.
[0060] As described above, Z1 has a negative surface charge and Z2
has a positive surface charge. Z1 removes additional cations that
may have been entrained in the extract from the first extractor
column unit 6. It will also contribute to water droplet induction
and coalescence. Z2 has a positive surface charge and will adsorb
anions and negatively charged fine particles from the hydrocarbon
phase. Additionally, Z2 may be slurried in naphtha that is spiked
with an asphaltene precipitator. The surface of Z2 is also
oleophilic, and therefore the alkanes and the asphaltene
precipitator partition to the surface of the Z2. This results in
asphaltene precipitation on to the surface of the Z2 particle,
resulting in a density change for the precipitating asphaltenes.
Self-agglomeration of the precipitating asphaltenes on the surface
is also likely to occur.
[0061] Extractor 24 functions due in-part to density differences,
with the heavy phase of asphaltenes and solids (and any remaining
water) falling to the bottom of the extractor 24, and the
substantially cleaned, dried, deasphalted, naphtha-modified,
possibly heated, crude rising to the top of extractor 24 as the
extract.
[0062] The extract from extractor 24 can then overflow into a surge
drum 32 and can be pumped through a heat exchanger 34 and
optionally to a solid/liquid hydrocyclone (not shown). Optionally,
the overflow from the solid/liquid hydrocyclone can then be routed
into a deep bed filter 36 with mixed media of Z1 and Z2 having
particle sizes, for example, ranging from about 50 to 200 microns.
The purpose of deep bed filter 36 is to provide a final polish to
the crude, removing any remaining salt and acid (if required by
client specification) prior to entering the diluent recovery
section of the process.
[0063] The mixture leaving filter 36 can be treated to separate the
crude from the solvent. For example, a series of flash drums cam be
used to remove naphtha from the crude stream to recycle the naphtha
for re-use. The hydrocarbon product, or synthetic crude,
originating from the flash drum(s) can be fed forward for secondary
upgrading by the existing refinery units. For the application of
the described processes for upgrading Athabasca Bitumen with 17%
asphaltene and 17% solids concentrations (assumed), the product
stream is estimated to contain about 50% distillate and 50% vacuum
gas oil, according to an exemplary embodiment.
[0064] Asphaltenes combined with zeolite and other hydrocarbons
come off the bottom of deasphalting extractor 24, as the raffmate.
The stream is routed to a mixing vessel 60 where it is combined
with toluene (toluene stream not shown), held, and mixed. The
contents of vessel 60 are then routed to a clarifier 62, where the
solids fall to the bottom, and toluene/asphaltene/hydrocarbon
mixture becomes the supernatant.
[0065] The zeolite solids can then be routed to a dryer 64 where
the remaining toluene is evaporated from the solid's surface. The
dried solids can then be pneumatically conveyed to mixer 124 where
they are washed with NaCl, sent to mixer 126 where the particles
are rinsed with water, and then routed to separator 128 where the
particles separate from the water stream. The particles are then
sent to spray dryer 66 where hot nitrogen can be introduced to
regenerate the surface and pores of the zeolite particles. The
particles can then be conveyed to a dryer 68 where they are cooled
and then optionally sprayed with surface modifier (possibly
including, but not limited to, a quaternary amine). The particles
can be further dried and stored for re-use.
[0066] The overhead from clarifier 62 containing the
toluene/asphaltenes/hydrocarbon is sent can be treated to flash off
the toluene and naphtha fractions. The overhead from flash drum can
distilled to separate the toluene from the naphtha, and both
solvents can be recycled.
[0067] The reduction in impurities will enhance the typical run
length of a crude distillation unit prior to having to shutdown for
maintenance, such as cleaning of heat exchangers and decoking of
furnace tubes. In addition, the distillation bottoms, either
atmospheric tower bottoms or vacuum distillation tower bottoms,
will comprises less solids, salts, and asphaltenes, thereby
improving efficiency of downstream unit operations.
[0068] Undiluted, extra heavy crude or bitumen such as Athabasca
can be treated at an existing refinery using essentially the same
process steps and apparatus illustrated in FIG 1.
[0069] One of skill in the art will appreciate that the disclosed
process can be implemented in a variety or ways. For example, if a
refinery receives diluted, extra heavy crude (e.g.
Athabasca+Diluent), the disclosed process can be installed before
the desalter. Doing so provides a way to upgrade the acidic, heavy
crude to lighter, cleaner feedstock for the refinery by removing
asphaltenes (and NSO and metals contained therein), decreasing
particulate content in feedstock, which in turn reduces wear in
downstream rotating equipment and plugging of catalyst beds,
decreases catalyst deactivation. The process also reduces corrosion
through naphthenic acid and salt removal, removing additional
heteroatoms contained in the acids; reduces desalter operational
issues caused by emulsions; and produces a product depleted in
ultra-fines or aromaticity issues.
[0070] The refiner realizes benefits such as improved product
slate, increased fuels production; reduced production of
atmospheric pollutants; longer catalyst life; and increased
refinery profitability. The refiner is able to produce a refinery
feedstock with a reduced level of heteroatoms. The product mixture
will comprise predominately distillate and vacuum gas oil boiling
range components.
[0071] A refinery receiving undiluted heavy crude (e.g. Merey), can
install the disclosed process unit before desalter. This improves
desalter operation by eliminating emulsion issues; removes
asphaltenes, salts, acids, and other contaminants; produces an
upgraded crude product without ultra-fines, aromaticity issues;
reduces deactivation and plugging of catalyst beds; reduces
corrosion in refinery equipment.
[0072] The disclosed process can be implemented at the production
facility that produces, for example, extra heavy crude (e.g.
Athabasca bitumen produced using Steam Assisted Gravity Drainage)
that cannot be pipelined w/o diluents. The process breaks
emulsions; removes asphaltenes and other contaminants; upgrades
crude, resulting in higher market value; provides excellent
performance in remote locations; produces a product without
aromaticity issues; produces a product without salt, acid, or
ultra-fines issues. The process thereby improves pumpability of
crude and reduces or eliminates the need for diluent to be added to
the crude.
[0073] As an example, thick, acidic heavy bitumen (tar sand) is
produced using Steam Assisted Gravity Drainage and must be diluted
with naphtha to thin it before it can be pumped through a first
pipeline from the producing field to refineries for processing. The
diluent is distilled from the bitumen-diluent mixture at the
refinery and the diluent is returned through a second pipeline to
the producing field to dilute more bitumen. The heat and electrical
energy used to recycle the diluent and the second pipeline
represent unnecessary costs. If a small plant implementing the
disclosed process is installed in the production field, the product
can be sent for distillation and further processing in the existing
refinery without adding a diluent. The quality of the refinery
feedstock is improved due to reduced contaminants, salinity, water,
acidity, asphaltenes, heteroatoms, and fines. Reduced heteroatoms
may result in a reduced load on hydrotreater catalyst. Special
metallurgy in crude distillation columns may not be required to
mitigate corrosion resulting from naphthenic acids. A better
quality cracking feedstock for FCC's may be produced.
[0074] The disclosed process can be implemented in bitumen (tar
sand) production obtained from surface mining and hot water
extraction. Tar sand bitumen is surface mined in a solid form and
moved to the processing operation using trucks. Once at the bitumen
production plant, the solid bitumen is mixed with hot water and
caustic, the bitumen is removed as froth, and is then further
upgraded by the refinery. The disclosed process can be substituted
for the extraction and separation process currently used in the
surface mining operation, resulting in a deasphalted, acid-free,
salt-free, dehydrated bitumen, having a higher market value.
Additionally, the problems associated with Bitumen Derived Crudes
(BDC), such as aromaticity and ultra-fines content, are minimized
with the inventive technology, which may allow it's product to be
used as FCC feedstock. The ultra-fines and aromaticity issues have
resulted in significant problems for BDC's (and other coked
bitumen) to be marketed as FCC feedstock. With the ultra-fines and
aromaticity issues minimized, the refinery processing the
deasphalted bitumen produced by the disclosed process can save
significant costs because of refining a higher valued
feedstock.
EXAMPLES
Example 1: Heavy Crude
[0075] Heavy crude from the Mississippi area (30 grams) was diluted
with naphtha (17 grams) in a test tube. Zeolite (1.5 grams, GSA
Resources, Inc. product number 500RW), demulsifier (1000 ppm, Baker
Hughes product number RE4555DMO), and of an asphaltene precipitant
(500 ppm, Baker Hughes product number RE4877ASO) were added to the
crude composition. Upon stirring for 5 minutes a water layer formed
on the bottom of the tube. The test tube was centrifuged at 1000
rpm for 10 minutes. The mixture separated into four layers:
hydrocarbon/asphaltene/water/solids. The procedure was repeated
with another 30 gram sample of crude and the combined supernatants
were combined and analyzed (Sample 1A).
[0076] Sample 1A (30 grams) was further contacted with naphtha (7.5
grams) and the same zeolite (0.8 grams), asphaltene precipitant
(500 ppm), and demulsifier (1000 ppm) as described in the preceding
paragraph. The mixture was centrifuged at 1000 rpm for 10 minutes
and the hydrocarbon supernatant was analyzed (Sample 1B). The
composition of Samples 1A and 1B are presented in Table 2 and the
removal efficiencies for the samples are shown in Table 3.
TABLE-US-00002 TABLE 2 Results of Contacting Heavy Crude with
Additive Package Crude Sample 1A Sample 1B TSS (mg/L) 22,250 150
100 Asphaltene (wt %) 5.87 3.6 2.5 Water (wt %) 15.63 0.772 0.172
Hydrocarbon (wt %) 76.3 95.63 97.33 Asphaltene/Hydorcarbon 0.077
0.038 0.024 SG ( ) 1.004 0.8196 0.7848 Viscosity (cP) 525 4.01
2.11
[0077] TABLE-US-00003 TABLE 3 Contaminant Removal Efficiencies
Removal in Removal in Component Stage 1 (%) Stage 2 (%) Solids 99.3
99.6 Asphaltene/Hydrocarbon 51 69 Water 95.1 98.9
[0078] The disclosed process provides good water drop, solids
removal efficiency, and asphaltene/HC removal. The analytical data
based on the laboratory experiments show that removal of only 69%
of the asphaltenes contributes to affecting almost 99% of water
removal. Since almost all of the water is removed from a dispersed,
emulsified state, it is likely that almost all of the salt in the
water phase was also removed.
[0079] Table 1 reflects a significant reduction in viscosity. This
is due to: diluent addition, emulsion breakage, water removal, and
asphaltene removal. (at 40 deg C.) Conventional crude has a
viscosity of about 11 cP (at 40 deg C.), medium crude is about 68
cP (at 40 deg C.), and heavy is about 619 cP (at 40 deg C.).
* * * * *