CA 02455149 2004-Ol-22
In-Line Hydrotreatment Process for Low TAN Synthetic Crude Oil
Production from Oil Sand
Field of the Invention
The invention relates to processing bitumen to reduce acid content.
Background to the Invention
Organic acids (Naphthenic, aromatic and paraffinic carboxylic acids) in crude
oils
have been demonstrated to strongly influence the corrosion rate in refining
equipment. The acidity of a crude oil is typically measured as the Total Acid
Number (TAN) by ASTM Method D664 or the UOP 565 Procedure. It is strongly
desirable to reduce the TAN of the crude oil as early in the oil refining
process as
possible, to minimize corrosion impact on the integrity of the refining
equipment.
It is well known that crude oils, and crude oil fractions contain sulfur,
nitrogen,
and other compounds, and a large number of processes have been proposed for
the removal of such compounds from crude oils and or crude oil fractions.
However, no single process or solution is useful, workable and economic for
all
crude oils as the organic components of crude oils vary depending on the
source
of the hydrocarbon. Consequently, processing methods and equipment must be
arranged to be effective for the crude oil constituents that are processed.
While
the organic chemical composition of fuel oil and lubricating oil products is
relatively uniform as supplied to the end use consumer, the hydrocarbon start
materials have diverse constituents that vary with the many locations on the
earth
that the hydrocarbon start materials are recovered from.
A particularly challenging hydrocarbon start material is bitumen as it
presents
numerous difficulties and virgin bituminous fractions have organic
characteristics
that are quite unique to bitumen as a source of oil products. Virgin Bitumen
distillates are produced by vacuum distillation processing of bitumen.
Typically,
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virgin bituminous distillates are quite different from distillates obtained
from
conventional crude oil sources. Virgin bituminous distillates contain very
high
concentrations of various ringed molecular structures, and are very low in
hydrogen content. For example, Canadian Athabasca tar sand bitumen usually
contains about 95% ringed molecular structures as compared to a 10-50% ringed
molecular structure content found in conventional crude oil hydrocarbons.
Moreover, distillates or fractions derived from bitumen are further
characterized
by a very high molecular weight and by having a high density, high viscosity,
low
viscosity-index and low fluidity properties. These unique properties of
bitumen
derived virgin fractions, particularly under lower hydroprocessing severity,
negatively affect the reactor hydrodynamics, resulting in lower mass transfer
rates; and hence render them more difFicult to upgrade into synthetic crude
oil.
Heretofore it was not known if organic acids in bitumen derived virgin
distillates
could be selectively removed at hydroprocessing severity conditions that are
below the conditions which result in the onset of sulfur and other reactions.
Moreover, the organic characteristics of bitumen hydrocarbons themselves vary
from one location to another. Bitumen located in Canada has chemical
properties and characteristics that are different again from the organic
characteristics of bitumen from other known sources in the world. Right from
the
outset, recovery of relatively small amounts of bitumen from tar sands sources
in
Canada requires handling vast amounts of sand and separating the bitumen from
the sand. Once the bitumen is separated from the sand, the bitumen must then
be upgraded into a synthetic crude oil to enable production of oil products
from
the bitumen.
In the processing of bitumen, bitumen fractions are produced, which are very
high
in organic acids. Sour Synthetic crude oils blended from these fractions are
very
high in TAN and also contain very high concentrations of sulfur, nitrogen and
other undesirable compounds. Severe hydrotreatment of the virgin bitumen
fractions, independently or in blends with other fractions produced from
thermo or
other conversion processes, is necessary to remove the undesirable compounds
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and reduce the TAN such that sweet, low TAN, synthetic crudes can be blended
for sale to refineries for conversion into fuel products.
One of the traditional approaches to reducing the acid content that is used in
processing facilities of other types of crude oils is to use chemical
neutralization,
where various bases are added to the crude oil to neutralize the acidic
components. Unfortunately, however, this approach has not been found to be
successful when applied to bitumen processing. In the context of bitumen
processing, this approach introduces other processing problems such as
emulsion formation, increases in the organic salts, particularly those of
calcium,
magnesium and sodium, which further exacerbates corrosion and conversion
issues in down-stream upgrading and refining process units.
Another approach is to refine crude oils into products even though the crude
oils
contain high TAN components. In this approach, corrosion-resistant metals are
used in the construction of refining units, which results in specialized
refining
facilities each with significant increased capital investment to provide the
corrosion-resistant units. Moreover, this approach is prohibitively expensive
to
retrofit onto existing refining facilities due to changes in component parts,
increased component costs, changes in process flows and changeover
production losses. Consequently, this approach is not in widespread use.
Another approach is to add corrosion inhibitors to the crude oil to protect
the
metallurgy of the refining units, which often results in other processing
complications in down-stream units such as catalyst poisoning andlor
inhibition,
or fouling in furnace tubes and other equipment etc.
Yet another approach is to blend high TAN crude oils with lower TAN crude oils
to reduce the TAN of the output crude oil and manage the corrosion rate at an
acceptable level in that manner. This approach results in high inventory costs
and greatly increases logistical and feed supply costs, for example sourcing
and
obtaining delivery of lower TAN crude oils for blending.
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The following patent documents relate to one or more of these approaches in
dealing with TAN components of conventional crude oils.
US patent No. 5, 985,137 describes a process to upgrade conventional crude
oils
by destruction of naphthenic acids, removal of sulfur and removal of salt by
mixing with alkaline earth metal oxides to convert substantially all of the
naphthenic acids contaminants to no-acid compounds, and alkaline earth metal
carbonates, and also to convert the sulfur contaminants to alkaline earth
metal
sulfide.
US Patent 6,531,055 B1 describes a process for extracting naphthenic acids
using solvent systems comprising liquid alkanols, water and ammonia, to
facilitate selective extraction and easy separation from conventional whole
crude.
US pat. No 5,961,821 describes a process for extracting organic acids, heavy
metals and sulfur from a starting crude oil comprising of treating the crude
oil with
ethoxylated amine and water under specified conditions and residence time to
form water-in-oil emulsion of amine salt for separation from the treated crude
oil.
Simila~iy, US pat. No 6,096,196 describes the same process as US pat. No
5,961,821 by treating the crude oil with alkoxylated amine and water.
US patent 4,634,519 similarly describes a process for extracting naphthenic
acids
using solvent systems comprising liquid alkanols, water and ammonia, to
facilitate selective extraction and easy separation from crude oil fractions
prepared by distillation.
The following patent documents relate to various hydroprocessing processes
that
have been proposed to reduce crude oil TAN.
US. Pat. No. 2,921,023 is directed toward a method of improve catalyst
activity
maintenance during mild hydrotreating to remove naphthenic acids in high
boiling
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petroleum fractions. The catalyst is molybdenum on a silica/alumina support
wherein the feeds are heavy petroleum fractions.
US. Patent No. 2,734,019 describes a process for treating a naphthenic
lubricating oil fraction by contacting with a cobalt molybdate on a silica-
free
alumina catalyst in the presence of hydrogen to reduce the concentration of
sulfur, nitrogen, and naphthenic acids.
US. Patent 3,876,532 relates to a very mild hydrotreatment of virgin middle
distillates from crude oils in order to reduce the total acid number or the
mercaptan content of the distillate without greatly reducing the total sulfur
content
using a catalyst which has been previously deactivated in a more severe
hydrotreating process.
Selective hydrogenation to remove essentially the naphthenic acids without
hydrogenating other compounds from crude oif and portions of crude oil has
been
reported in CA. Patent No. 2,198,623 and also in US. Patent No. 6;063,266. US
Patent #5,910,242 describes a process for reducing the Total Acid Number in
crude oil by hydroprocessing the crude oil in front of a refinery crude tower.
These hydroprocessing processes reduce the corrosivity of crude oils by
hydrotreatment in various process arrangements. The process arrangements
include stand-alone hydrotreaters dedicated to naphthenic acid removal, or a
refinery facility having a naphthenic acid hydrotreater placed in the crude
oil
processing process flow before the refinery crude tower. Thus these
hydroprocessing processes are arranged in a refinery environment to provide
equipment to process high TAN crude oils while reducing or eliminating
corrosion
caused by the high TAN crude Oil.
It is well known in the oil sand industry, where bitumen is first extracted
from tar
sands and then upgraded to synthetic crude oils, that virgin bituminous
fractions
are very high in organic acids. Consequently, sour synthetic crude oils
blended
from these virgin bituminous fractions are very high in TAN and also contain
very
high concentrations of sulfur, nitrogen and other undesirable compounds.
Severe
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hydrotreatment of the virgin fractions, independently or in blends with
fractions
produced from thermo or other conversion processes, removes the undesirable
compounds and reduces the TAN such that sweet, low TAN, synthetic crudes
can be blended for sale to refineries for conversion into fuel products.
Severe hydrotreatment to upgrade bituminous derived fractions is a capital-
intensive process. In addition to the hydrotreater, hydrogen production and
sulfur
recovery units are also required. Hence it is strongly desired for the oil
sand
industry to be able to produce a low TAN synthetic crude oil where
particularly
organic (naphthenic, aromatics, and paraffinic) acids from virgin bitumen
derived
distillates and blends of such virgin bituminous distillates, can be removed
economically.
Summary of the Invention
The present invention provides a low cost process for the removal of the
organic
(naphthenic, aromatic, paraffinic carboxylic) acids during the synthetic crude
oil
manufacturing process. in accordance with the invention, low TAN synthetic
crude oils can be produced from bitumen start material, which then eliminates
the
con-osion concerns of the refining industry when synthetic crude oils are
refined
into fuel products in refineries.
It has now been discovered, that virgin low TAN synthetic crude oils can be
produced by integrating a selective organic acid (naphthenic, aromatic and
paraffinic carboxylic acids) hydroprocessing unit within the synthetic crude
oil
manufacturing process. By providing a selective organic acid hydroprocessing
unit, other hydroprocessing conversion reactions for sulfur and other
undesirable
compounds that occur in a severe hydroprocessing unit are not necessary and
can be kept to a minimum.
It is possible to carry out selective removal of the organic acids from the
vacuum
fractionated cuts of virgin bitumen fractions by selective hydrogenation of
the
organic acids under very-mild conditions. Under such mild conditions, any
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substantial amount of desulfurization reactions or denitrification reactions
or
saturation reactions is avoided, which results in a moderate hydrogen
consumption. It has further been discovered that a comparative low hydrogen
purity (>50%) in the hydrotreating gas will effect good conversions. As a
consequence, common hydrotreater bleed gases may be used for the
hydrogenation process thereby eliminating the need for hydrogen production
units or equipment.
In one of its aspects the invention provides the selective hydrogenation of
the
organic acids under very mild conditions using a low purity hydrotreating gas.
The low purity hydrotreating gas is sourced from waste gases of the bitumen
processing plant into which the selective hydrogenation equipment is
integrated
with. Integration of the selective hydrogenation equipment with a bitumen
processing plant achieves numerous advantages resulting in lower costs are
achieved relative to the common art of using high purity hydrogen as a
hydrotreating gas.
The present invention provides a process for removing naphthenic and other
carboxylic acids from bitumen derived distillates and blends of such
distillates. In
accordance with the invention, the facilities to carry out the process are
incorporated into the bitumen processing facility that upgrades the bitumen
into
synthetic crude oil blending components. incorporation of the process
facilities
into a bitumen processing facility eliminates the need for separate hydrogen
production and process heat supplylcooling inputs to carry out the selective
hydrotreatment process. Thus reduced TAN of bitumen derived vacuum
distillates and blends of bitumen derived vacuum distillates is achieved. The
process of the invention can be integrated into the facilities of a bitumen
Upgrader that receive feed bitumen or diluted bitumen streams that are
produced
from bitumen sand excavation and Clarke hot water process or other bitumen
extraction or processes from Steam Assisted Gravity Drainage (SAGD) or other
bitumen production methods.
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if the bitumen is produced by excavating the tar sands formation material and
then extracting it from the sand using a caustic hot water process (i.e.
Clarke hot
water process) or other organic/inorganic solvent process, a pre-treatment of
the
bitumen derived distillates or blends of bitumen derived distillates to
demulsify,
dewater, and demineralize the bitumen feed material is generally necessary
prior
to distillation. However, if the bitumen is produced from tar sands by Steam
Assisted Gravity Drainage (SAGD) or other in situ thermally assisted gravity
drainage bitumen production methods, it may not be necessary to process the
bitumen to demulsify, dewater, and deminerafize it prior to distillation.
Irrespective of the manner in which the bitumen was produced, it is generally
advantageous to dilute the feed bitumen with hydrocarbon solvent or other
diluent.
The process of the invention achieves a selective reduction of the content of
organic acids in bitumen derived distillates, or blends of bitumen derived
distillates to less than about 0.45 mg KOHlg without the simultaneous
hydrogenation of sulphur compounds and nitrogen compounds which may be
present.
In accordance with the invention, apparatus to carry out the process is
integrated
within a bitumen Upgrader that processes bitumen recovered from tar sand into
synthetic crude oils. Thus, the invention provides a low capital and operating
cost solution by integrating the process within a bitumen Upgrader, and in
particular integrating the process with a bitumen vacuum fractionation unit of
the
bitumen Upgrader. In the preferred arrangement, the hot vacuum gas oils
produced by the bitumen vacuum fractionating unit are diverted from their run-
down heat exchangers and supplied directly as a hot feed to an in-line
hydrotreating reactor. Thus, process heaters to heat the hot feed of the
hydrotreating unit are eliminated. The in-line hydrotreating reactor product
is then
supplied to the run-down heat exchangers of the bitumen fractionating unit
vacuum tower to cool down the hydrotreated vacuum gas oils. Thus, separate
process heat exchangers to cool the product of a hydrotreating unit are
eliminated. This configuration of the in-line hydrotreating reactor arranged
with
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the fractionating unit vacuum tower allows the vacuum tower product to be
heated and cooled without additional equipment by using the exiting process
facilities of the bitumen fractionating unit vacuum tower.
The novel integrated configuration design provides a low capital and operating
cost solution that achieves reduction of the acidity of bitumen distillates to
obtain
low TAN synthetic crude oils. The process is incorporated in a bitumen
upgrading facility thereby eliminating the need for TAN treatment in
downstream
refineries that process the synthetic crude oil products obtained from the
bitumen
start material.
Thus, the invention provides a process for the manufacturing of low TAN
synthetic crude oils from oii sand derived bitumen streams by hydrotreatment
in a
selective hydro-deoxygenation processing facility nested within a bitumen
vacuum distillation unit. A preferred embodiment of the invention will now be
described with reference to the attached drawings.
Brief Description of the Drawings
Figure 1 - Is an overview process flow schematic diagram of a prior art
bitumen
processing plant drawn to identify process flows and equipment that
accommodate apparatus adapted to carry out the process of the invention.
Figure 2 - Is a process flow schematic diagram of the preferred embodiment of
an arrangement of apparatus adapted to carry out the process of the invention
including a conventional bitumen vacuum fractionation unit and an inline hydro-
deoxygenation reactor unit interoperably connected to it.
Figure 3 - Is a process flow schematic diagram of an alternate embodiment of
the
inline hydro-deoxygenation reactor unit of Figure 2 interconnected with a
conventional bitumen fractionation unit.
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Figure 4 - Is a graph of TAN of bitumen distillates after processing by
experimental pilot plant equipment arranged to carry out the process of the
invention operating under various conditions.
Detailed Description of the Preferred Embodiment
The description and drawings denote the same features by the same reference
characters throughout. Figure 1 shows an overview process flow schematic
diagram of a bitumen Upgrader bitumen processing facility drawn to show the
apparatus and process flows that are used to interconnect with to carry out
the
process of the invention. A geographic formation 10 includes a bitumen
containing tar sand formation that has a source of bitumen. The bitumen is
produced in one manner by mining or excavation and is then transported to and
processed in a bitumen upgrading processing facility. When the bitumen is
produced by excavation, the bitumen bearing tar sand is removed from the earth
at 12 and transported by truck 14 to a receiving facility. One form of
receiving
facility is a slurry transport pipe 16, which transports the bitumen sand to
the
intake facilities of the bitumen Upgrader where the bitumen is separated from
the
sand in primary separation cells 18. In the primary separation cells 18 the
received bitumen and sand material is mixed with a caustic hot water. The
bitumen is separated out of the slurry solution using air flotation producing
a
bitumen froth output 20.
The bitumen froth output 20 from the primary separation cells is supplied to a
secondary separation facility 22, which removes the water and mineral fines
present in the bitumen froth to obtain an enhanced bitumen product. During
processing in the secondary separation facility 22, a diluent 24 is also added
to
assist in the separation process by reducing the viscosity of the bitumen and
enhancing the purification of the bitumen produced by the secondary separation
facility 22. The bitumen product from the secondary separation facility is
processed by a diluent recovery unit 26 to remove the diluent 24 that was
added
to the bitumen in the secondary separation facility to assist in the
separation
process. The diluent recovered by the diluent recovery unit 26 is then
recycled
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back to the secondary separation facility as part of the diluent supply 24.
The
output of the diluent recovery unit is a bitumen feed 28.
An alternate method of bitumen production includes drilling a well 46 to
supply
steam to the bitumen sand formation from a source of steam 48. The steam
heats the bitumen in situ and increases its flowability causing it to pool in
the
tower portion of the volume treated by the steam. This form of bitumen
production is referred to as the steam assisted gravity drainage method
(SAGD).
The bitumen that pools in the formation is extracted from the well and is then
transported by pipe 50 directly to the diluent recovery unit 26 of the bitumen
Upgrader. Unlike the bitumen produced using the mining and flotation method,
the SAGD produced bitumen does not require separation from enormous
quantities of sand by a primary separation cell facility. As with bitumen that
is
extracted using mining and flotation methods 10, 12, 14, 16, 18, 20, the SAGD
recovered bitumen is processed by providing a diluent at 48 to reduce the
viscosity and increase the flowability of the recovered bitumen.
Irrespective of the method used to produce the bitumen, once the bitumen has
been processed in the DRU 26, the bitumen feed 28 is supplied to a vacuum
distillation unit 52, where virgin bitumen distillates (such as virgin
kerosens,
diesels, and gas oil cuts) 54 are produced. These virgin bitumen distillates
have
a high TAN content and have heretofore been used in blending sour synthetic
crude oil.
The residual bitumen 55 is then fed to a thermal conversion unit 30, for
example
a coker unit, for conversion to lighter hydrocarbons: The products from the
thermal conversion or coker unit 30 are separated into coker products streams
based on boiling points ranges. From the coker unit, a coker gases stream 32
is
produced as well as other streams of compounds with differing ranges of
boiling
points, including a stream 34 of naphtha compounds that have a boiling point
less
than about 315°F. Also produced are a stream 36 of diesel compounds
which
have higher boiling points in the 300-650°F range and a stream 38 of
gas oils that
have boiling points in excess of 600°F.
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The distillate compounds produced by the coker unit 30 are low in hydrogen
content and are high in Sulfur, Nitrogen and other undesirable constituents.
Consequently each of these compounds is further treated in the bitumen
upgrading process by supplying each of the compounds streams to a
corresponding hydro-treatment facility 40. After the hydro-treatment process,
the
hydrotreated petroleum products streams, namely, the paraffinic gas oils
stream
PG, the paraffinic diesels stream PD and the paraffinic naphtha stream PN, are
supplied to a corresponding storage facility 42. For product delivery, the
petroleum products are drawn from storage and are blended at blending facility
44 to produce sweet low TAN synthetic crude for supply to downstream refiners.
The invention provides a bitumen processing facility that includes a hydro-
deoxygenating facility 74 which provides a mild hydro-treatment to effect TAN
reduction in a manner that will be explained in more detail with reference to
Figures 2 and 3. The process of the invention produces low TAN gas oil
products
for sour low TAN synthetic crude oil blending which overcome the difficulties
that
are present when high TAN gas oil products are processed in downstream
refinery processing.
Thus the process of the invention is carried out in the facilities of a
bitumen
Upgrader to remove essentially organic acids from the virgin distillate
hydrocarbon oils derived from bitumen or diluted bitumen. In accordance with
the
process of the invention, virgin bitumen distillates, or blends of such
distillates,
are separated from the bitumen feed of the bitumen Upgrader and then
hydrogenated at very mild temperature over a catalyst. The catalyst is of a
kind
used for hydrogenation of vacuum gas oils andlor atmospheric residue, and
preferably is a catalyst consisting of nickel-molybdenum or cobalt-molybdenum,
deposited on alumina as a carrier material. The process is carried out by a
bitumen vacuum fractionating unit that interoperates with the facilities of a
bitumen Upgrader producing:
(a) a distillate derived directly from (Althabasca) bitumen; or
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(b) a blend of distillates, in any ratio which has previously been distilled
into fractions, from (Althabasca) bitumen
In the process of the invention it is preferred to carry out the hydrogenation
at a
pressure range of 300-650 PS1G, at a temperature range of 350 - 600°F
preferably in the range of 400-530 degrees Fahrenheit, at a Liquid Hourly
Space
Velocity (LHSV) range of 0.1-5.0, being the ratio of the volume of feed
divided by
the volume of catalyst, and with a charge gas supply rate range of 250-1500
standard cubic feet per barrel (SCFB).
The hydrogenation is suitably effected in one or more parallel reactors or one
or
more reactors arranged in series, each reactor having one or more fixed
catalyst
beds. As mentioned, the catalysts utilized in the process of the invention are
such catalysts that have proved to be suitable for hydrogenation of gas oils
and
atmospheric residue oils. To carryout the mild hydrogenation process in a
bitumen processing facility successfully, it is important that the carrier
material of
the catalyst is sufficiently porous to allow penetration by diffusion of even
the
heaviest part of the bitumen derived distillates or blends of bitumen derived
distillates into the catalyst pores. Therefore, the carrier material should
have
porosity such that the final supported catalyst preferably has a porosity of
the
magnitude 10 to 12 nanometers (nm). Particularly useful catalysts comprise
nickel-molybdenum or cobalt-molybdenum deposited on afumina as a carrier
material. The bitumen derived distillate or blends of bitumen derived
distillates
flow rate through the catalyst is preferably 0.5 to 5.0 LHSV and most
preferred
1.0 to 3.0 LHSV.
On exit from a vacuum faction distillation tower unit 52, the hot virgin
distillates
while at distillation temperature are supplied to a hydrogenation reactor. In
the
preferred embodiment, the distillates are supplied directly to a hydrogenation
reactor along with a hydrogen rich (>50% H2) gas for processing at the
conditions just specified. In an alternate embodiment, the hot distillates are
sent
to a surge tank. Distillates drawn from the surge tank are pumped to
processing
pressure and then mixed with hydrotreater bleed gas containing at least 50% H2
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at a rate in the range of 500 -1500 SCFB. The mixture is supplied to the
hydrogenation reactor for processing directly. Depending on the temperature of
the hot virgin distillate(s), and the molecular species of organic acids as
well as
the properties of the virgin distillates, booster heater may be added for
higher
reaction temperature if required.
An example of a facility arranged in a preferred manner to embody the process
flows of the invention is described in more detail herein. The main features
of the
preferred embodiments are shown in Figures 2 and 3.
In Figure 2 a bitumen feed 28 is supplied to a vacuum fractionator vacuum
distillation tower unit 52. The vacuum fractionator distills the bitumen feed
into a
hot virgin Light Vacuum Gas Oil (LVGO) stream 58 and Heavy Vacuum Gas Oi1
(HVGO) stream 60, at 365 degrees Fahrenheit and 520 degrees Fahrenheit
respectively. The high TAN LVGO and HVGO streams are taken off the vacuum
distillation tower unit 52 by pumps 62 and 64. In the preferred embodiment of
Figure 2 tap points 66, 68 are provided in the LVGO and HVGO process streams
and portions 70, 72 of the LVGO, HVGO streams are taken off the output process
streams of the vacuum distillation tower unit 52. The portions 70, 72 of the
LVGO
and HVGO streams that are taken, are taken either alone or by combining the
stream portions together in various volume ratios. The amounts taken and any
combining effected varies and is determined by what is found to be useful to
obtain optimal processing of the time-varying constituents found in the
bitumen
feed 28 and the portions taken can include all of LVGO and HVGO streams in
their entirety. The portions taken of the LVGO and HVGO streams 70, 72 are
supplied to an in-line hydro-deoxygenation hydroprocessing unit 74.
The portions taken off the distillate streams from the vacuum distillation
tower unit
52, or blends of the distillate streams, while still hot from egress from the
vacuum
distillation tower unit 52, are pressured up to hydrogenation pressure range
of
500-650 PSIG by a charge pump system 76. A hydro deoxygenation.heater
(HTR) 78 may be provided if desired depending on the process needs such as:
target TAN level, feed quality, catalyst consumption/aging rate.
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The pressurized distillate or distillate blend is mixed with a hydrogen charge
gas
80, which is obtained from a source of hydrogen gas. In the preferred
embodiment, the source of hydrogen gas is the pressurized waste gas from other
hydroprocessing units found in a bitumen Upgrader that the hydrotreater
process
system is deployed in. The hydrogen charge gas preferably contains at least
50% hydrogen and is supplied at a rate m the range of 100-1000 standard cubic
feet per barrel (SCFB), and preferably at a rate in the range of 400-700 SCFB.
The actual supply rate will vary depending on the hydrogen content of the
charge
gas and other operating parameters. Where the source of the charge gas 80 is
obtained from other hydroprocessing units of the bitumen Upgrader, it
preferably
contains 5-6% of H2S to enhance the reactions of organic acid conversion
within
the in-line hydro-deoxygenation reactor unit 74.
The mixture of the vacuum gas oil liquids 70, 72 and hydrogen charge gas 80 is
supplied to an in-line hydro-deoxygenation reactor unit 74. Depending on the
temperature of the hot virgin distillate(s), the molecular species of organic
acids,
as well as the properties of the virgin distillates and target TAN content, a
booster
heater (HTR) 78 may be added for higher reaction temperature if required as
shown in Figure 3. The hydro-deoxygenating reactor unit 74 has a catalyst
beds)
of sufficient size and is loaded with catalysts) proven to remove organic
acids
from the feed. The treated vacuum gas oil (VGO) reactor effluent 82 exits the
reactor to a gas-liquid separator 84. The liquid output 86 of the gas-liquid
separator is returned to a return tap point 88 to supply the reduced TAN
liquid
output 86 to an output stream of the vacuum distillation tower unit where it
will
continue in the downstream process of that system. The heat in the product
fluids is recovered by heat exchangers 90. The heat recovered is typically
then
supplied or recycled to heat at 91 the bitumen feed 28 of the vacuum
distillation
tower unit 52.
The waste gas 92 of the gas-liquid separator is returned to the originating
bleed
gas treatment system that it was supplied from at 80. The bleed gas treatment
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system is present in the facilities of a bitumen Upgrader and provides
treatment
of bleed gas by hydrogen recovery and/or sweetening for fuel gas production.
The cooled product liquid continues through to the bitumen Upgrader vacuum
distillation tower unit rundown system 94, which provides additional cooling,
or
recycling to the vacuum distillation tower, as needed prior to reporting to
tankage
96. The lower organic acid product collected in tankage 96, as measured by
Total Acid Number (TAN), is used to blend sour low-TAN crude for transport to
market.
If hydrogen rich waste gas 80 from another hydrotreater is not available, or
in
insufficient quantity for once through operation, or to maximize utilization
of
available hydrogen in the waste gas, a recycle gas circuit complete with a
compressor may be employed to recover the hydrogen containing gas from the
hydro-deoxygenation reactor effluent.
Suitable process equipment and suitable safe operating procedures for carrying
out the process of the invention as described herein is available from
suppliers of
the equipment utilized in well-known processes for hydrogenation of gas oils.
It is
to be noted, however, that additional equipment, which is used in connection
with
gas sweetening, sulphur recovery and nitrogen removal, is not contemplated or
required to carry out the process of the invention.
Figure 3 shows an alternate embodiment of an in-line hydro-deoxygenation unit.
In the embodiment of Figure 3, the portions of the LVGO and HVGO streams 70,
72 taken off the vacuum distillation unit are supplied to a feed drum 98. The
portions of the LVGO and HVGO streams that are taken, are taken either alone
or by combining the streams together in various volume ratios. The amounts
taken and any combining effected varies and is determined by what is found to
be useful to obtain optimal processing of the time-varying constituents found
in
the bitumen feed 28. A temperature and flow controller 900 is preferably
provided to control the flow rates of the portions 70 and 72 of the LVGO and
HVGO streams that are supplied to the in-line hydro-deoxygenating unit 74.
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The portions 70, 72 taken ofF the distillate streams from the vacuum
distillation
unit 52, or blends of the distillate streams, while still hot from egress from
the
vacuum distillation unit 52, are pressured up to hydrogenation pressure by a
charge pump system. In the embodiment of Figure 3, the charge pump system
has a charge pump 102 disposed at the outlet of the feed drum 98. The
pressurized distillate or distillate blend is mixed with a hydrogen charge gas
80
and the mixture is supplied to the in-line hydro-de-oxygenation reactor unit
74.
The treated vacuum gas oil (VGO) reactor effluent 82 exits the reactor to a
gas-
liquid separator 84. The liquid output 86 of the gas-liquid separator is
supplied to
the return tap point 88 where it is incorporated into an output stream of the
vacuum distillation tower to continue in the downstream process of that
system.
Apparatus to carry out the process of the invention provides a low severity
hydrogenation, or hydro-deoxygenation, unit that is integrated in operation
with a
bitumen processing facility. The hydrogenation unit is placed within the
process
flows of a bitumen processing facility to obtain operating efficiency and
reduced
processing cost in processing the bitumen into synthetic crude oil components.
Operating efficiency and reduced processing cost is achieved through several
benefits obtained by integration with a bitumen Upgrader. A significant
capital
and operating cost saving is achieved by obtaining the hydrogenation process
hot
supply feed at operating temperature from the process flows within the bitumen
Upgrader, which eliminates the need for a separate feed or charge heater.
Consequently the fuel consumption for the hydrogenationlhydro-deoxygenation
reactor is eliminated. In certain configurations, such as that shown in Figure
3,
where the supply feed may cool during residency in a feed drum, a charge
heater
may advantageously be provided. A charge heater may also be used to
advantage where the cost of providing and operating a charge heater to obtain
elevated process temperatures is offset by a cost reduction obtained by a
reduction in size of the hydro-deoxygenation reactor needed to operate at the
higher temperature.
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Other operating efficiency and reduced processing cost reductions achieved
through integration with a bitumen Upgrader include.
o The hydrogenation reactor product cooling is integrated with the
distillation product cooling system for better process cooling and
heating efficiency in product rundown to tankage, resulting in significant
reductions in capital cost and operating costs, including savings in
lower maintenance requirements.
o A hydrotreater charge gas containing a comparatively low hydrogen
content is advantageously used, thereby reducing or eliminating the
need for stand-alone or additional hydrogen production and or
purification facilities to support the low severity hydrogenation TAN
reduction process in the bitumen Upgrader.
o Preferably the hydrotreater charge gas is a bleed gas from other
hydrogenation units in the bitumen Upgrader, allowing for once-through
hydrogen gas configuration, and eliminating the need for additional
make-up compressor facilities or recycle gas compression or recovery
facilities in the bitumen Upgrader.
o If hydrogen rich waste gas 80 from another hydrotreater is not
available, or in insufficient quantity for once through operation, or to
maximize utilization of available hydrogen in the waste gas, a recycle
gas circuit complete with a compressor may be employed to recover
the hydrogen containing gas from the hydro-deoxygenation reactor
effluent.
The cost of integrating the process of the invention with the virgin oil
fractionator
processing bitumen is a small fraction of the capital cost of a traditional
complete
stand-alone hydrogenation unit.
Thus, with the new process flows described herein, which are incorporated into
existing bitumen processing flows arranged with the diluted bitumen diiuent
recovery unit andlor a bitumen vacuum distillation unit, there is no need for
any
additional process heater, heat exchangers or any additional capacity for
waste
water treatment, sulfur handling and hydrogen supply.
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Now that the arrangement to carry out the process of the invention has been
described, persons skilled in the art will readily be able to accommodate
known
gas oil hydrogenation construction techniques to arrange facilities that carry
out
the process of the invention.
Pilot plant tests were performed to investigate the reduction of Total Acid
Number
(TAN) in a blend of bituminous hydrocarbon intermediate streams from a bitumen
fractionation unit. The runs were carried out using a ChevronTexaco
hydrotreating catalyst product named AT-405 operated at a total pressure of
550
psig, over a LHSV range of 2 to 3, and an GHSV range of 500 or 1500 SCF/B,
containing 0 to 7% H2S in the charge gas.
The objectives of the test program were to:
~ Demonstrate that low TAN sour virgin distillates can be produced from
high TAN bituminous stocks for production of iow TAN sour synthetic
crude blending for sale to the refineries.
~ Measure the TAN reduction kinetics for the blend of Bitumen derived virgin
distillates.
~ Determine the hydrogen consumption of the process.
Experimental Details
Feedstocks
Samples of virgin vacuum LVGO and HVGO distillates derived from Althabasca
Bitumen were blended for processing. Detail inspections of the properties of
the
virgin bitumen derived distillates were performed and the results of the
inspections are outlined in Table I below.
Table I - Properties of Bituminous LVGO ~ HVGO & Blend by liquid volume
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Feed ID Description HVGO LVGO Blend
82LV%
HVGO
18LV%
LVGO
-_.. - -
APP Gravity 14.7 21.5 15.9
Sulfur, Wt % 3.4 2.46 3.23
Viscosity Index -31 16 -12
Viscosity 100C, cSt 8.96 2.40 7.02
Viscosity 40C, cSt 138.20 10.36 82.34
TAN, mg KOHIg 4.96 2.91 4.34
Bromine Number, gBR/100g 11.6
Nitrogen, ppm 1570 478 133()
UV Absorbance
Wavelength GramlLiter GramlLiterGramll.iter
226nm 32.76575 31.43568 32.59277
255 nm 19.55795 11.43124 19.40041
272 nm 14.13724 7.79867 14.06157
305 nm 5.78895 2.77768 5.75053
310 nm 4.65795 1.89056 4.62105
340 nm 1.50828 0.39794 1.50106
348 nm 1.0153 0.24735 1.00717
385 nm 0.17963 0.04768 0.18377
435 nm 0.006 -0.00083 0.01416
450 nm -0.00402 0.00113 0.00875
Simulated distillation TBP
(Weight %) F F F
0.5 519 376 466
I
S 607 460 579
636 495 621
30 704 569 702
50 763 617 762
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70 817 664 823
90 904 737 906
95 943 782 945
99.5 1044 915 102()
As indicated by the UV Absorbance measurements of the test results given in
Table 1, the bitumen compounds are high in ringed unsaturates and the
chemistry of these gas oils are very different from the measurements that
would
typify conventional crude oils. The UV absorbance measurements are typical of
absorbance measurements of bitumen derived distillates obtained from the
Athabasca tar sands.
Catalyst
A hydrotreating catalyst manufactured by ChevronTexaco and available as their
product AT 405 was used to perform pilot tests. The catalyst contains cobalt,
molybdenum, and alumina. It was tested as a presulfided 1/20" diameter
cylindrical extrudate, with a nominal Length to diameter ratio of 3 to 4. The
catalyst load was 100 cc, 70.4 grams on a dry basis.
Operating Conditions
Table II shows the matrix of operating conditions used in the pilot plant
tests and
the key results obtained. Note that six sets of conditions were studied.
Table II - Operating Conditions for the Suncor Pilot Plant Tests
Run Run Run Run Run Run
Run Operating Conditions 1 2 3 4 5 6
Reactor Temp, F 485 485 485 525 525 485
LHSV, Hr 2.0 2.0 2.0 2.0 3.0 2.0
Total Pressure, psig 547 551 557 554 544 543
Average H2 Partial Pressure,310 381 302 305 299 293
psia
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GaslOil Ratio, SCFIB 500 1500 500 500 500 500
TAN in Product- mg KOH/g 0.65 0.55 0.70 0.35 0.60 0.65
Hydrogen Consumption - SCFB 39 52 41 69 40 40
Changes in [Sulfur) wt% NIC NlC NIC NIC NIC NIC
Changes in [Nitrogen) ppmW NE NE NE NE NE NE
Changes in [Aromatics] wt% NE NE NE NE NE NE
NC = No Change detected
NE = No Change Expected due to higher severity requirement than hydro-
desulfurization.
The results listed in Table II are presented in graph form in Figure 4, thus
the
graph of Figure 4 presents the same information as Table II and summarizes the
results of the six runs graphically.
Based on the results of the pilot testing, the following may be observed:
~ At 2.0 LHSV and 500 SCF/B gasloil ratio, the SOR temperature to
accomplish 90% TAN reduction is 510°F.
~ At 90% TAN reduction, conversion of feed components to products with
boiling points below 650°F was ~3 wt %, with a net chemical H2
consumption of ~60 SCFIB.
~ Increasing gas/oil ratio from 500 to 1500 SCFIB increased TAN reduction
activity by ~15°F.
~ Negligible catalyst deactivation was observed over an 800-hour period,
based on operations at 485°F and 2.0 LHSV.
~ No detectable changes in Nitrogen, Sulfur and aromatic concentrations
had been observed in the low TAN product samples.
Now that the invention has been described, numerous substitutions,
modifications and equivalents will become apparent to those skilled in the
art.
The invention is not limited to the preferred embodiments that have been
described to illustrate the invention, but rather is defined in the claims
appended
ao2oo~ os.~
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