Note: Descriptions are shown in the official language in which they were submitted.
CA 02900794 2015-08-18
PARAFFINIC FROTH PRE-TREATMENT
BACKGROUND
Field of Disclosure
[0001] The disclosure relates generally to the field of oil sand
processing. More
specifically, the disclosure relates to processing bitumen froth.
Description of Related Art
[0002] This section is intended to introduce various aspects of the art,
which may be
associated with the present disclosure. This discussion is believed to assist
in providing a
framework to facilitate a better understanding of particular aspects of the
present disclosure.
Accordingly, it should be understood that this section should be read in this
light, and not
necessarily as admissions of prior art.
[0003] Modern society is greatly dependent on the use of hydrocarbon
resources for
fuels and chemical feedstocks. Hydrocarbons are generally found in subsurface
formations
that can be termed "reservoirs." Removing hydrocarbons from the reservoirs
depends on
numerous physical properties of the subsurface formations, such as the
permeability of the
rock containing the hydrocarbons, the ability of the hydrocarbons to flow
through the
subsurface formations, and the proportion of hydrocarbons present, among other
things.
Easily harvested sources of hydrocarbons are dwindling, leaving less
accessible sources to
satisfy future energy needs. As the costs of hydrocarbons increase, the less
accessible sources
become more economically attractive.
[0004] Recently, the harvesting of oil sand to remove heavy oil has
become more
economical. Hydrocarbon removal from oil sand may be performed by several
techniques.
For example, a well can be drilled to an oil sand reservoir and steam, hot
air, solvents, or a
combination thereof, can be injected to release the hydrocarbons. The released
hydrocarbons
may be collected by wells and brought to the surface. In another technique,
strip or surface
mining may be performed to access the oil sand, which can be treated with
water, steam or
- 1 -
CA 02900794 2015-08-18
solvents to extract the heavy oil. Where the oil sand is treated with water,
the technique may
be referred to as water-based extraction (WBE). WBE is a commonly used process
to extract
bitumen from mined oil sand.
[0005] In an example of WBE, mined oil sands are mixed with water to
create a slurry
suitable for extraction. Caustic may be added to adjust the slurry pH to a
desired level and
thereby enhance the efficiency of the separation of bitumen.
[0006] Regardless of the type of WBE employed, the extraction process
will typically
result in the production of a bitumen froth comprising bitumen, water and fine
particles and a
tailings stream comprising coarse particles and some fine particles and water.
The tailings
stream may consist essentially of coarse particles and some fine particles and
water. A typical
composition of bitumen froth may be about 60 weight (wt.) % bitumen, 30 wt. %
water, and
wt. % solids, based on a total weight of the bitumen froth. The water and
solids in the
froth are considered as contaminants. The contaminants may be substantially
eliminated or
reduced to a level suitable for feed to an oil refinery or an upgrading
facility, respectively.
Elimination or reduction of the contaminants may be referred to as a froth
treatment process.
Elimination or reduction of the contaminants may be achieved by diluting the
bitumen froth
with a solvent. The solvent may comprise any suitable solvent, such as an
organic solvent.
For example, the organic solvent may comprise naphtha solvent and/or
paraffinic solvent.
Diluting the bitumen with solvent (also referred to as dilution) may increase
the density
differential between bitumen and water and solids. Diluting the bitumen with
solvent may
enable the elimination or reduction of contaminants using multi-stage gravity
settlers. Use of
the multi-stage gravity settlers may result in a "diluted bitumen froth" and
froth treatment
tailings. The froth treatment tailings may comprise residual bitumen, residual
solvent, solids
and water. The froth treatment tailings may be further processed to recover
residual solvent,
for instance in a tailings solvent recovery unit (TSRU).
[0007] Certain processes use naphtha to dilute bitumen froth before
separating the
product bitumen by centrifugation. These processes are called naphtha froth
treatment (NFT)
processes. Other processes use a paraffinic solvent, and are called paraffinic
froth treatment
- 2 -
CA 02900794 2015-08-18
(PFT) processes, to produce pipelineable bitumen with low levels of solids and
water. In the
PFT process, a paraffinic solvent (for example, a mixture of iso-pentane and n-
pentane) is
used to dilute the froth before separating the product, diluted bitumen, by
gravity. A portion
of the asphaltenes in the bitumen is also rejected by design in the PFT
process and this
rejection is used to achieve reduced solids and water levels. In both the NFT
and the PFT
processes, the diluted tailings (comprising water, solids and some
hydrocarbon) are separated
from the diluted product bitumen.
[0008] Solvent is typically recovered from the diluted product bitumen
component
before the bitumen is delivered to a refining facility for further processing.
[0009] One PFT process will now be described further, although variations
of the
process exist. The PFT process may comprise at least three units: Froth
Separation Unit
(FSU), Solvent Recovery Unit (SRU) and Tailings Solvent Recovery Unit (TSRU).
Two
FSUs may be used, as shown in Figure 1.
[0010] With reference to Figure 1, mixing of solvent with the feed
bitumen froth (100)
is carried out counter-currently in two stages: FSU-1 and FSU-2, labeled as
Froth Separation
Unit I (102) and Froth Separation Unit 2 (104). The bitumen froth comprises
bitumen, water,
and fine solids (also referred to as mineral solids). A typical composition of
bitumen froth is
about 60 wt% bitumen, 30 wt% water, and 10 wt% solids, based on a total weight
of the
bitumen froth. The paraffinic solvent is used to dilute the froth before
separating the product
bitumen by gravity. Examples of paraffinic solvents are pentane or hexane,
either used alone
or mixed with isomers of pentanes or hexanes, respectively. An example of a
paraffinic
solvent is a mixture of iso-pentane and n-pentane. In FSU-1 (102), the froth
(100) is mixed
with the solvent-rich oil stream (101) from the second stage (FSU-2) (104).
The temperature
of FSU-1 (102) is maintained at, for instance, about 60 C to about 80 C, or
about 70 C, while
the solvent to bitumen (SB) ratio may be from 1.4:1 to 2.2:1 by weight or may
be controlled
around 1.6:1 by weight for a 60:40 mixture of n-pentane: iso-pentane. The
overhead from
FSU-1 (102) is the diluted bitumen product (105) (also referred to as the
hydrocarbon leg) and
the bottom stream from FSU-1 (102) is the tailings (107) comprising water,
solids
- 3 -
CA 02900794 2015-08-18
(inorganics), asphaltenes, and some residual bitumen. The residual bitumen
from this bottom
stream is further extracted in FSU-2 (104) by contacting it with fresh solvent
(109), for
instance, in a 25 to 30:1 (w/w) SB ratio at, for instance, about 80 C to about
100 C, or about
90 C. Examples of operating pressures of FSU-1 and FSU-2 are about 550 kPag
and 600
kPag, respectively. The solvent-rich oil (overhead) (101) from FSU-2 (104) is
mixed with the
fresh froth feed (100) as mentioned above. The bottom stream from FSU-2 (104)
is the
tailings (111) comprising solids, water, asphaltenes and residual solvent,
which is to be
recovered in the Tailings Solvent Recovery Unit (TSRU) (106) prior to the
disposal of the
tailings (113) in an ETA. The recovered solvent (118) from TSRU (106) is
directed to the
solvent storage (110). Solvent from the diluted bitumen overhead stream (105)
is recovered
in the Solvent Recovery Unit (SRU) (108) and passed as solvent (117) to
Solvent Storage
(110). Bitumen (115) exiting the SRU (108) is also illustrated. The foregoing
is only an
example of a PFT process and the values are provided by way of example only.
An example
of a PFT process is described in Canadian Patent No. 2,587,166 to Sury.
[0011] It would be desirable to provide an alternative or improved
process for treating
bitumen froth.
SUMMARY
[0012] It is an object of the present disclosure to provide alternative
or improved
processes for processing bitumen froth.
[0013] Disclosed is a process including providing a bitumen froth
comprising
bitumen, water, and solids. A paraffinic solvent is added to the bitumen froth
in an amount
below an asphaltene precipitation point to form a diluted bitumen froth. Water
is removed
from the diluted bitumen froth to form a dewatered diluted bitumen froth.
Additional
paraffinic solvent is added to the dewatered diluted bitumen froth in an
amount above an
asphaltene precipitation point for precipitating asphaltene aggregates. The
dewatered diluted
bitumen froth is separated to form a hydrocarbon-rich stream and a solids-rich
stream.
- 4 -
CA 02900794 2015-08-18
[0014] The foregoing has broadly outlined the features of the present
disclosure so
that the detailed description that follows may be better understood.
Additional features will
also be described herein.
BRIEF DESCRIPTION OF THE DRAWINGS
[0015] These and other features, aspects and advantages of the disclosure
will become
apparent from the following description, appending claims and the accompanying
drawings,
which are briefly described below.
[0016] Figure 1 is a prior art paraffinic froth treatment (PFT) process.
[0017] Figure 2 is a flow chart of a bitumen froth processing.
[0018] Figure 3 is a flow diagram of a bitumen froth processing.
[0019] It should be noted that the figures are merely examples and no
limitations on
the scope of the present disclosure are intended thereby. Further, the figures
are generally not
drawn to scale, but are drafted for purposes of convenience and clarity in
illustrating various
aspects of the disclosure.
DETAILED DESCRIPTION
[0020] For the purpose of promoting an understanding of the principles of
the
disclosure, reference will now be made to the features illustrated in the
drawings and specific
language will be used to describe the same. It will nevertheless be understood
that no
limitation of the scope of the disclosure is thereby intended. Any alterations
and further
modifications, and any further applications of the principles of the
disclosure as described
herein are contemplated as would normally occur to one skilled in the art to
which the
disclosure relates. It will be apparent to those skilled in the relevant art
that some features
that are not relevant to the present disclosure may not be shown in the
drawings for the sake
of clarity.
- 5 -
CA 02900794 2015-08-18
[0021] At the outset, for ease of reference, certain terms used in this
application and
their meaning as used in this context are set forth below. To the extent a
term used herein is
not defined below, it should be given the broadest definition persons in the
pertinent art have
given that term as reflected in at least one printed publication or issued
patent. Further, the
present processes are not limited by the usage of the terms shown below, as
all equivalents,
synonyms, new developments and terms or processes that serve the same or a
similar purpose
are considered to be within the scope of the present disclosure.
[0022] Throughout this disclosure, where a range is used, any number
between or
inclusive of the range is implied.
[0023] A "hydrocarbon" is an organic compound that primarily includes the
elements
of hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any
number of other
elements may be present in small amounts. Hydrocarbons generally refer to
components
found in heavy oil or in oil sand. However, the techniques described are not
limited to heavy
oils but may also be used with any number of other reservoirs to improve
gravity drainage of
liquids. Hydrocarbon compounds may be aliphatic or aromatic, and may be
straight chained,
branched, or partially or fully cyclic.
[0024] "Bitumen" is a naturally occurring heavy oil material. Generally,
it is the
hydrocarbon component found in oil sand. Bitumen can vary in composition
depending upon
the degree of loss of more volatile components. It can vary from a very
viscous, tar-like,
semi-solid material to solid forms. The hydrocarbon types found in bitumen can
include
aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be
composed of:
19 weight (wt.) % aliphatics (which can range from 5 wt. % - 30 wt. %, or
higher);
19 wt. % asphaltenes (which can range from 5 wt. % - 30 wt. %, or higher);
30 wt. % aromatics (which can range from 15 wt. % - 50 wt. %, or higher);
32 wt. % resins (which can range from 15 wt. % - 50 wt. %, or higher); and
some amount of sulfur (which can range in excess of 7 wt. %), based on a total
weight
of the bitumen.
- 6 -
CA 02900794 2015-08-18
In addition, bitumen can contain some water and nitrogen compounds ranging
from less than
0.4 wt. % to in excess of 0.7 wt. %. The percentage of the hydrocarbon found
in bitumen can
vary. The term "heavy oil" includes bitumen as well as lighter materials that
may be found in
a sand or carbonate reservoir.
[0025] "Heavy oil" includes oils which are classified by the American
Petroleum
Institute ("API"), as heavy oils, extra heavy oils, or bitumens. The term
"heavy oil" includes
bitumen. Heavy oil may have a viscosity of about 1,000 centipoise (cP) or
more, 10,000 cP or
more, 100,000 cP or more, or 1,000,000 cP or more. In general, a heavy oil has
an API
gravity between 22.3 API (density of 920 kilograms per meter cubed (kg/m3) or
0.920 grams
per centimeter cubed (g/cm3)) and 10.0 API (density of 1,000 kg/m3 or 1
g/cm3). An extra
heavy oil, in general, has an API gravity of less than 10.0 API (density
greater than 1,000
kg/m3 or I g/cm3). For example, a source of heavy oil includes oil sand or
bituminous sand,
which is a combination of clay, sand, water and bitumen. The recovery of heavy
oils is based
on the viscosity decrease of fluids with increasing temperature or solvent
concentration. Once
the viscosity is reduced, the mobilization of fluid by steam, hot water
flooding, or gravity is
possible. The reduced viscosity makes the drainage or dissolution quicker and
therefore
directly contributes to the recovery rate.
[0026] "Fine particles" are generally defined as those solids having a
size of less than
44 microns (p.m), that is, material that passes through a 325 mesh (44
micron).
[0027] "Coarse particles" are generally defined as those solids having a
size of greater
than 44 microns (rim).
[0028] The term "solvent" as used in the present disclosure should be
understood to
mean either a single solvent, or a combination of solvents.
[0029] The terms "approximately," "about," "substantially," and similar
terms are
intended to have a broad meaning in harmony with the common and accepted usage
by those
of ordinary skill in the art to which the subject matter of this disclosure
pertains. It should be
understood by those of skill in the art who review this disclosure that these
terms are intended
- 7 -
CA 02900794 2015-08-18
to allow a description of certain features described and claimed without
restricting the scope
of these features to the precise numeral ranges provided. Accordingly, these
terms should be
interpreted as indicating that insubstantial or inconsequential modifications
or alterations of
the subject matter described and are considered to be within the scope of the
disclosure.
[0030] The articles "the", "a" and "an" are not necessarily limited to
mean only one,
but rather are inclusive and open ended so as to include, optionally, multiple
such elements.
[0031] The term "paraffinic solvent" (also known as aliphatic) as used
herein means
solvents comprising normal paraffins, isoparaffins or blends thereof in
amounts greater than
50 wt. %, based on a total weight of the solvent. Presence of other components
such as
olefins, aromatics or naphthenes may counteract the function of the paraffinic
solvent and
hence may be present in an amount of only 1 to 20 wt. % combined, for instance
no more than
3 wt. %. The paraffinic solvent may be a C4 to C20 or C4 to C6 paraffinic
hydrocarbon solvent
or a combination of iso and normal components thereof The paraffinic solvent
may comprise
pentane, iso-pentane, or a combination thereof The paraffinic solvent may
comprise about 60
wt. % pentane and about 40 wt. % iso-pentane, with none or less than 20 wt. %
of the
counteracting components referred above.
[0032] Conventionally in a PFT process, a paraffinic solvent is mixed
directly with the
bitumen froth (comprising bitumen, water, and solids). When sufficient
paraffinic solvent is
added, large aggregates form between the precipitated asphaltenes (and
entrained maltenes),
fines, and water. The density of the formed aggregates is a function of their
composition and
the density of each component.
[0033] Described herein is a process which increases the average density
of the
aggregates by removing water in the bitumen froth prior to adding sufficient
solvent for
asphaltene precipitation. By removing water, the solids content of the formed
aggregates
increases and therefore the aggregates will have a higher average density.
Higher density
aggregates may improve solid-liquid separation.
- 8 -
CA 02900794 2015-08-18
[0034]
Additionally, removing water upstream of a first separator may reduce
agglomeration of free coarse solids and/or aggregates thereby reducing
hydrocarbon
entrainment to a solids-rich stream. In particular, hydrophilic particles will
agglomerate
together in the presence of water in a hydrocarbon continuous phase.
Therefore, by reducing
this agglomeration (by removing the water), the amount of hydrocarbon
(comprising solvent
and maltenes) entrainment to the solids-rich stream may be reduced.
[0035]
Other potential advantages may include a higher bitumen throughput, a lower
solvent use, reduced solids carry-over from the first separator, and reduced
volumes to the
first separator.
[0036]
Figure 2 is a flow chart of bitumen froth processing. As seen in Figure 2, a
bitumen froth is provided (202) including bitumen, water, and solids. A
paraffinic solvent is
added (204) to the bitumen froth in an amount below an asphaltene
precipitation point to form
a diluted bitumen froth. Additives that modify fluid properties and help with
water separation,
such as viscosity or surface tension modifiers or emulsion breakers, may or
may not be added.
Water is removed (206) from the diluted bitumen froth to form a dewatered
diluted bitumen
froth. Additional paraffinic solvent is added (208) to the dewatered diluted
bitumen froth in
an amount above an asphaltene precipitation point for precipitating asphaltene
aggregates.
The dewatered diluted bitumen froth is separated (210) to form a hydrocarbon-
rich stream and
a solids-rich stream. Where the separation is gravity separation, the
hydrocarbon-rich phase is
an overflow and the solids-rich stream is an underflow. The hydrocarbon-rich
stream is richer
in hydrocarbons than the dewatered diluted bitumen froth and may comprise a
small amount
of residual solids, for instance less than 1000 ppm by weight on a bitumen
basis. The
solids-rich stream is richer in solids and asphaltene aggregates than the
dewatered diluted
bitumen froth.
[0037]
Figure 3 is a flow diagram of bitumen froth processing. Figure 3 includes the
steps illustrated in Figure 2 along with additional features. A bitumen froth
(302) is provided
including bitumen, water, and solids. The bitumen froth (302) may be pumped in
a froth
pump (304) and mixed with a paraffinic solvent (306) in an amount below an
asphaltene
- 9 -
CA 02900794 2015-08-18
precipitation point to form a diluted bitumen froth (308). Static or dynamic
mixers may be
used to assist mixing of the bitumen froth (302) and the paraffinic solvent
(306). The
paraffinic solvent may be any suitable paraffinic solvent. For instance, the
paraffinic solvent
may comprise greater than 50 vol % pentane. Where the solvent is pentane, the
solvent to
bitumen ratio may be less than about 0.8, which is below a typical asphaltene
precipitation
point for pentane in this environment.
[0038] The diluted bitumen froth (308) may then be passed through a mixer
(310), a
pump, or any other suitable shear device, before dewatering which is
illustrated as in Figure 3
as a water knock-out drum (312). The dewatering may be effected by any
suitable device.
For instance, the dewatering may be effected by a water knock-out drum, a
bulge in a pipe, an
enhanced gravity separator, or a flow regime that facilitates water separation
in a pipe. The
enhanced gravity separator may be any suitable enhanced gravity separator. For
instance, the
gravity separator may comprise a cyclone or a centrifuge. The dewatering
device(s) may also
remove some coarse mineral solids that may otherwise cause erosion in piping
and
equipment.
[0039] Water (314) may be removed from the diluted bitumen froth (308) to
form a
dewatered diluted bitumen froth (316). Any suitable amount of water may be
removed. For
instance, at least 15 wt.%, or at least 50 wt.%, or at least 75 wt.%, or at
least 90 wt.%, or at
least 95 wt.% water may be removed, based on an initial weight of water in the
dewatered
diluted bitumen froth. The dewatered diluted bitumen froth (316) may comprise
any suitable
amount of water. For instance, the dewatered diluted bitumen froth may
comprise less than
15 wt. % water or between 1 and 15 wt. % water, based on a weight of the
dewatered diluted
bitumen froth.
[0040] The aggregates may have an average density of above 1000 kg/m3,
and as high
as 2000 kg/m3. Aggregate density is a function of the percentage of each
component and the
component density. Asphaltenes, maltenes, solvent, water, and solids are all
components of
the aggregates. Bitumen (comprising asphaltenes and maltenes) and water have a
density of
about 1000 kg/m3. Solvent density may be much lower, for instance about 600
kg/m3. Solids
- 10 -
CA 02900794 2015-08-18
have a higher density, for instance about 2650 kg/m3. Typical aggregates may
have densities
from 870 to 1000 kg/m3. By removing water, the fraction of solids is increased
to increase the
overall aggregate density above 1000 kg/m3.
[0041] The bitumen froth or the diluted bitumen froth may be sheared to
facilitate the
water removal. Shear may be applied by any suitable method and equipment.
Examples
include flow in a pipe, static mixers, dynamic mixers, and pumps.
[0042] Additional paraffinic solvent (318) may then be added to the
dewatered diluted
bitumen froth (316) in an amount above an asphaltene precipitation point for
precipitating
asphaltene aggregates. For example, where the solvent is pentane, the solvent
to bitumen
ratio may be about 1.6:1, which is above a typical asphaltene precipitation
point for pentane in
this environment.
[0043] The dewatered diluted bitumen froth (316) may then be sent through
a
pre-separator mixer (320) for mixing with the additional paraffinic solvent
(318) and to a
separator (322) to form a hydrocarbon-rich stream (324) and a solids-rich
stream (326). The
separator (322) may be any suitable separator. The separation may be performed
by gravity
separation or by enhanced separation. Non-limiting examples of enhanced
separation devices
are cyclones, centrifuges, and inclined plate separators. The separator may be
a settler, for
instance a froth separation unit (FSU), as described above. Where two or more
separators are
used, they may be arranged in series or in parallel or the combination thereof
[0044] Solvent may be recovered from the hydrocarbon-rich stream (324) to
produce a
bitumen product (not shown). For example, the hydrocarbon-rich stream (324)
may be passed
through a solvent recovery unit (SRU) (not shown) or other suitable apparatus
in which the
solvent is flashed off and condensed in a condenser associated with the
solvent flashing
apparatus and recycled/reused in the process. The SRU may be any suitable SRU,
such as but
not limited to a fractionation vessel. Any suitable amount of solvent may be
removed.
Recovered solvent may be recycled (not shown) as paraffinic solvent (306)
and/or as
additional paraffinic solvent (318).
- 11 -
CA 02900794 2015-08-18
[0045] The solids-rich stream (326) may be sent to a second separator
(not shown), for
instance as described above as a second FSU. A second paraffinic solvent (not
shown) may
be added to the solids-rich stream followed by gravity separating the solids-
rich stream.
[0046] The paraffinic solvent (306) added to the bitumen froth (302) or
the additional
paraffinic solvent (318) added after dewatering may comprise recycled solvent
or a second
hydrocarbon-rich stream from gravity separation of the solids-rich stream.
[0047] Water (314) removed in the dewatering step may be recycled (328)
to a bottom
portion (322a) of the separator (322) or to a downstream separator (not
shown). The bottom
portion may be a bottom cone portion, a dense bed region in the separator, or
anywhere below
a separation interface. Water (314) removed in the dewatering step may also or
alternatively
be recycled (330) to a downstream tailings solvent recovery unit (TSRU) (not
shown) as
dilution water. Water (314) removed in the dewatering step may also or
alternatively be
recycled to an inlet feed of a downstream separator (not shown).
[0048] It should be understood that numerous changes, modifications, and
alternatives to the preceding disclosure can be made without departing from
the scope of the
disclosure. The preceding description, therefore, is not meant to limit the
scope of the
disclosure. Rather, the scope of the disclosure is to be determined only by
the appended
claims and their equivalents. It is also contemplated that structures and
features in the present
examples can be altered, rearranged, substituted, deleted, duplicated,
combined, or added to
each other.
- 12 -
