U.S. patent application number 17/181559 was filed with the patent office on 2021-08-26 for liquid/liquid extraction of hydrocarbons in bulk storage tanks.
This patent application is currently assigned to Macquarie Commodities Trading US, LLC. The applicant listed for this patent is Macquarie Commodities Trading US, LLC. Invention is credited to Vikas Dwivedi, Virginia Flippin Green, Aaron Kildow, Monica Lloyd.
Application Number | 20210261871 17/181559 |
Document ID | / |
Family ID | 1000005444847 |
Filed Date | 2021-08-26 |
United States Patent
Application |
20210261871 |
Kind Code |
A1 |
Lloyd; Monica ; et
al. |
August 26, 2021 |
LIQUID/LIQUID EXTRACTION OF HYDROCARBONS IN BULK STORAGE TANKS
Abstract
Described herein are methods and systems for performing
liquid-liquid extraction in bulk tankage. According to certain
embodiments, the liquid-liquid extraction can occur in a bulk tank
via a circulation loop, in which a solvent mixture is injected with
the hydrocarbon ahead of mix valves on the circulation loop.
According to other embodiments, a misting system is installed in
the vapor or head space of bulk tankage. The misting system
distributes small micro-drops of a solvent mixture so as to cause a
uniform lay down over the entire top surface area of hydrocarbon.
The solvent mixture migrates from the top surface of the
hydrocarbon to the bottom of the bulk tank, reacting during
migration to cause liquid-liquid extraction.
Inventors: |
Lloyd; Monica; (Dickinson,
TX) ; Kildow; Aaron; (Houston, TX) ; Dwivedi;
Vikas; (Houston, TX) ; Flippin Green; Virginia;
(Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Macquarie Commodities Trading US, LLC |
Houston |
TX |
US |
|
|
Assignee: |
Macquarie Commodities Trading US,
LLC
Houston
TX
|
Family ID: |
1000005444847 |
Appl. No.: |
17/181559 |
Filed: |
February 22, 2021 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62979778 |
Feb 21, 2020 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
C10G 2300/206 20130101;
C10G 2300/203 20130101; C10G 19/02 20130101; C10G 21/16 20130101;
C10G 2300/208 20130101; C10G 61/04 20130101; C10G 5/04
20130101 |
International
Class: |
C10G 19/02 20060101
C10G019/02; C10G 5/04 20060101 C10G005/04; C10G 61/04 20060101
C10G061/04; C10G 21/16 20060101 C10G021/16 |
Claims
1. A liquid-liquid extraction method comprising: determining a
total acid number of hydrocarbon stored in a bulk tankage unit;
dosing a solvent feed with a caustic solution at 1,000 ppm of the
caustic solution per point of the total acid number of hydrocarbon;
circulating the solvent feed dosed with the caustic solution into
the bulk tankage unit via one or more circulation loops connected
to the bulk tankage unit, wherein circulating causes the solvent
feed dosed with caustic solution to contact the hydrocarbon;
extracting metal soaps from the hydrocarbon formed in the bulk
tankage unit; decanting the solvent mixture from the hydrocarbon in
the bulk tankage unit; and transporting the decanted solvent
mixture from the bulk tankage unit to a solvent recovery tank
separate from the bulk tankage unit, wherein soluble constituents
of the solvent mixture are separated from the decanted solvent
mixture and the solvent mixture is recycled for reuse.
2. The liquid-liquid extraction method of claim 1, wherein the
decanted solvent mixture transported from the bulk tankage unit to
the solvent recovery tank comprises naphthenates and asphaltenes
from the hydrocarbon stored in the bulk tankage unit.
3. The liquid-liquid extraction method of claim 2, wherein the
decanted solvent mixture transported from the bulk tankage unit to
the solvent recovery tank further comprises salts, metals,
chlorides, hydrogen sulfide, mercaptans, phenols, and polycyclic
aromatic hydrocarbons from the hydrocarbon stored in the bulk
tankage unit.
4. The liquid-liquid extraction method of claim 1, wherein the
solvent feed comprises water, one or more alcohols, and
glycerin.
5. The liquid-liquid extraction method of claim 4, wherein the
solvent feed comprises ethanol.
6. The liquid-liquid extraction method of claim 4, wherein the
solvent feed comprises 30-50 wt.-% alcohol(s), 20-40 wt.-% water,
and 20-40 wt.-% glycerin.
7. The liquid-liquid extraction method of claim 1, wherein
circulating the solvent feed dosed with caustic solution into the
bulk tankage unit comprises circulating the solvent feed in a ratio
amount of at least 10:50 by mass compared to the amount of the
hydrocarbon in the bulk tankage unit.
8. The liquid-liquid extraction method of claim 1, wherein
circulating the solvent feed dosed with caustic solution into the
bulk tankage unit causes the solvent feed to contact the
hydrocarbon for at least six hours.
9. The liquid-liquid extraction method of claim 1, wherein
circulating the solvent feed dosed with caustic solution into the
bulk tankage unit causes the solvent feed to contact the
hydrocarbon for a period until the total acid number of the
hydrocarbon is non-detectable.
10. The liquid-liquid extraction method of claim 1, further
comprising, after transporting the decanted solvent mixture from
the bulk tankage unit to a solvent recovery tank separate from the
bulk tankage unit, acidizing the decanted solvent mixture,
recovering asphaltene and naphthenic acid from the decanted solvent
mixture, and recycling the solvent mixture through reverse osmosis
skids.
11. The liquid-liquid extraction method of claim 10, wherein
recycling the solvent mixture through the reverse osmosis skids
comprises capturing phenols and polycyclic aromatic
hydrocarbons.
12. The method of claim 11, further comprising: sending the
captured phenols and polycyclic aromatic hydrocarbons to thermal
desorption units; producing steam at the thermal desorption units;
and using the steam in one or more heating units integrated with
the bulk tankage unit.
13. The liquid-liquid extraction method of claim 1, wherein
circulating the solvent feed dosed with caustic solution into the
bulk tankage unit comprises using a heat exchanger on the one or
more circulation loops to heat the solvent feed dosed with caustic
to a temperature ranging from at least 100.degree. F. up to and
including 200.degree. F.
14. The liquid-liquid extraction method of claim 1, wherein dosing
the solvent feed with the caustic solution occurs concurrently as
the solvent feed is circulated into the bulk tankage unit.
15. The liquid-liquid extraction method of claim 1, further
comprising additionally dosing the solvent feed with an acid and
circulating the solvent dosed with acid into the bulk tankage unit
to cause the acid to contact the hydrocarbon.
16. A bulk tankage liquid-liquid extraction system comprising: a
bulk storage tank that houses static hydrocarbon; a solvent feed
tank separate from the bulk storage tank; a circulation loop
connecting the solvent feed tank to the bulk storage tank,
configured to circulate a solvent mixture into the bulk storage
tank so as to contact the solvent mixture with the static
hydrocarbon in the bulk storage tank; and a sump unit located on
the bottom half of the bulk storage tank, the sump unit configured
to pump the solvent mixture out of the bulk storage tank after
completion of a liquid-liquid extraction reaction between the
solvent mixture and the static hydrocarbon.
17. The system of claim 16, further comprising a heating unit
installed at the bottom of the bulk storage tank, along one or more
sidewalls of the bulk storage tank, or both, wherein the heating
unit is a hot oil or steam coil system configured to heat the
static hydrocarbon during the liquid-liquid extraction reaction
completed inside the bulk storage tank.
18. The system of claim 16, further comprising a heat exchanger
attached to the circulation loop, wherein the heat exchanger is
configured to heat the solvent mixture during transport from the
solvent feed tank to the bulk storage tank.
19. The system of claim 16, further comprising a sparging unit at
the bottom of the bulk storage tank, wherein the sparging unit
comprises a plurality of vortexing nozzles configured to blend the
static hydrocarbon and the solvent mixture after the solvent
mixture is circulating into the bulk storage tank.
20. The system of claim 16, wherein the sump unit is configured to
pump naphthenates, asphaltenes, hydrogen sulfide, mercaptans, and
phenols out of the bulk storage tank with the solvent mixture after
the completion of the liquid-liquid extraction reaction.
21. The system of claim 16, further comprising a plurality of
electrical probes connected to a roof on the bulk storage tank,
wherein the plurality of electrical probes deliver electrical
current into the static hydrocarbon inside the bulk storage tank.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a non-provisional of and claims priority
to U.S. Provisional Patent Application No. 62/979,778, filed on
Feb. 21, 2020. The aforementioned application is hereby
incorporated by reference in its entirety.
FIELD OF THE INVENTION
[0002] Described herein are embodiments of liquid-liquid extraction
processes for use with hydrocarbons in bulk storage tanks, and
embodiments of systems to perform such processes.
BACKGROUND OF THE INVENTION
[0003] Liquid-liquid extraction is a separation process for
isolating the constituents of a liquid mixture. The process
involves extracting a solute from a solution by bringing it into
contact with a second immiscible solvent in which the solute is
soluble. It is, generally speaking, an established process, and
together with distillation, the two processes are regularly
practiced industrial separation procedures. Whereas distillation
causes separation by utilizing the differing volatilities of the
components of a mixture, liquid-liquid extraction causes separation
by using a particular solvent (or mixture of solvents) to partition
immiscible components.
[0004] The petroleum industry utilizes liquid-liquid extraction to
separate, for example, different types of hydrocarbons using
solvents such as liquified sulfur dioxide, furfural and diethylene
glycol. In general, extraction is applied when the materials to be
extracted are heat-sensitive or nonvolatile and when distillation
would be inappropriate because components have similar boiling
points, have poor relative volatilities, or form azeotropes.
[0005] One example of a simple extraction operation is
single-contact batch extraction, in which the initial feed solution
is agitated with a suitable solvent, allowed to separate into two
phases, and then the solvent containing the extracted solute is
decanted. On an industrial scale, the extraction operation
typically involves more than one extraction stage and is normally
carried out on a continuous basis. The equipment may be comprised
of either discrete mixers and settlers or some form of column
contactor in which the feed and solvent phases flow
counter-currently by virtue of the density difference between the
phases. Final settling or phase separation is achieved under
gravity at one end of the column by allowing an adequate settling
volume for complete phase separation. Such extraction operations
are most typically performed in process units, with the hydrocarbon
moving through the unit. There is a void in industry for performing
liquid-liquid extraction on static hydrocarbons that are stored in
bulk tankage.
[0006] Naphthenic Acid has been a nemesis throughout the refining
process for years. Typically, the majority of acids present in a
hydrocarbon feed are naphthenic acids (a subset of carboxylic
acids). They generally have high total acid numbers ("TAN") and are
oil soluble. These characteristics cause various problems in the
refining process.
[0007] At a crude distillation unit, for example, caustic washes
that react with naphthenic acids convert the carboxylic acids into
naphthenates, which can create severe emulsions in the desalting
units. Such emulsions can greatly decrease desalting efficiency and
often minimize throughput to the entire distillation unit. This
leaves refiners with a choice of two undesirables: do not run high
naphthenic acid crudes at all or minimize the relative percentage
of high naphthenic acid crudes in the overall blend. These would be
the options in order for the desalting units to maintain
efficiency. Crude oil itself (not high naphthenic acid crudes)
typically has naphthenates existing in its composition, most
commonly in the form of calcium naphthenates or sodium
naphthenates--they may exist in the structure of iron, copper, and
magnesium as well.
[0008] The majority of naphthenic acids typically reside in the
heavier cuts of crude--because the majority of naphthenic acids are
a heavier molar weight, they tend to end up in the bottom cuts of
the crude. Accordingly, refiners may struggle with elevated
corrosion in the bottom portions of their atmospheric columns and
vacuum columns (typically where the heavier cuts reside) due to
naphthenic acid finding its way to those portions of such columns
and processing units. These problems can be exacerbated in systems
that lack suitable caustic washing processes. Refiners must also
limit their blend of crude feedstocks in order to minimize TAN in
heavy fuels that would trigger a discount to the sales price (fuel
must be blended to meet the upper threshold of a maximum 2.5
TAN).
[0009] By extracting the naphthenic acid in bulk tankage according
to the inventive embodiments described herein, refiners can remove
or lower the TAN of the virgin crude initially, before it is
refined, which minimizes (or even eliminates) downstream processing
and the above-stated problems. Implementing the systems and methods
described herein, refiners can extract naphthenic acid and lower
TAN from heavy fuel cuts in product tanks, which is can eliminate
the excess TAN discount they otherwise would be forced to take.
There is a void in industry for removing naphthenates and
naphthenic acid from static hydrocarbon stored in bulk tankage,
before downstream processing and without traditional refinery
operations.
[0010] Sulfur is another nemesis for refineries. Sulfur
specifications for all fuels are continually tightening, requiring
further removal of sulfur in order for refiners' products to meet
global governmental requirements. The traditional technology for
sulfur removal is a hydrotreater, a mechanism configured to perform
hydrotreating, or the reaction of organic compounds in the presence
of high pressure hydrogen to remove oxygen and other heteroatoms,
like sulfur. They are expensive units to build and operate,
requiring not only the hydrotreater itself for sulfur removal, but
also a hydrogen plant and downstream sulfur recovery unit.
Hydrotreaters are product specific and are effective on the lighter
cuts of oil, such as naphtha, kerosene, diesel, and gas oil, but
fairly ineffective on heavier cuts.
[0011] Technology for hydrotreating heavier cuts is limited. There
is no current technology to remove sulfur from the crude before it
is refined. Thus, a refiner's choices for a crude slate are often
very limited by the sulfur content of the crude and their
hydrotreater limitations. In addition, new international laws have
placed lower sulfur limits on heavier fuels, such as bunker fuels.
As a result, there is an increased need for new sulfur removal
technologies. Removing or reducing sulfur from the crude initially,
would provide refiners a greater selection of crudes without
overtaxing downstream hydrotreaters.
[0012] Some crude slates are known bad actors for desalting. Due to
various compounds, they are either difficult to desalt in a classic
desalter or they have extreme high levels of water initially that
is emulsified. High water levels in crude causes throughput issues
for the crude unit and increased downstream corrosion due to
desalter inefficiency. Desalters add fresh water to solubilize
salts. Even crudes that are dewatered before being refined will
take up water again in a desalter. Desalting and dewatering in
tankage will resolve throughput and corrosion issues derived from
these types of crudes. There is a need for a mechanism, apparatus,
or system to improve desalting--indeed, to completely desalt crudes
while minimizing water consumption and outfall.
[0013] In liquid-liquid extraction, the problem of what to do with
the resulting off-spec liquid being used for extraction is always
an issue. With amines, they must be stripped with the extracted
material removed. Disposal of water or solvent is expensive and can
become an insurmountable issue because of environmental
restrictions. Most refineries and terminals are already reaching
limits on outfall permits for quantity and biochemical oxygen
demand ("BOD") and chemical oxygen demand ("COD"). Disposal of any
quantity of water or solvent becomes an economic hurdle that would
render the process not viable.
[0014] Asphaltenes are another common type of material that plague
refineries. Most crudes have some level of measurable asphaltenes
(the percentage that are insoluble in n-heptane). Asphaltenes are
long chained molecules that have a polar tail, making them slightly
incompatible with the other constituents of crude oil. They can
cause havoc from production, transport, storage, and refining
because of their capacity to flocculate. Asphaltenes are highly
viscous and rich in sulfur, metals (in particular vanadium and
nickel, complexed metals with little capacity to form salts) and
nitrogen. Due to their polar tails, they cause emulsion issues at
desalters, as they migrate to the water/oil interface and
accumulate, resulting in oil undercarry and water overcarry into
the crude unit heaters and main fractionator. Asphaltenes are a
main source of fouling in crude preheat and vacuum units due to
their tendency to create depositions within the exchangers.
[0015] Currently, refinery de-asphalting processes take place on
residue streams, but the material in the streams must go through
the crude pre-heat, desalters, a main fractionation unit, and a
vacuum unit before it arrives at a location where de-asphalting can
effectively occur. This allows the asphaltenes to cause operational
issues on said units, as well as other downstream units. Regarding
downstream units, asphaltenes can migrate up the tower into higher
cuts, affecting such downstream units and the catalyst--the
catalyst, in particular, being sensitive to nitrogen and metal.
Further, asphaltenes tend to be rich in phenols, naphthalenes, and
other defined polycyclic aromatic hydrocarbons (PAHs). Such
materials are well known health hazards, as they have polar
constituents that are water soluble and can leach into the water
table. After vacuum residue goes through a de-asphalting unit, it
undergoes an air-blowing operation to oxidize the asphalt. One of
the primary reasons for doing so is to minimize the PAHs before the
asphalt can be marketed for commercial purposes. Air blowing of
asphalt is a major source of greenhouse gas emissions..
[0016] Until now, there has been limited technology to extract
undesirable materials, such as naphthenic acid, asphaltenes,
metals, hydrogen sulfide, and mercaptans, from hydrocarbon in bulk
tankage. The industry is therefore lacking and desirous of systems
and methods for stripping these materials from hydrocarbon (e.g.,
crude stock) before or during transit to a refinery and downstream
processing plants, or upon arriving at a processing site, without
having to use traditional distillation methods.
SUMMARY OF THE INVENTION
[0017] Embodiments described herein are directed to methods of
performing liquid-liquid extraction in bulk tankage, and systems to
facilitate the same. Embodiments of the present invention are
designed to treat hydrocarbon in bulk tankage (e.g., storage tanks)
while the hydrocarbon is statically contained in the bulk tankage
(e.g., at the hydrocarbon extraction site, in transit between
extraction and refineries or downstream processing sites, or at a
refinery but before undergoing traditional refinery processing
operations). Treatment of the hydrocarbon in the bulk tankage
typically occurs in batch processes. As described in more detail
below, in certain embodiments, circulation loops are on, attached
to, or otherwise incorporated with the tankage. These circulation
loops are configured to insert/inject solvent mixtures comprising,
e.g., one or more alcohol(s), water, glycerin and potentially other
materials. The solvent mixtures react with the hydrocarbon to
extract an array of undesirable materials from the hydrocarbon,
including naphthenic acid, asphaltenes, phenols, hydrogen, oxygen,
nitrogen, hydrogen sulfide and mercaptans, chlorides, sulfur, and
water soluble salts and/or metals as well as complexed metals such
as vanadium and nickel. After being injected in the bulk storage
tank and reacting with the hydrocarbon, the solvent eventually is
decanted and "drops out," at which point it can be pumped out of
the bulk storage tank to a solvent recovery tank. There, the
solvent is acidized and then cycled through external reverse
osmosis systems to remove metals and soluble salts to allow clean
solvent to be recycled and reused.
[0018] According to one embodiment, liquid-liquid extraction can
occur via a circulation loop in which a solvent mixture (e.g.,
comprising water, alcohol(s), and/or glycerin/glycerol) dosed or
combined with caustic is injected with the hydrocarbon ahead of mix
valves on the circulation loop. The solvent mixture may be infused
with the hydrocarbon input to form a single input stream or
injected independently and simultaneously with the hydrocarbon.
Additionally, a sparging system may be installed in the bottom of
the tank comprising vortexing nozzles. Thus, in certain
embodiments, the circulation loop is located on or integrated with
the bulk storage tank (a processing tank in the sense the
liquid-liquid extraction is carried out in said tank). Solvent
mixtures may be inserted/injected into the crude via the
circulation loop and sparging system to allow for contact between
the solvent and hydrocarbon. In some embodiments, heat is used in
the process. To facilitate that, heat exchangers may be installed
on the circulation loop or heaters may be installed in the bottom
of the tank to supply necessary heat. An embodiment may also
include an elevated high draw, which will cause the hydrocarbon to
be exposed to the solvent mixture more quickly. While systems and
methods described herein may refer to the storage and processing of
crude oil, it should be understood that the embodiments of the
present invention are effective with all types of hydrocarbon
(e.g., all types of crude, vehicle fuels, lubricating oils, bunker
oils etc.).
[0019] According to another embodiment, a misting system is
installed in the vapor space or head space of the bulk tankage. The
misting system creates small micron drops of a solvent mixture that
"lay down" over the entire top surface area of the hydrocarbon and
migrates through the hydrocarbon, reacting as it falls to the
bottom of the tank where it is pumped off from the sump.
[0020] In order to facilitate liquid-liquid extraction in fuel oil
or hydrocarbons with an extremely low American Petroleum Institute
("API") gravity, one embodiment comprises a sparging system that
can utilize steam along with the solvent that has a higher vapor
point. Although most chemistries added to the steam in accordance
with this invention have a vapor point higher than 212.degree. F.,
the steam provides a distribution system as well as the water
source to combine with the solvent for the extraction to occur. The
steam and solvent mixture condenses once it is injected into the
tank and rises to the top, where high draws allow for the water and
solvent to be removed.
[0021] Embodiments of the systems described herein have been found
to be particularly effective for liquid-liquid extraction of: (1)
naphthenic acid from hydrocarbon; (2) sulfur from hydrocarbon; and
(3) water soluble salts or metals (4) asphaltenes and the
constituents that are heavily enriched in said asphaltenes. And,
according to certain embodiments, once acid, sulfur, asphaltenes,
and salts are removed, extracted naphthenates can be converted back
to naphthenic acid for sale, extracted sulfur can be resold,
extracted asphaltenes can be marketed to various commercial outlets
and extracted flocculate salts may be properly disposed. Moreover,
the water/solvent mixture used for liquid-liquid extraction can be
re-used within the process. Certain other embodiments utilize
ultrasonic sound waves, either initially, or throughout the
extraction process. Doing so excites molecules, which can expedite
reactions.
[0022] According to another embodiment of the present invention, a
method of liquid-liquid extraction comprises several steps. In the
first step, it is important to understand the compositional makeup
of the mixture. It is advisable to check for certain physical
properties, such as API gravity, total metals (with particular
attention to metals that have the potential to become salts or
metal soaps, such as sodium, calcium, magnesium, potassium, iron),
total acid number ("TAN"), percent (%) asphaltenes, and viscosity.
This initial step further comprises determining and measuring the
total volume of hydrocarbon coming into the system or bulk tankage.
In certain embodiments, an additional initial acid/solvent washing
step may be performed to convert metal naphthenates into naphthenic
acid in order to allow the metals to drop out with the solvent.
This step may be useful, for example, when metal levels (e.g.,
calcium levels) are extremely high.
[0023] The second step of this exemplary embodiment is to calculate
the dosage of caustic chemistry (e.g., potassium hydroxide (KOH) or
sodium hydroxide (NaOH) solution) to be dosed/injected into the
solvent for the solvent washing step. Using KOH or NaOH, dose the
caustic at 1,000 ppm per every point of total acid. As KOH is
slightly weaker, it can require a stronger dose than if utilizing
NaOH. A simple lab dosage of hydrocarbon being stirred with the
caustic and a check of total acid will confirm proper dosage
amount. For example: A TAN of 5.0 would require a dosage of 5,000
ppm of caustic.
[0024] The third step of this exemplary embodiment is to combine
caustic-dosed solvent and hydrocarbon. The use of caustic to
neutralize acids (which are most likely naphthenic acids) will form
metal soaps, which tend to create severe emulsions. Water alone is
not effective in extracting acids without also extracting
hydrocarbon. Rinsing the oil with a solvent of water and alcohols
allows for the extraction of metal soap without extracting
hydrocarbon other than hydrocarbons specifically targeted such as
asphaltenes or PAHs that are also targeted due to their polarity
issues. Many alcohols are effective. For example, a solvent recipe
may comprise 30-50% alcohol(s), 20-40% water, 20-40%
glycerin/glycerol may be used (% by weight), where one useful
solvent mixture comprises 40 wt.-% ethanol, 30 wt.-% water, and 30
wt.-% glycerin/glycerol. Ethanol provides for a cleaner, more
efficient extraction of soaps, as compared to water and glycerin
alone. Glycerin/glycerol in the solvent combination is useful in
order to provide a solvent gravity that is heavy and desires to
drop out of the hydrocarbon in tankage.
[0025] Generally, the solvent-to-oil ratio may be 10:50 by mass, or
alternatively 20:40 by mass. In certain embodiments, the solvent
can be blended with the hydrocarbon on the run-down from a ship or
barge or on a circulation loop after hydrocarbon is in the tank. In
certain embodiments, the caustic can be injected neat into the
crude or pre-dosed into the solvent. Pre-dosing caustic into the
solvent may provide benefits of better distribution and
contact.
[0026] In this step, according to certain embodiments, the solvent,
hydrocarbon, and caustic are circulated together for at least 6
hours, advantageously at least 12 hours up to and including 24
hours, to allow for full contact of acids and caustic. It may be
useful to periodically check the TAN of the solvent/hydrocarbon
mixture to determine if full reaction has taken place. For a full
reaction, the TAN will be non-detectable or a minimal value.
Reaction and separation happen regardless of temperature and can be
performed at ambient conditions. Notwithstanding this, circulation
can also occur under elevated heated conditions. Slight amounts of
heat (no more than 150.degree. F., due to boiling points of
alcohols, for example) can facilitate more efficient blending and
separation because elevated temperatures lower the viscosity of the
hydrocarbon. After enough contact has taken place, circulation
stops and the tank is allowed to become sedentary.
[0027] At this point in the process, the solvent will immediately
begin to drop and separate from the hydrocarbon. Once approximately
30% of the solvent has separated, the solvent/metal soap can begin
to be pumped off to treatment skids (or treatment tanks). It is
expected that total solvent drop out will take approximately 24
hours. The metal soap content expected to be recovered is
approximately 0.1% to 15.0% of crude volume per point of TAN. In
addition, if original metals (e.g., sodium or calcium) are present
in excessive quantities, then it may be assumed that there was a
pre-existing metal soap present, which will increase volume per the
ppm reported. After solvent has been removed, total metals, pH of
oil and water, percent (%) asphaltenes and TAN should be
rechecked.
[0028] The fourth step in this exemplary embodiment is an
optimization step and depends on one's ultimate goal. For instance,
one process goal may be to completely remove soap or ultimate
resulting naphthenic acids or asphaltenes. In that scenario,
evaluating the level of total metals or % asphaltenes after solvent
rinse will indicate how much of the metal soaps or asphaltenes were
not picked up and extracted in first rinse. Generally, a sodium,
potassium, or calcium number would be in the 100 to 300 ppm range.
If the optimization goal is to completely remove soap or additional
removal of soap and asphaltenes, then one or more additional
solvent rinses may be required. The pH of oil will be high, but
most likely not high enough for the soap to be in the range that
the soap will cause an emulsion.
[0029] According to an embodiment, to remove soap entirely, an
additional solvent rinse comprises dosing the solvent with a small
amount of caustic, enough to merely to bring the solvent pH above
11 so as to prevent the soap from forming a lather. Then, the
procedure for contacting and settling of the solvent is repeated.
The first pass results in the majority of both soaps as well as
asphaltenes being extracted, however, every subsequent pass will
result in a smaller level extracted until both quantities become
trace levels.
[0030] In an alternative embodiment, where the optimization goal is
to extract the metals from the solvent after the liquid-liquid
extraction reaction with the hydrocarbon, a solvent wash with acid
will be required in a solvent recovery unit, remote from the bulk
tankage unit. After the liquid-liquid extraction occurs, the
solvent (which now contains the undesirable materials, such as
naphthenates and asphaltenes) is decanted and pumped out of the
bulk tankage to a solvent recovery unit. There, the solvent is acid
washed or acidized with strong acid. Exemplary strong acids that
may be used include HCl or H.sub.2SO.sub.4. The acids break down
the soaps, convert the metal soaps back to a naphthenic acid, and
form metal salts that are solvent soluble.
[0031] The addition of acid can improve treatment. For example,
recovered solvent can be injected with acid on its way to one or
more settling tanks. The acid will immediately begin to convert the
naphthenate soaps back into naphthenic acid as well as force the
asphaltenes that were solubilized in the high pH solvent out of
solution, which both will rise to the top of the processing tank no
longer soluble with the solvent. It can take time to separate and
fully convert naphthenate soap into naphthenic acid (at least 5
hours up to as many as 24 hours). For increased speed and
efficiency, certain embodiments comprise multiple settling tanks
and sheering mixers for closer contact between strong acids and
soaps for reaction. The naphthalenes and phenols (PAHs) tend to
remain in the solvent as opposed to migrating back with the
naphthenic acids and asphaltenes, as they are readily soluble in
alcohol, in particular ethanol. The reverse osmosis then captures
them for recovery for value or BTU recovery at the thermal
desorption units and removes them from the solvent bound for re-use
within the process.
[0032] The acid-washed solvent then may be "recycled" through a
bank of solvent treatment skids. Such skids may be advanced
oxidation skids that, with an electrical charge and specialized
catalyst plates, can convert the metal soaps back to naphthenic
acid. Such converted naphthenic acid can be skimmed off, and any
metal salts created can be precipitated out. This allows for the
solvent recipe to be reused and recycled continuously. In other
embodiments, solvent recycle may be treated using reverse osmosis
skids comprising carbon filters or organic membranes to catch any
crude or converted naphthenic acid that may have carried over.
Reverse osmosis skids are effective for removing salts and
chlorides and repairing solvents for reuse.
[0033] In certain embodiments, reverse osmosis ("R/O") equipment is
used in lieu of oxidation skids. R/O skids "cycle up" the
concentration of extracted constituents (e.g., metals, naphthalene,
phenols, sulfur salts, and chlorides) in the solvent mixture. The
cycled-up material can be sent directly to a cement kiln for
recycling of the metals into cement (e.g., Portland cement). The
alcohol and glycerin components of the solvent mixture, along with
the naphthalenes and phenols, have BTU value. In addition, alcohol
and glycerin are renewable fuels subject to monetary rebates when
consumed for energy, as well as emissions tradeable credits.
Thermal desorption burns will create energy and heat to
self-sustain the nominal heat required to provide for the tankage
heating options discussed herein.
[0034] According to certain embodiments, the extraction process
utilizes an advanced oxidation water treatment facility, which,
through oxidation via catalyst plates, is able to produce a water
of potable quality or clean solvent. For example, sodium
naphthenate that is extracted from the crude from exposing NaOH or
KOH to the naphthenic acid is oxidized. That removes the Na, Ca, or
other compound(s) that can convert the naphthenates back to the
various molar weights of naphthenic acids. This enables continuous
recycling for re-use in the liquid-liquid extraction. The advanced
oxidation flocculates the material being extracted and recovers
them as a saleable product or a concentrated material for safe
disposal at an appropriate facility. The advanced oxidation also
flocculates out the sulfur that is also extracted. The sulfur that
is segregated can be sold into the raw sulfur industry where there
is a wide variety of industrial uses. In other embodiments, this
extraction process may, in addition to or in combination with the
advanced oxidation equipment, utilize reverse osmosis skids, as
mentioned above.
[0035] An acid step or acid wash may also be implemented in the oil
reaction stage in the bulk tankage. Such embodiments comprise
slowly adding acid to the solvent in an amount about or equal to
(in ppm) the amount of metals remaining in the oil along with any
level of basic nitrogen, followed by circulating the acidized
solvent and hydrocarbon for about 12 to 24 hours. The acidized
solvent converts metal soaps to metal salts, and the metals in the
crude will have reduced, or trace, or nominal levels in the crude
once solvent drops out. The basic nitrogen level of the crude will
also drop as a result. A final polishing rinse with solvent might
be necessary with no chemistry (e.g., without further dosing
caustic or acid) to rinse any strong acids remaining in the oil.
The level of strong acids in the crude can be monitored various
ways: e.g., by measuring TAN and calculating strong acid levels, or
if utilizing HCl as the strong acid, measuring total chloride
level.
[0036] The systems and methods described herein may also be
incorporated at upstream stages of hydrocarbon processing. The
embodiments of the present invention described herein may be
implemented during hydrocarbon transport (e.g., on a ship or
vessel). In transit, circulation loop systems attached to or
incorporated with the hydrocarbon bulk tankage can allow for
initial contacting of solvent mixture and hydrocarbon, even before
the hydrocarbon arrives at its destination (e.g., refinery). In
this context, if the circulation loop systems are turned off or
disconnected, the solvent mixture will drop out from the bulk
tankage, allowing it to be removed and directed to solvent
extraction tanks on site. The hydrocarbon in the bulk tankage will
thus be "pre-treated" (e.g., naphthenic acid removed, asphaltenes
removed, and water soluble salts or metals removed) all before
being directed for further processing on site (e.g., at the
refinery). Upstream stages where the embodiments of the present
invention may be implemented include all types of transport (e.g.,
ship/barge or rail).
[0037] Furthermore, at the point of crude production or wellheads,
specifically regional crudes that tend to consistently have same
issues, this process can be applied at production to lessen the
transport issues that ensue or mitigate the need at the refining
location. For example, the embodiments described herein may be
advantageous in "pre-treating" crudes that tend to run with high
TAN, asphaltene, metals and nitrogen, such as North Sea naphthenic
crudes and Canadian bitumen crude. The described extraction
processes could be inserted in lieu of portions of the hot water
washing methodology currently utilized for recovering bitumen from
the oil sands. This could enable Canadian operations to recover the
asphaltenes, naphthenic acids and PAHs at the origin of production
for future commercial use, while sending the saturates, aromatics,
and resins blended with condensate through various transportation
methods onward to larger integrated refiners for further
manufacturing.
[0038] Further, the processes described herein as opposed to just
hot water are more effective in stripping the bitumen oil from the
sands because of, among other things, the combination of alcohol
and water possessing more stripping power. In addition, utilizing
water alone leaves some residue of PAHs and naphthenic acids in the
waters collected in tailing ponds. The inventive embodiments
described herein provide a more complete removal of PAHs and
naphthenic acids.
[0039] In certain embodiments, an additional feature is to distill
the repaired solvent once it exits the reverse osmosis units.
Bitumen crude contains large quantities of water that would
increase ratio of water to alcohol to glycerol ratio. Recovery of
alcohol and water as separate fractions allows for the recovery of
alcohol and some level of water while outfalling unwanted yet clean
water in order to maintain the correct ratios for solvent
effectiveness.
[0040] Naphthenic acids have multiple uses in the industry, ranging
from fuel additives to corrosion inhibitors to main ingredients for
paint dryers and lumber treatment. The heavier molar weight
naphthenic acids are highly sought after because they are difficult
to extract from hydrocarbon. Embodiments of the present invention
allow for extraction of naphthenic acids from crudes and heavy
fuels, ranging in molar weight from very heavy to light. The
various weight naphthenic acid may be sold to a naphthenic acid
refiner who has the capabilities to further refine the acid into
specific molar weight acid. In addition, as the naphthenic acids
and asphaltenes are extracted together and must be gently distilled
to separate, an on-site distillation facility for the separation of
the majority of asphaltenes from lighter naphthenic acids can be
installed or the entire mixture sent onward to consolidation
facilities designed to separate the asphaltenes from acids and
further upgrade both the naphthenic acids as well as the
asphaltenes for commercial use.
[0041] Liquid-liquid extraction embodiments described herein are
performed in bulk tankage in batch operation, with minimal amounts
of equipment, and a relatively green carbon footprint. These
embodiments can also be implemented in terminals for crude blends
being shipped to refiners or on bunker or fuel oil blend-stocks
being delivered from refiners. Using the embodiments described
herein on the back end of the refinery on heavier cuts allows
refiners to meet the new sulfur specifications without requiring
them to develop, invest, and build new hydrotreater technology
specific for heavy fuel. This also allows for heavy crudes to be
treated in terminals and directed directly to market, bypassing
refineries.
[0042] In practice, process engineers have typically separated and
treated crude hydrocarbon by running (or moving) the hydrocarbon
through refinery processing units (e.g., distillation columns,
separators etc.). The embodiments described herein provide for
separation and treatment without moving the crude hydrocarbon;
rather, the separation and treatment can be performed on stationary
hydrocarbon in tankage. As a result, upstream hydrocarbon owners
and producers, who may not operate a refinery, have the capability
and flexibility to upgrade the value of the hydrocarbon they have
purchased by addressing numerous problems at once, such as removing
naphthenic acid, metals, and asphaltenes.
[0043] The advantages of bulk tank liquid-liquid extraction
embodiments described herein are multiple. For example, the process
can be performed outside of a refinery in a terminal; it can permit
treatment of greater volumes of crude hydrocarbon; and it allows
for flexibility on treatment options (e.g., typical process units
are limited by location and lineup of the units). Naphthenic acids,
moreover, are detrimental to generic refinery processing units, so
it is beneficial to remove naphthenic acids before the crude
hydrocarbon enters the refinery. Additionally, the embodiments of
the present invention can also more efficiently de-salt and
minimize corrosion.
BRIEF DESCRIPTION OF THE DRAWINGS
[0044] FIG. 1 is a schematic diagram of an exemplary system for
performing the liquid-liquid extraction in bulk tankage methods
described herein.
DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS
[0045] Embodiments of the system that performs the liquid-liquid
extraction comprise numerous pieces of equipment. Certain pieces of
equipment, components, and features of these embodiments are
described in more detail below.
[0046] According to certain embodiments, and in general reference
to FIG. 1, the system 100 comprises a main bulk processing tank 10
(also referred to herein as bulk storage tank, storage tankage,
bulk tank, liquid-liquid extraction unit, or the like) where the
liquid-liquid extraction occurs. The size of the tank can range
from 1,000 barrels (bbls) up to and including 1,000,000 bbls.
Typically, the liquid-liquid extraction of the present invention is
performed as a batch process, where the hydrocarbon does not move
once it arrives in the bulk storage tank (e.g., from a raw/crude
hydrocarbon stream 30), until the completion of the process.
Liquid-liquid extraction processes described herein can be
performed in any size storage tank that is feasible to be
built.
[0047] According to certain embodiments the storage/processing tank
10 has the following features. The processing tank 10 may or may
not comprise a top enclosure, such as a floating roof, depending on
the type of processing performed in the unit. Generally, the
processing tank 10 will not comprise a floating roof, either
internal or external, if the solvent mixture is introduced via
misting process. This is to allow for a head space and room for
processing equipment associated with a misting system. However, if
the solvent mixture is introduced via circulation loop, then the
processing tank may comprise a top enclosure, such as a floating
roof.
[0048] In certain embodiments, an electrical current source is
incorporated or attached to the floating roof of the processing
tank. The electrical current source may be arranged as a caged grid
of electrical probes. Such grid system covers the entire under
portion of the floating tank. A probe system is equally distributed
and connected to the floating roof, and the volume or number of
probes in the system are dependent upon their voltage and amperage
distribution. In practical terms, the electrical current source for
the floating roof generally is akin to electrical current sources
used an incorporated in desalter units. Desalter units use
electrical current sources to drive out brine water quickly from
incoming crude. The electrical current source heightens the
polarity of the salt laden water and increases the speed of
separation. Similarly in the present system, the electrical current
source incorporated into the floating roof can be used to
accentuate, accelerate, and make separation more efficient.
[0049] By way of example here, once the solvent mixture has begun
to be pumped off (after introduction to the hydrocarbon and a few
hours hold time), the electrical grid system located at the top of
the tank can be placed on a "pulse" system to expedite the
separation of the solvent from the hydrocarbon. The electric
pulsing will also encourage the extraction of slightly polar
constituents from the hydrocarbon. It promotes a cleaner break
between hydrocarbon and solvent, while maximizing the extraction of
problematic polar constituents.
[0050] The processing tank 10 may further comprise a heating
system. The heating system may be installed in the bottom of the
tank or vertically along one or more sidewalls of the tank, or a
combination of both. The heating system comprises either a hot oil
or steam coil system in order to allow the tank to be heated to
temperatures of at least 100.degree. F. up to and including
200.degree. F. (advantageously, the system will heat to a
temperature ranging from 130.degree. F. up to and including
160.degree. F., or 140.degree. F. up to and including 150.degree.
F.), if desired for adjusting hydrocarbon viscosity and increasing
contact efficiency between the hydrocarbon and additive streams
(e.g., solvent mixture). The storage tank may comprise a
circulation loop, and heat may also be applied via heat exchangers
on the circulation loop.
[0051] The processing tank 10 may further comprise relief valve
systems. The relief valve systems may comprise a system configured
to route light end vapors and nitrogen to a light ends recovery
tank or straight to thermal desorption unit for BTU recovery. Such
relief valve systems may also incorporate or work in conjunction
with vapor recovery systems, which are configured to recondense
light end vapors. The inclusion of such system allows for
flexibility of taking in low flash hydrocarbons and adding nominal
amounts of heat without the loss of the hydrocarbon. This vapor
recovery system and thermal desorption safely routes any H.sub.2S
or mercaptans that reform in the acid phase for reaction into
productive products or to the thermal desorption to be utilized for
BTU recovery.
[0052] The bottom of the processing tank may further comprise a gas
sparging system (e.g., for nitrogen/air) in order to "nitrogen
strip" light ends to the recovery tank, if required. Including this
feature allows for flexibility if electing to intake low-flash
hydrocarbons. The gas sparging system may also be configured to
inject steam into the processing tank.
[0053] The inside of the processing tank 10 may comprise a
corrosion control coating throughout to minimize corrosion due to
extreme pH swings. If the temperature within the tank is kept below
150.degree. F., then both caustic and acid corrosion is only
nominally invasive to carbon steel. However, certain processing
techniques described herein may require higher temperatures, which
could increase the possibility for corroding the inside walls of
the tank. Using a corrosion control coating could mitigate this
concern.
[0054] In certain embodiments, the floor and footings of the
processing tank 10 are installed and configured to be at a slight
angle leading to a deep sump in order to facilitate gathering of
the liquid being used for extraction with ease--without pumps also
sucking oil. In other embodiments, a flat floored tank with a small
sump can be utilized.
[0055] The processing tank 10 may further comprise a high draw for
pumping off finished product to a product tank. Finished product
may alternatively be pumped from sump or low draw. A high draw is
advantageous because it can avoid pumping off any small layer of
emulsion at the interface of oil/liquid being used for
extraction.
[0056] The processing tank 10 may further comprise a weir installed
at the sump. The weir can minimize hydrocarbon vortexing with the
solvent when the final quantities of solvent are being pumped
off.
[0057] According to certain embodiments, the system comprises a
misting system connected to or integrated in or with the storage
tank 10. The misting system is configured to evenly distribute the
liquid being utilized for extraction (e.g., caustic-dosed solvent
mixture) in an even layer across and upon the total surface area of
the hydrocarbon at the top of the tank. A misting system may be
incorporated or installed according to various options, described
as follows.
[0058] In certain embodiments, the misting system may comprise
numerous misters (or mister heads) that produce a droplet size of
15 to 50 microns. The misters are attached to piping emanating from
the floor of the tank 10. The piping system is evenly distributed
throughout the tank. The pipes lead from a feed system installed in
the foundation of the tank, leading to individual pipes that
measure in length so as to extend higher than the highest safe fill
of the tank in the additional head space allowed. Each pipe ends at
a header system, at which the plurality of misters are installed.
The misters are configured and positioned to point upwards, away
from the hydrocarbon contained in the storage tank. In this manner,
when misting occurs, it creates a fog that will evenly lay down
over the entire surface area of the hydrocarbon. The pipes may be
braced at the floor and footings can be engineered to support the
additional weight of the piping and liquid being pumped.
[0059] In certain embodiments, the misting system is installed in
the head space of the storage tank 10 and braced at the roof with
an additional truss system to support the weight (the roof itself
would not likely be able to support the weight of the misting
system itself). According to this configuration, the misters are
configured and positioned to point downward toward the hydrocarbon.
The misters are further configured to spray in a pattern that
completely covers the surface area of the hydrocarbon. The misters
would still produce droplets having size within the range of 15 up
to and including 50 micron. In embodiments in which a misting
system is installed in the head space of the processing tank, the
tank may comprise an infrared foam indicator in head space as well,
like those that may be used in coke drums. Regardless of the
misting system's configuration, it may comprise a heat exchange
feature configured to heat the liquid solvent mixture being
introduced to the hydrocarbon. As explained in more detail below,
solvent mixture may be pumped from a separate storage unit, and the
heat exchange feature can heat the solvent as it travels from the
separate storage unit to the misting system. A heated solvent
mixture can speed up the reaction with the hydrocarbon.
[0060] In certain embodiments, a sprinkling system substitutes for
the misting system. The sprinkling system is installed at the roof
with a truss system. With a sprinkling system, however, the micron
size of the liquid droplets would be larger than with a misting
system. As a result, distribution and surface area contact of
solvent mixture onto hydrocarbon may not be as effective with the
sprinkler system, as compared to the mister system.
[0061] As mentioned previously, in certain embodiments, the system
comprises a circulation loop for distribution and delivery of the
solvent/caustic mixture. When electing to use a solvent mixture
circulation loop, mix valves and a vortexing nozzle sparging system
are advantageously used in combination. The circulation loop may be
constructed, installed, and incorporated as a permanent feature or
it can be included as a temporary loop. The temporary loop allows
for the injection of solvent ahead of the pump (e.g., from solvent
tank 20). Pump impellers may be incorporated in the tank to act as
a blender. Impellers may be tied back into a sparging system within
the bottom of the tank 10. For a faster, more efficient blending
and contacting of the solvent mixture with the hydrocarbon, the
system may comprise numerous circulation loops around the diameter
of the tank. Incorporating a plurality of circulation loops can
maximize exposure between solvent and hydrocarbon.
[0062] Each circulation loop may further comprise additional
features and components. For example, as mentioned above, a
circulation loop may comprise a heat exchanger, which is configured
to heat the hydrocarbon before solvent is injected. Heating the
hydrocarbon lowers its viscosity, which helps to increase contact
between solvent and hydrocarbon.
[0063] Each circulation loop may comprise mix valves. The mix
valves are configured to mix solvent mixture and hydrocarbon during
transport through the circulation loop. Mix valves may be located
at one or more locations along the path of a particular circulation
loop. The processing tank may further comprise a vortexing
nozzle/sparging system that allows for the hydrocarbon to further
blend and contact with the hydrocarbon residing in the tank.
[0064] In certain embodiments, draws leading to the circulation
loop are located high on the tank (e.g., above the midpoint of the
tank or at a location in the upper half of the tank). Such
configuration allows for a more complete exposure of the
hydrocarbon to the solvent mixture within the tank, which could
mitigate or eliminate the need for the vortexing nozzle/sparging
system. Notwithstanding, certain embodiments feature high draws to
the circulation loop coupled with a vortexing nozzle/sparging
system. If locating high draws well above the internal floating
roof legs, check valves should be installed directly next to the
tank in order to minimize back flow of oil into the tank when
volume of the tank has been dropped.
[0065] The processing tank 10 may further comprise a piping system
for drawing water and/or solvent mixture from the tank, not only at
the sump. Such piping system may comprise repeated draws,
equidistant from one another (e.g., every 6 inches or every foot),
in order to draw water from the top of the tank, when the tank is
in fuel oil treatment service and solvent is drawn from the
top.
[0066] As mentioned previously, the processing tank 10 may comprise
a sparging system at the bottom of the tank with vortexing nozzles.
Such sparging system provides additional blending of
solvent/hydrocarbon into hydrocarbon within the tank. The sparging
system may also be utilized to blend the solvent mixture and/or to
allow for blending of a steam/solvent mixture.
[0067] The processing tank 10 may further comprise a nitrogen purge
system for the head space of tank 10. A nitrogen purge system is
generally for safety purposes if a misting system is included. In
certain embodiments, nitrogen is injected into the head space of
the tank to keep the vapor space inert. Accordingly, the nitrogen
purge system is a safety feature to clear the head space of gas, if
necessary.
[0068] According to certain embodiments, the system 100 comprises a
solvent bulk storage tank 20 dedicated for storage of clean liquid
solvent meant for the liquid-liquid extraction process. The liquid
solvent may comprise water, amines, organic solvents (e.g., acetone
or any type of alcohol such as ethanol or isopropyl alcohol), or
combinations thereof, designed to facilitate liquid-liquid
extraction. As used herein, the terms solvent and solvent mixture
refer to the liquid injected or introduced into the bulk storage
tank, which reacts with the hydrocarbon to extract acids and other
undesirable materials from the hydrocarbon. In certain embodiments
the solvent may consist of water only; in other embodiments the
solvent mixture may comprise multiple materials, including a
plurality of water, amines, organic solvents, and/or glycerin. The
solvent bulk storage tank 20 can vary in size depending on the
volume of solvent mixture needed to process the hydrocarbon in the
processing tank. The solvent storage tank 20 can have an optional
floating roof if the solvent mixture being used requires vapor
control.
[0069] The system 100 may further comprise separate storage tanking
and injection systems, as necessary, to account for other liquid
components that may be required for the liquid-liquid extraction.
For example, water, caustic, acid, and/or peroxides may be useful
liquid components for the extraction techniques described here. The
system, therefore, may comprise a plurality of storage tanks, one
each for these other liquid components. The system also comprises
injection systems corresponding to these liquid components and
integrated and incorporated with the plurality of other storage
tanks. The injection systems are configured to inject liquid
components necessary for liquid-liquid extraction into either the
processing tank directly, the solvent feed line, a misting system
feed line, or a circulation loop.
[0070] In certain embodiments, the system 100 comprises a light
ends recovery tank. In case the process has initial light ends
(e.g., naphtha), vaporized light ends and nitrogen are collected at
the top of the processing tank 100. The light ends vapor is
recondensed by a vapor recovery system and then pumped back into
the bottom of the tank. The light ends recovery tank comprises a
constant water table in order to solubilize any solvent that may
vaporize and keep it separate from the light ends vapor. The light
ends recovery tank also has a relief valve in order to relieve the
excess nitrogen to the flare system. Condensing light ends vapor
can also take place in an exchanger, in the alternative.
[0071] H.sub.2S and mercaptans in the caustic phase of treatment
are bound as a salt. However, in the acid phase of the process,
they are re-released as a gas both on the raw crude and any salts
that were not fully extracted along with the extracted material. In
certain embodiments, the vapor recovery system is routed through a
thermal desorption unit for initial heat and energy recovery. The
thermal desorption units have scrubbers that minimize ultimate
emissions.
[0072] The addition of acid to a basic environment is exothermic
and springs H.sub.2S and mercaptan gases. Certain embodiments may
be capable of self-heating through this exothermic reaction. In
such embodiments, acid is added slowly to allow for a slow reaction
and to control the exothermic reaction and to control the
production of H.sub.2S and mercaptan gases. Correspondingly,
nitrogen used in the sparging system creates a small amount of
positive pressure on the tank to continually purge the gases from
the tank into the vapor recovery system for incineration and energy
recovery. The thermal desorption system may be lined up with and
connected to the spent solvent system for continuous feed.
Regulation mechanisms can adjust the feed flow depending upon the
heat needs for the system, as it varies due to batch operation.
[0073] The vapor recovery system may also be connected and
integrated with the spent solvent system. The spent solvent tank
can have a line up for introduction of spent glycol, spent caustic,
and spent amines which all have some level of BTU value. According
to the processes described herein, water is picked up from the
crude. Any additional materials such as amines, glycols, or spent
caustic will also have additional water. The thermal desorption
unit can create steam from this water content. Such steam may be
routed to heat exchangers in the bulk tankage heating system in
order to recover heat. Once condensed, it can be sent to a
wastewater treatment plant as relatively clean water for outfall or
to a make-up water system for recirculation into a cooling water
system or into the solvent mixture. The thermal desorption unit
allows for the system to be relatively self-sustaining on energy
consumption. Being a renewable system that promotes a high level of
water recycling and conservation is an unassailable advantage of
the present invention.
[0074] In certain embodiments, the system 100 comprises recovery
and recycling subsystems. Liquid-liquid extraction processes
described herein may produce spent water. A recovery and recycling
subsystem may comprise water treatment facilities. For example,
water treatment facilities may utilize advanced oxidation units
and/or reverse osmosis skids to extract the majority of solubilized
metals, salts, sulfurs etc. in the spent water. Although not a
critical requirement, without a water recycling subsystem, the
amount of water that would be consumed and that would need to be
disposed would be significant and create economic inefficiencies.
Other recovery systems for solvents, amines, and other liquid
components used in the liquid-liquid extraction may be incorporated
as well.
[0075] The components and features described above can be used to
perform liquid-liquid extraction in bulk tankage, regardless of the
size of the tank. FIG. 1 illustrates an exemplary embodiment of the
system designed to perform the liquid-liquid extraction methods
described herein.
[0076] According to an embodiment of the present invention, to
extract naphthenic acid in bulk tankage, naphthenic acid is reacted
with NaOH (caustic) or KOH. This reaction converts the various
molar weight naphthenic acid to sodium or potassium naphthenate
(soap). The reaction also creates an emulsion in crudes or heavy
fuels that, until now, was considered impossible to remove or break
in any type of traditional processing unit. Any type of severe
blending, such as the oil passing through a pump impeller, would
further increase the severity of the emulsion in the presence of
water alone.
[0077] Naphthenic acid can be completely converted to naphthenate
with various strength caustic--e.g., full strength, 50% neat, or
caustic dosed within a solvent mixture. Caustic can be dosed with
solvent mixture on the run down from the vessel (e.g., raw/crude
stream 30) to the storage tank 10 with mix valves in line to ensure
contact. Dosage will vary depending upon the incoming TAN. Lab
titration may be used to specifically define the required dosage,
but generally, a point of TAN will require 1 mg KOH/kg solvent
mixture, approximately 0.1% full strength caustic, to reduce the
TAN to non-detect. In certain embodiments, a sparging system
installed with a circulation loop can allow for the introduction of
additional caustic and blending, if the rundown dosage is not
sufficient. When using a solvent that is heavily laden with
naphthenates and asphaltenes, the solvent will have a very dark
color, almost indiscernible from the color of the oil, except for a
prevalent amber tint. As the rinse progresses and the quantity of
naphthenates and asphaltenes being extracted are reduced, the color
of the solvent will move to an amber color.
[0078] Once the TAN is brought to a non-detect or acceptable level,
it is in the form of naphthenate soap, which will, if exposed to
water alone, create a severe emulsion. Because soap is miscible in
both oil and water, any type of agitation will make the emulsion
very difficult to break. However, water and soap can be displaced
or a solvent mixture can minimize the emulsion and allow the
naphthenates to easily migrate to the solvent mixture and extract
from the oil. A solvent mixture of water and alcohols can minimize
the emulsion and encourage the naphthenates to migrate to the
solvent from the oil, along with promoting asphaltenes to
solubilize instead of remaining at the oil/water interface.
[0079] Water and/or solvent mixture will continuously displace in
the bottom of the tank. According to certain embodiments, the water
and solvent mixture is pumped off to a storage tank for naphthenic
acid and asphaltene recovery. After naphthenic acid and asphaltenes
are recovered, the solvent proceeds to reverse osmosis water
treatment skids. The reaction between caustic and crude or acid and
crude generally occurs at ambient temperature; however, in certain
embodiments, tanks may be heated with steam coils or hot oil. Steam
coils or hot oil may be located vertically along the tank walls or
at the bottom of the tank. The steam coils or hot oil heat to a
temperature ranging from about 100.degree. F. up to and including
180.degree. F. The heating temperature depends on solvent
temperature tolerance. It has been observed that this type of
heating facilitates the contacting of liquids and a faster
displacement due to improved viscosity of the oil.
[0080] In certain embodiments, a misting system is installed in the
top of a bulk storage tank. It can be installed through a
"sprinkler type system" comprising misters. A plurality of misters
may be installed throughout the top of the tank, directed downward
toward the hydrocarbon contained in the tank. The misters are
configured to create fine droplets of water, for example, as small
as 5 to 15 microns. The misting system may be installed as part of
a "truss system" on the outside of the tank, in order to support
the weight of the system.
[0081] Certain embodiments of the liquid-liquid extraction system
comprise pipes that emanate from the floor and spread vertically
and evenly throughout the tank. Misting heads are connected to
terminal ends of the piping and are configured to point upward, or
directionally away from the hydrocarbon stored in the tank. The
water/caustic mixture may be pumped upward through the pipes and
ultimately sprayed out into the tank via the misting heads. In this
configuration, the positioning of the misting heads upward enables
the water/caustic mixture to be sprayed or misted into an upper
portion of the tank, creating a fog-like header that then lays down
over the complete surface area of the tank. In certain embodiments,
the tank will not be enclosed by a floating roof or top-side lid.
This helps to ensure that the upward spray from the misting heads
is not impeded and thus the water/caustic mist can lay down evenly.
When the misters are pointed downward, they can have a distinct
spray patterns that might or might not overlap as the hydrocarbon
level in the tank rises and falls. This can lead to uneven
coverage.
[0082] When misting from the top to the bottom with a solvent
mixture, various solvent mixtures are effective. The addition of
glycerol alcohol, for example, is useful to decrease the gravity
enough to allow the solvent to drop through the hydrocarbon and
draw from the bottom of the tank, while extracting the
naphthenates. Mixtures of water, glycerol, and ethanol, isopropyl
alcohol ("IPA"), methanol, acetone, or other polar water soluble
solvents are effective. Water and glycerol alone, without the
addition of an additional alcohol, will also be effective.
[0083] The fresh water/solvent rinse can mist for as little as 12
hours or up to 120 hours (5 days), depending upon the initial level
of TAN. Generally, the higher the initial TAN, the longer the rinse
will need to go. In some embodiments, the misters may be set to
allow for 10% to 20% of the total capacity of hydrocarbon misted
over the applicable application period.
[0084] In certain embodiments, a misting system is not present. In
such embodiments, the inclusion of a circulation (or sparging)
system may be useful. With a circulation system, the solvent is
pre-dosed with caustic or acid and introduced before a mixing valve
to allow for excellent contact of the solvent and caustic or acid
with the oil. The solvent dosed with caustic can initially be
introduced to the crude on the run-down from the provider (e.g., a
ship or barge) to the tank, or the caustic or acid can be
introduced via the circulation loop at the tank. The appropriate
dosage of caustic or acid and appropriate amount (percentage) of
solvent that should be used is dependent upon final specification
requirements. A solvent mixture can be highly effective in picking
up the majority of naphthenates and asphaltenes in a single rinse.
If initial TAN or asphaltene is particularly high, then it can be
advisable to increase the percentage of solvent as the solvent can
have a saturation point and/or adjust dosage of caustic (e.g.,
elect to reduce caustic dosage by 25% up to and including 75%).
[0085] In dealing with fuel oil, where the gravity is less than 10,
the caustic may be injected into a steam header/sparging system
installed on the floor of the tank. According to such embodiments,
the caustic is dispersed throughout the steam and distributed
throughout the tank. The steam condenses back to solvent mixture
and displaces itself along with the soap at the top of the tank,
where it is drawn off through a series of high draws. In this
instance, distillation would need to occur in order to remove
portions of the water in order to keep solvent/water ratio in
balance.
[0086] According to certain embodiments, an initial
strip/extraction with solvent, if dosed with caustic at full
strength in order to account for all of the naphthenic acid, may be
sufficient to remove the majority of naphthenates. However, it is
possible that even still there could be a small percentage of
naphthenates or asphaltenes left behind. A second or third wash
will continue to remove the remnants of naphthenates and
asphaltenes. The pH of the oil after the initial strip will have
been reduced. It is useful to continue to dose solvent with caustic
to at least extent to keep the pH of the solvent above about 11.
And, of course, on secondary or tertiary strip cycles, the dosage
will be reduced stepwise because some of the naphthenic acid has
already been converted into naphthenate form from prior stripping
cycle(s).
[0087] Once the desired quantity of naphthenates and asphaltenes is
removed, the same solvent can then be used to revert the remaining
quantity of naphthenates back to naphthenic acid. For example,
according to certain embodiments, the same solvent on a circulation
loop can be dosed with an acid (strong or weak acids will work).
The acid can be injected along with the water or solvent in the
misting system or at full strength through the sparging system and
circulation loop. The naphthenates will revert back to a naphthenic
acid, and any remaining metals will create metal salts that are
washed out with the solvents. In the acid phase, no further
asphaltenes will be extracted. In the acid phase, there will be a
reduction of basic nitrogen as well.
[0088] Again, at this stage of the process, there should only be
small quantities of naphthenates present; therefore, the dosage of
acid required to revert the naphthenates back into naphthenic acid
will be minimal For this reversion step, it is useful to dose the
solvent mixture to a pH of around 4. As the naphthenates are
converted back, the pH of the solvent dropping out will rise. The
dosed solvent should continue to circulate until the pH stabilizes.
The basic nitrogen number should be monitored as well because it
also consumes acid for neutralization. The conversion back to a
naphthenic acid is not instantaneous. Once the conversion reaction
is completed, any excess sodium, potassium, or calcium will have
formed a water-soluble salt and will migrate to the solvent phase
and drop out with the solvent. Once the soap is converted back, the
stable emulsion will no longer be present. The previously
emulsified water and solvent will now quickly break out along with
the sodium and chlorides. The oil now will have a new lower TAN and
lower % asphaltene, while being water, sodium, and chloride free. A
final solvent wash with no chemistry may be required to remove
residual levels of strong acid.
[0089] There are a number of ways to determine how much of the
naphthenates has been removed. One way is by observing the actual
recovery of naphthenates on recovery skids or in a lab, which
involves washing the hydrocarbon with solvent and then adding acid
to a known amount of solvent and observing the naphthenic acid
produced.
[0090] In certain situations, the only desired result for crude
extraction is to reduce the overall level of naphthenic acid in
order to create "low TAN" crude or bunker fuel. In such situations,
a single solvent wash may be sufficient. If a secondary desire is
sulfur removal, then it is recommended to remove as many
naphthenates as possible because the presence of acids (i.e.,
naphthenic acid) can minimize the effectiveness of sulfur removal
processing steps. Therefore, if sulfur removal is desired, in
addition to producing low-TAN crude, then follow-on solvent washes
may be required.
[0091] During extraction, it is useful to continuously observe pH.
If the pH begins to drive below about 11, an emulsion can develop
due to saponification. If the pH drives lower, the soap may begin
to lather. To counteract this, it can be useful to add strong base
with the solvent mixture--that will minimize lathering and increase
efficiency of the extraction.
[0092] For crudes that are holding excess water or for crudes known
to have desalting difficulties, a solvent mixture wash with
slightly acidic water/solvent can often help to "pre-wash" metals
and salts stabilized in the crude that can cause desalting
difficulties. For any crude, it is helpful to always check a full
slate of metals and TAN level. Incoming crude with excessive levels
of sodium, calcium, iron, magnesium, copper, or other metals will
most likely be holding an excessive amount of naphthenate soap that
developed naturally in the earth's structure. The presence of
excessive metals is typically an indicator of naphthenate soap and
typically does not reflect in the TAN, but will generally lead to
recovery of additional naphthenic acid. A high metal number is an
indicator the crude will have major desalting issues.
Solvent Mixtures
[0093] The solvent mixtures referred to above and used in the
embodiments of the extraction processes described herein may
comprise water in combination with various alcohols. In bulk
tankage and the premise of circulation and contact, ultimately, the
solvent mixture must be able to drop to the bottom of the tank.
Most alcohols have an API or specific gravity that would not allow
for it to drop to the bottom. Thus, embodiments of the present
invention use glycerol, which has a low API and is water
soluble/miscible in water. The inclusion of glycerol not only will
aid in extracting soap, it will also give the solvent mixture a low
enough gravity to drop out of even heavy fuel oil mixtures.
[0094] In certain embodiments, the solvent mixture may also
comprise one or more of ethanol, acetone, IPA, or methanol, in
addition to the water/glycerol mixture. The addition of these
alcohols can increase effectiveness of the solvent when extracting
the soaps. The solvent mixtures must comprise water in an amount
significant enough to cause alcohols to want to remain with the
water phase, as opposed to solubilizing into the hydrocarbon.
Useful solvent mixtures comprise water in an amount of at least 30%
by weight.
[0095] For embodiments introducing a solvent mixture by misting,
the system should continue to mist at 10 to 20% of the total volume
of the oil volume per day until the presence of naphthenic acid is
negligible in the recovery skids. The solvent needs to continuously
have caustic present in order to minimize or eliminate the
saponification effect. The caustic can be dosed either neat into
the oil initially on the run down to the storage tank, neat on a
circulation loop, or dosed within the actual solvent mixture.
[0096] For embodiments that batch treat crude with the solvent
mixture or that introduce the solvent mixture on a circulation
loop, the system should provide the solvent mixture in an amount of
10% to 40% of the volume of oil. Increasing the volume of solvent
increases contact ability, increases efficiency of break between
oil and solvent, and decreases the percentage of naphthenates
absorbed. In these embodiments, for the initial solvent wash,
caustic is dosed at a level sufficient to account for the
conversion of the desired amount of naphthenic acids to soap. On
subsequent washes, the solvent needs to have enough caustic added
in order to bring the pH up to above 11 in order to minimize the
lathering effect of soap. The initial solvent mixture can either be
added into the oil on the rundown to the storage tank or via the
circulation loop.
Heating
[0097] The reaction of naphthenic acid with caustic is relatively
instant and requires no heat. The solvent absorbing the soap also
occurs at ambient temperatures. The addition of nominal levels of
heat, however, can be useful. For example, heating the oil affects
its viscosity, which can allow for better contact with the solvent
and the break of the solvent from the hydrocarbon. Heating the
solvent can help with washing efficiency. A nominal level of heat
(e.g., about 100.degree. F. up to and including 150.degree. F.) can
minimize solvent wash time. It is important, however, to be mindful
of the actual boiling point of the hydrocarbon, as well as the
boiling point of solvent. Glycerol, for example, has an extremely
high boiling point, but ethanol and methanol do not. If heating
temperatures applied during the process rise above respective
boiling points of hydrocarbon or solvent materials, then a clean
break between the solvent and hydrocarbon may not occur. When using
circulation loop techniques, as opposed to misting techniques
(e.g., to introduce the solvent mixture to the oil), it can be
useful to enclose the top of the storage tank (e.g., with a
floating roof) so as to minimize or eliminate vapors in a head
space of the tank.
Caustic and Acid Dosage
[0098] The initial dose of caustic can be calculated based on the
TAN of the crude. For example, a TAN of 5.4 is actually reporting
the mg/g of KOH required to fully neutralize the hydrocarbon. It
fundamentally translates to 1,000 ppm of KOH per point of TAN.
Since KOH is approximately 76% strength of NaOH, when utilizing
sodium hydroxide, your actual dosage can be reduced slightly to
account for the increase in strength.
[0099] On subsequent dosages, to the extent required, the caustic
is dosed into the solvent mixture at an amount sufficient to make
the solvent mixture have an elevated pH above 11. A simple lab pH
test checking the original pH of solvent mixture and slowly adding
small quantities of caustic until the pH of the known quantity of
solvent reaches above 11 provides the rate needed to set caustic
pumps. It can be useful to also check an actual sample of the
hydrocarbon/solvent mixture. If the oil has a "milkshake" creamy
appearance and the solvent appears to have created an emulsion that
is slow to break, then the pH is not high enough. In such
situation, the solvent mixture should continue to circulate while
gradual amounts of caustic are added in order to raise the pH to a
desired level that eliminates the emulsion and creamy
appearance.
[0100] Determining acid dosage required to convert any remnants of
soap back to a free oil soluble naphthenic acid is done through
observing pH changes. The first step comprises checking the
original pH of the recovered solvent, and then slowly adding acid
to the sample while continuing to observe pH. The appropriate acid
dosage is the amount necessary to make the pH of recovered solvent
equal to about 4.5 to 5. This dosage of acid is then injected into
the solvent mixture bound for the circulation loop. Converting the
soap back to naphthenic acid should begin upon introduction of the
acid dosed-solvent mixture, but a complete conversion can take up
to 24 hours. During circulation, it is advisable to take samples of
the oil/solvent solution. Allow the sample time to sit so that the
solvent mixture breaks from the oil, and check the pH of the
solvent. As the acid reacts with the naphthenates, the solvent pH
will rise. As long as the solvent pH is below 6, there is still
active acid. If the solvent pH gets above 6, although still an
acidic environment, it can be useful to further add a small amount
of acid to expedite the conversion. As the pH of the solvent goes
up, the TAN of the crude and calculated weak acid will also rise
due to conversion. The basic nitrogen will begin to lower in the
crude as it reacts with strong acid.
Exemplary Liquid-liquid Extraction Process
[0101] The embodiment illustrated in FIG. 1 is configured to
perform liquid-liquid extraction in bulk tankage. An exemplary
liquid-liquid extraction technique that can be performed using the
system illustrated in FIG. 1 is described below.
[0102] Step 1: If the hydrocarbon has a low flash, the first step
comprises a "light distillation" utilizing nitrogen to separate and
distill off the light ends to a light ends recovery tank. If the
processing tank 10 comprises a floating roof, then it should
include nitrogen purge valves for safety. This process may also be
performed in a processing tank lacking a floating roof. This
initial step of separating the light ends may also be skipped
depending on the end use of the hydrocarbon (e.g., if it were bound
for market at bunker fuel). Next, the hydrocarbon is heated to a
temperature about 10.degree. F. above the desired temperature the
liquid-liquid extraction will be performed at. Once the temperature
has reached this point, the nitrogen purge valve is opened and
nitrogen feed is pumped into the bottom of the processing tank
through the sparging system. The light ends that vaporize are
pushed to the light ends recovery tank and re-condensed. This first
step of the process is not generally suited for a hydrocarbon with
excessive light ends.
[0103] Step 2: The water/solvent mixture dosed with caustic (e.g.,
about 30-50% KOH or NaOH solution, typically 50% solution) in an
amount prescribed based on the Total Acid of the hydrocarbon (e.g.,
1,000 ppm per every point of TAN) and injected into the misting
system and/or circulation loop system (e.g., one or more
circulation loops incorporated with or into the processing tank 10,
as described above) via solvent tank 20. Along the way to the
misting system and/or circulation loop system, a heat exchanger
heats the caustic-dosed solvent mixture. The misting system and/or
circulation loop system distributes the caustic-dosed solvent
mixture in the processing tank, ultimately contacting the
hydrocarbon to the solvent mixture. Liquid-liquid extraction
proceeds via the reaction between the caustic and the hydrocarbon,
converting the naphthenic acid into naphthenates and utilizing
polarity to extract asphaltenes. (Note: If the hydrocarbon has no
light ends, this would be considered step 1.)
[0104] Step 3: If TAN and asphaltene removal is the only desired
outcome, then the solvent is extracted into an extracted solvent
tank 40, where the extracted solvent is dosed with acid and used to
revert the naphthenates back into naphthenic acid and adjust the
asphaltenes polarity enough to excise themselves from the solvent
and float
[0105] Step 4: If the hydrocarbon requires an additional sulfur
removal step, then the hydrocarbon is reacted with suitable
oxidizing materials to wash the sulfur out. Performing the acid
wash before a suitable oxidizing reaction would mitigate the
effectiveness of the oxidation step. Further optional steps may be
taken for spent water recycling and naphthenic acid recovery.
[0106] It should be appreciated that the systems and processes
described herein are advantageously useful to extract a number of
undesirable constituents from a hydrocarbon stock. Notably, that
includes naphthenates/naphthenic acids, metals, and salts, but the
processes extract, more generally, constituents in the hydrocarbon
that are polar. The pH of the solvent in the caustic phase allows
hydrocarbons that have any level of polarity to migrate to the
solvent to be extractable with naphthenic acid. Additionally, the
processes and systems described herein can isolate and extract the
following array of undesirable materials: asphaltenes, phenols,
metals, hydrogen, oxygen, nitrogen, hydrogen sulfide and
mercaptans, chlorides, and waxes, among others.
[0107] Asphaltenes tend to migrate to high pH solvent. They become
miscible/soluble in the alcohol solvent. Asphaltenes have a polar
tail, which is why they often cause emulsion issues at a desalter
especially in conjunction with naphthenic acids. The high pH
solvent is conducive for the asphaltenes of all carbon chain
lengths to migrate to the solvent. Migration occurs in the high pH
environment, where the polarity of the solvent and the non-polarity
of the oil is at its closest.
[0108] Phenols are not typically prevalent in crude oil; however,
they do appear on occasion, deriving from specialty chemicals being
placed downhole or slop oil or re-run being reintroduced into crude
for refining along with some naturally occurring. Phenols are
soluble in alcohol and will migrate to the solvent during the
extraction processes described herein.
[0109] Most metals in the caustic phase will either be present in
the form of a salt or a naphthenate and tend to migrate to the
solvent phase. Metals are recovered in the acid phase of the
extraction process as any remaining naphthenates not extracted in
the caustic phase are converted back to a naphthenic acid, and the
metal subsequently forms a salt that is polar and migrates to the
solvent.
[0110] It has been stated that the processes and systems described
herein extract salts and acid. Accordingly, inorganic chlorides
will reflect in either a salt or an acid. They are predominately
highly water soluble and thus extractable in the water-solvent
mixture. Organic chlorides, however, tend to migrate to the oil
phase. Industry desalters are relatively ineffective at removing
them. Organic chlorides are man-made and should not ideally exist
in crude, but nevertheless are often found in crude, in low grade
fuel oil, and in bunker fuel. The processes described herein have
an extraction effect on some of the commonly found organic
chlorides, such as chloroform or variants of vinyl chloride, either
due to a reaction with caustic forming a water, or alcohol soluble
salt, or solubility with ethanol or alcohol in general.
[0111] All refiners, regardless of their crude slate, must deal
with the components of crude that cause a variety of downstream
issues. For example, corrosion and fouling throughout the refinery
are a large concern. Salts, nitrogen, oxygen, metals, naphthenic
acid, strong acids, CO.sub.2 and asphaltenes are major causes of
both. By extracting the majority of these constituents using the
processes described herein will meaningfully reduce fouling and
corrosion throughout the refinery.
[0112] For example, many units in a refinery function with a
catalyst reaction. Metals, nitrogen, and oxygen are primary poisons
to all these catalysts. Refiners also have ancillary units
throughout the refinery to deal with removal of H.sub.2S,
mercaptans, and CO.sub.2 using amines, caustic, oxidation, or some
type of catalyst. Naphthenic acids, naphthalenes, metals,
asphaltenes all effect the final product quality specifications
and, more specifically, test results that indicate emissions
issues. The extraction of these undesirable materials in advance of
refinery processing (1) reduces workload and degradation on
downstream units designed to deal with such materials, (2) yields
downstream production of cleaner products, and (3) reduces harmful
environmental emissions attributable to the various downstream
refining processes.
[0113] While crude has been mentioned throughout this description,
the systems and processes described herein are not limited to
crude. The embodiments described herein are effective on
hydrocarbon inputs, products, and feed streams generally, if the
API gravity of the stream is higher than that of the solvent
mixture, which can range from a 5 to a 15 API gravity depending
upon the ratio of glycerol in the solvent mixture. Generally, the
API of the solvent mixture may fall within the range of 7 up to and
including 9, which is typically advantageous for dealing with heavy
crudes. The solvent mixture is effective at a higher API, however,
where the water/alcohol-to-glycerol ratio is higher. This is less
common but can present itself with residue streams and clarified
slurry oil, which can often have an API lower than the solvent
mixture. In those instances, it may be advantageous to add a cutter
to lift gravity of the product stream to increase effectiveness of
the extraction process.
[0114] As mentioned, the systems and processes described herein
provide potential downstream co-product/by-product benefits at
downstream processing plants. For example, considering a fuel oil
blend stock with a TAN over 100. A titration revealed the acid in
the stream was a weak acid. Using the liquid-liquid extraction
processes described herein, the acid was easily extracted. It is
doubtful that such acid was a naphthenic fatty acid, which has been
discussed above. Rather, it was more likely derived from an
entrainment of some form of weak acid being used as a catalyst in a
co-product stream. Pyrolysis gas oil streams are common co-products
stemming from chemical plants being blended to bunker or fuel oil.
They predominately have great properties but can have a few
specifications due to entrainment or reaction that are unwanted.
Using the embodiments described herein on non-crude streams have
also proven effective.
[0115] The embodiments described herein provide further positive
advantages for tank cleaning, rerun production and API separator
sludge production. The processes described have a profound impact
on future production and build-up of sludge throughout the
refinery. Crude tanks, for example, develop a large heel of sludge
that is primarily a combination of emulsified water, hydrocarbon
with polarity issues, and metals. The embodiments of the present
invention extract water, polar hydrocarbons, and metals, and thus
will inherently minimize future build-up of sludge within a crude
tank. Crude tank sludge is designated as hazardous waste with
cradle-to-grave disposal implications pursuant to federal and state
regulations. Most countries in the world also regulate crude tank
bottoms with hazardous waste disposal regulations. Crude tank
sludge is a major yearly source of reportable solid waste
production at a refinery or terminal, and implementation of the
systems and processes described herein can markedly reduce such
waste.
[0116] Another positive advantage is the ability to rerun sludge to
also help prevent build-up in equipment. A way to do this, for
example, is to add and blend a caustic-dosed solvent mixture with
the sludge to convert the sludge to reduce its viscosity and make
it a pumpable material. Once it is pumpable, the treated sludge is
transferred back into a processing tank to undergo the extraction
processes described above. Rerunning sludge in this manner can help
reduce solid waste disposal.
[0117] Product tanks similarly develop natural build-up and can,
over time, develop a heel of sludge due to metals and incompatible
portions of the product that tend to flocculate out. As with crude
tanks, extracting metals and incompatible portions of crude will
minimize the buildup of sludge in such product tanks. Most product
tanks are designated hazardous waste with cradle-to-grave issues of
their own. Product tank disposal is a major source of reportable
solid waste production within a refinery on a yearly basis, and
implementation of the systems and processes described herein can
markedly reduce such waste
[0118] A type of sludge of particular interest is API separator
sludge, which is an emulsion, a tar like substance of heavy oils,
metals, and water. It is a registered hazardous waste. The main
source of API separator sludge is desalter water oil under carry.
The embodiments of the present invention enable a refinery to
bypass desalter processing, therefore severely minimizing the
production of API separator sludge. API skim oil is the oil that
instead of sinking and forming a sludge remains floating and is
skimmed and re-routed to re-run or slop oil tanks. The major source
of skim oil is a desalter as well. The skim oil system is open to
the atmosphere and is a source of reportable emissions for a
refinery. The elimination of desalters and desalter processing, as
provided for by the present invention, can severely reduce the skim
oil production.
[0119] Rerun or slop oil is the agglomeration of all oil that does
not completely make it through the refining process and refiners
must attempt to re-process. It must be fed slowly as its metal
content, water content, cleanliness and incompatible portions of
crude are a major source of upsets and subsequent products going
off-spec thus creating additional re-run. Slop oil emulsions are
designated hazardous waste. The EPA does not define the specific
bounds for slop oil, so most refiners must consider the entire tank
hazardous waste if they elect to dispose. Disposal is an expensive
and reportable event. Most refiners seek to avoid disposal and opt
instead to attempt to re-process, often with detrimental effects.
Extracting metals, naphthenic acids, and incompatible portions of
crude while the crude is in bulk tankage--according to the
processes described herein--significantly increases desalter
efficiency, which can severely mitigate the production of rerun or
slop oil that refiners are effectively left to reprocess.
[0120] In addition to reducing waste, prolonging refinery
equipment, and increasing efficiency and processing output, the
inventive systems and processes described herein have multiple
positive environmental impacts. The embodiments described herein
have a positive and cumulative effect on fuel gas and natural gas
consumption at refinery, quantity of wastewater and quality of
water outfall at a refinery, actual fresh water consumed at a
refinery, total carbon footprint and emissions at refinery,
reduction of power consumed at pumps and compressors at refinery,
improvement of carbon footprint and total emissions of all products
produced at a refinery, as well as reduction of solid waste bound
for disposal at a refinery. A total carbon footprint of a refinery
not only accounts for power consumption, fuel consumption, water
consumption, and emissions, but also encompasses incoming and
outgoing materials and products for consumption within the refinery
and material exiting the refinery for disposal or recycling. The
systems and methods described herein minimize both incoming
products and outgoing disposal and recycling operations--thus
minimizing the complete carbon footprint of a refinery.
[0121] Examples of incoming reduction of footprint are delivery via
vehicle of incoming specialty chemicals and commodity chemicals,
such as scrubbing amines and cartridge filters, to be used
throughout the facility to filter metals and incompatible
particulates. Examples of outgoing reductions of the overall carbon
footprint are solid waste production from tankage and API
separators that include both the transportation and the subsequent
incineration for little to no productive use. There will also be a
reduction in spent amines that must be sent out for disposal or
recycling. In sum, the cumulative benefits are measurable and
accountable on water, air, and solid waste.
* * * * *