United States Patent [19]
Leto et al.
[11] Patent Number:
[45] Date of Patent:
4,648,964
Mar. 10, 1987
32 Claims, 5 Drawing Figures
FOREIGN PATENT DOCUMENTS
630710 11/1961 Canada.
910271 9/1972 Canada.
918091 111973 Canada.
952837 8/1974 Canada 208/390
952839 8/1974 Canada 208/390
Primary Examiner-Asok Pal
Attorney, Agent, or Firm-Sheridan, Ross & McIntosh
3,884,829 5/1975 Moyer 252/331
3,900,389 8/1975 Baillie 208/188
4,005,005 111977 McCollum et al 208/390
4,158,638 6/1979 Tsai 208/391
4,192,731 3/1980 Steams et a1. 208/390
4,238,315 12/1980 Patzer, II 208/435
4,272,383 6/1981 McGrew 210/741
4,324,652 4/1982 Hack 209/3
4,358,373 11/1982 Jubenville 210/181
4,385,982 5/1983 Anderson 208/390
4,425,227 1/1984 Smith 209/5
A process suitable for separating the hydrocarbon fraction
from a tar sands froth is provided. The process
comprises heating a fluid stream comprising the froth to
above about 300° C., pressurizing the stream to above
about 1000 psig and separating the hydrocarbon fraction,
having less than 1 percent solids and less than 5
percent water, from the treated stream. Separation is
preferably by gravitational settling in a settler and occurs
substantially instantaneously. The heat/pressure
treatment can be optionally followed by addition of a
diluent, such as naphtha. The pressure is preferably
produced by the hydrostatic head of a column of froth.
[57] ABSTRACT
[56] References Cited
U.S. PATENT DOCUMENTS
895,229 8/1908 Beddoes 210/617
2,223,184 11/1950 Pier et a1. 208/429
2,772,209 1l/1956 Stewart et al 208/145
2,789,083 4/1957 Hardy 208/390
2,809,153 10/1957 Bacsik et al 208/6
2,864,502 1211958 May 210/774
3,291,717 1211966 White 208/390
3,331,765 7/1985 Canevari et al 208/391
3,338,814 8/1967 Given et al 208/425
3,401,110 9/1968 Floyd et al 208/391
3,422,000 111969 Bichard 208/391
3,464,885 9/1969 Land et al 166/17
3,606,731 9/1971 Cole et al 55/45
3,606,999 9/1971 Lawless 423/659
3,607,721 9/1971 Nagy 208/390
3,684,699 8/1972 Vermeulen et al 208/188
3,716,474 2/1973 Hess et al 252/390
3,853,759 1211974 Titmas 210/600
[54] SEPARATION OF HYDROCARBONS FROM
TAR SANDS FROTH
[75] Inventors: Joseph J. Leto, Broomfield; Dennis
D. Gertenbach, Golden; Daniel W.
Gillespie, Wheatridge, all of Colo.
[73] Assignee: Resource Technology Associates,
Boulder, Colo.
[21] App1. No.: 771,204
[22] Filed: Aug. 30, 1985
[51] Int. Cl.4 ClOG 1/04
[52] U.S. Cl 208/390; 208/391
[58] Field of Search 208/11 LE, 8 LE, 13;
252/346, 347, 348
u.s. Patent Mar. 10, 1987 Sheet 1 of4 4,648,964
18
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u.s. Patent Mar. 10, 1987 Sheet 2 of4 4,648,964'
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u.s. Patent Mar. 10, 1987 Sheet 3 of4 4,648,964
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u.s. Patent Mar. 10, 1987 Sheet 4 of4 4,648,964
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TEMPERATURE,oC
SEPARATION OF HYDROCARBONS FROM TAR
SANDS FROm
This invention relates to a process for separating the
hydrocarbon fraction from a tar sands froth and particularly
to a separation process comprising heating and
pressurizing a tar sands froth.
4,648,964
1
FIELD OF THE INVENTION
BACKGROUND OF THE INVENTION
2
described by Canevari et al. (U.S. Pat. No. 3,331,765,
1967) and Moyer (U.S. Pat. No. 3,884,829, 1975). The
cost of reagents has an effect on the economics of such
processes. Even where some of the additives can be
5 later recovered for recycle, a portion of the additives is
typically degraded or otherwise lost to the recycle
processes, particularly in processes which include treatment
at elevated temperatures and/or pressure following
addition of reagents. Furthermore, such processes
10 involve a cost for transporting the additives to the treatment
site which, in a tar sands froth application, is ad-
A number of processes for recovery of bitumen from vantageously a field site.
tar sands result in the formation ofa hydrocarbon-water A number of froth treatment processes involve the
froth having an amount of fmely divided solids dis- use of elevated temperatures or pressures during some
persed therein. Typically, about 99 percent of the solids 15 portion of the treatment. Given et al. (U.S. Pat. No.
consists of quartz grains and clay minerals. The maxi- 3,338,814, 1967) disclose a multi-step process for treatmum
sand grains size is about 1 mm diameter. About ing a bituminous emulsion, the first step of which in-
99.9 percent of the mineral matter is fmer than 100 vo1ves a dehydration zone maintained at temperatures
microns (about -150 mesh). of from about 2250 F. to about 5500 F. (1070 C. to 2880
One widespread tar sands treatment process is the 20 C.) and pressures offrom about 4 psig to about 1000psig
so-called hot water extraction process. According to in which vaporized water is removed from other conthis
process, a mined bitumen sand is sent to a condition- stituents of the froth. Solids are separately removed
ing drum. Caustic soda is added to adjust the pH to
between about 7.5 to about 9.0. Steam is used to adjust downstream. May (U.S Pat. No. 2,864,502, 1958) disthe
temperature to about 1800 to 1900 F. (820 to 880 C.) 25 closes a multistage treatment for gas-oil-water emuland
make-up water is added to form a pulp having a sions including emulsion breaking under a pressure of
solids content of about 70 percent. Oversized material is 30 pounds.
removed from this pulp by screening, and the screened Other heat/pressure treatment methods have been
pulp is sent to a flotation device. In the flotation device, used to separate oil fractions in waste treatment prothe
pulp is agitated to introduce air bubbles. Those 30 cesses. Cole et al. (U.S. Pat. No. 3,606,731, 1971) discomponents
of the pulp which are least easily wetted close that when the growth of algae in a water treatare
preferentially carried to the surface by the bubbles ment facility or an API separator forms an algae-oilto
form a froth. This froth is a fluid emulsion of water water emulsion detrimental to water treatment proand
hydrocarbons, such as bitumen. Non-hydrocarbon cesses, it is useful to coke the emulsion under autogesolids,
such clay and sand, are typically dispersed in the 35 nous pressure at elevated temperatures. In the feeds
fluid. The froth is separated from the bulk of the pulp. treated by Cole et al., the algae form an emulsifying
The so-called tar sands flotation froth which exits the agent. Cole et al. disclose heating the emulsion to coke
flotation device typically contains about 40 to about 75 the algae, thus substantially removing the emulsifying
percent bitumen, about 10 to about 50 percent water agent. Hess et al. (U.S. Pat. No. 3,716,474, 1973) disand
less than about 15 percent solids. 40 close treating an oil-water sludge at a temperature of
This froth is treated downstream by such pr.ocesses as between about 7500 F. and 8500 F. (3990 C. to 4540 C.)
delayed or fluid coking, residual hydrocracking, or at elevated pressures. In the examples disclosed in Hess
solvent deasphalting. In most cases, it is advantageous et al., pressures of 3900 to 6150 psig were used. The
to decrease the water and/or solids content of the tar Hess et al. process is directed to treatment of a sludge
sands froth prior to such downstream processing. 45 from a refmery disposal pit which typically contains
A method f?r r.emoving water and so~ids fro~ tar emulsifying agents such as metallic salts and aromatic
s~ds froth which IS commonly employed.IS ce~trifuga- sulfonic acids. To remove metallic, particularly organotlOn
of the fr<;>th. Such methods are descnbed m Evans metallic, contaminates, Hardy (U.S. Pat. No. 2,789,083,
et al. (Canadian Patent No. 918,091, 1973), Hall et al. 1957) d' Itt' h d bo il am' ul I
(Canadian Patent No. 910,271, 1972) and Baillie (U.S. 50 . 18C ?S~ re~ ~g a ~ rocw: ~ 0 , p c.ar y
P t N 3 900 389 1975) Oth h d d
· gas oil or similar distillate oils, which mvo1ves subJecta
. o. , " . er ar ware eVlces. 1 . bo 5000 F d
which have been proposed for solids removal include a mg an emu slon to a temperaru:e a ve . an a
hydrocyclone, as described by Given et al. (U.S. Pat. pressure of abo~t 100 to 5~ pSlg..
No. 3,338,814,1967), an electrostatic desalter described A co~on dIflicul~y With prevlOus.froth treatment
by Anderson (U.S. Pat. No. 4,385,982, 1983) and an 55 methods IS. th<:, necessity for const~ctlOn of elaborate
ultrasonic vibrator described by Jubenville (U.S. Pat. an~ expensl~e apparatus for performmg th~ processes.
No. 4,358,373, 1982). One difficulty common to such This. necessIty ~ak~s the processes particularly ?Oa!-
hardware approaches is related to the fact that a solids- tractIve for a~plicatlOn to tar sands recovery which 18
containing tar sands froth has a highly abrasive nature. mo.st econonncally condu~ted when san.d an~ other
Because of this, such hardware devices are relatively 60 solIds are separated from bitumen before mcurnng the
quickly rendered inoperable by attrition. Such devices cost of transport to treatment facilities. Furthermore, in
are also relatively expensive to acquire, install and oper- treating tar sands froths, such apparatus is susceptible to
ate, particularly at field sites. abrasion from solids. Methods which require addition of
Other approaches to removal of water and solids reagents have proven uneconomical for many applicafrom
a tar sands froth have included chemical additions, 65 tions and particularly where recycle of reagents is preranging
from a simple diluent addition such as that vented because of thermal degradation.
described by Nagey (U.S. Pat. No. 3,607,721, 1971), to Previous methods produce only slight, if any, inmore
complicated chemical treatments such as those creases in settling rates. These methods are accompa5
4
tIer, will separate into hydrocarbon and water phases
without the necessity for extended settling periods, i.e.
in less than about 1 minute, and, typically, less than
about 15 seconds.
It may be convenient or desirable to add a diluent
following the heat/pressure treatment. Addition of a
diluent is particularly advantageous when the hydrocarbon
constituent of the froth is viscous, as a means for
reducing viscosity and density of the hydrocarbon
phase. Since the diluent can be added following the
heat/pressure treatment and, preferably, following a
cooling step, the diluent is not significantly degraded,
evaporated or otherwise lost as might happen if the
diluent were subjected to the elevated heat/pressure
15 treatment of the present invention. All post-heat/pressure
treatment steps are preferably conducted so as to
minimize creation of turbulence or mixing or stirring
the treated froth, so as to facilitate phase separation of
the treated froth.
4,648,964
SUMMARY OF THE INVENTION
3
nied by gravity settling which is typically extended in
time, and often must be augmented with centrifugation.
Accordingly, it is an object of this invention to provide
a process for separating hydrocarbons from a tar
sands froth which can be practiced in the field.
It is also an object of this invention to provide a tar
sands froth hydrocarbon separation process that involves
minimal consumption of energy, reagents and
equipment.
It is a further object of this invention to provide a 10
process for treating a stream comprising a tar sands
froth which results in a substantially instantaneous gravitation
separation the hydrocarbon fraction from the
treated stream.
The present invention provides a process suitable for
separating the hydrocarbon fraction from a tar sands
froth. The process comprises heating a fluid stream
comprising the froth to a treatment temperature above 20
about 300· C., pressurizing the stream to a treatment BRIEF DESCRIPTION OF THE FIGURES
pressure above about 1000 psig to produce a treated FIG. 1 is a schematic flow diagram of the preferred
stream, and separating the hydrocarbon fraction from
the treated stream. embodiment of the present invention.
Although the process of the present invention is par- 25 FIG. 2 is a schematic flow diagram of the preferred
ticularly applicable to tar sands froths, the invention is process of the present invention applied to a tar sands
generally applicable to any dispersion of solids in a fluid extraction operation.
which contains hydrocarbons. As used herein, "hydro- FIGS. 3 and 4 ar.e diagrams of differential thermal
carbon" is a compound or mixture of compounds con- analyses ~f fro~h solids fr~m aut~clave tests.
taining carbon and hydrogen and can additionally con- 30 FIG. ~ IS a dlagr~ of differential thermal analyses of
tain other elements commonly present in organic and froth solids from IDlcrotube tests.
organometallic compounds such as oxygen, nitrogen, DESCRIPTION OF THE PREFERRED
sulfur, phosphorus, and halogens and metals. The pre- EMBODIMENTS
ferred hydrocarbon-containing fluid for this process is a
tar sands froth produced by the hot water tar sands 35 The present invention relates to a process for separatextraction
process. ing solids from a hydrocarbon-containing fluid, particu-
The invention comprises treatment at elevated tem- larly a tar sands froth, by subjecting !he flui? to e1ev~ted
peratures and pressures to achieve separation of the temperatures and pressures for a penod oftlIDe. PartICUhydrocarbon
fraction from the remaining portions of lar1y contemplated for treatment by the process of the
the treated feed stream. The heat/pressure treatment 40 present inventi~n ~e fluids w~ch contain hydrocarrenders
the treated froth amenable to rapid phase sepa- bons such as bitunnnous ma!en~ from tar .sands, .alration
so that the hydrocarbon fraction can be segre- thoug~ the process has applications for flwds which
gated by means of gravity settling, thickening, decanta- contain othe~ hydrocarbons such as petroleum and kertion,
etc. ogen from oil shale. Thus, although the present inven-
According to the process ofthe present invention, the 45 tion may be practiced with any dispersion of solids in a
froth is heated to above about 300· C. and subjected to hydrocarbon-containing fluid, it is particularly useful
a pressure of greater than about 1000 psig. The resi- for treatment of a tar sands flotation froth. "Tar sands",
dence time of the froth at the elevated temperature and as used herein, should be understood to include oil
pressure depends upon such factors as the chemical sands.
composition of the hydrocarbon, the amount of coking 50 The tar sands froths treated by this procedure will
that can be tolerated and the concentration of solids in typically be emulsions of water and hydrocarbons, with
the froth, but will generally be in the range of between solids and gas entrained therein. Separation of the hyabout
1 and about 60 minutes, preferably between about drocarbon fraction of those froths from water and from
1 and about 15 minutes. barren (non-hydrocarbon) solids is desirable in order to
Following the pressureiheat treatment, the constitu- 55 accomplish effective and economical refining of the
ents of the froth are separated. The separation can be hydrocarbons. A preferred feed is a raw froth, i.e. a
accomplished in a settler, by decantation or other simi- froth substantially in the same condition as when it exits
lar means. A cooling step, including cooling by heat the froth flotation device, without any substantial interexchange
with the untreated froth or by other cooling vening additions, or heat/pressure treatment. The raw
means, can precede the settling/separation. When ap- 60 froth may have been treated by such means as settling,
plied to a tar sands froth, the process of the present in order to remove a first portion of easily separated
invention has been found to result in substantially in- water and/or solids. The preferred feed is substantially
stantaneous separation of the hydrocarbon phase from diluent-free, i.e., it has no substantial amount of a 10wthe
solids-containing water phase. In this context, "sub- viscosity liquid miscible in the hydrocarbon fraction
stantially instantaneous" settling means that after the 65 which is not present in the raw froth. A typical flotation
heat/pressure treatment described more fully below, froth will comprise from 10 to 50 weight percent water,
the treated froth, upon contact with a water layer, such 40 to 75 weight percent hydrocarbons and less than
as that typically present in a continuous-operation set- about 15 weight percent non-hydrocarbon solids.
4,648,964
5
The separation of the hydrocarbon fraction from a
froth, according to the present invention, is not necessarily
an absolute separation, in the sense that a certain
amount of solids and/or water can be tolerated in the
separated hydrocarbon fraction. The maximum cOlicen- 5
tration of solids which can be tolerated in the separated
hydrocarbon fraction depends upon the downstream
use or processing to which the hydrocarbon fraction
will be subjected. When the hydrocarbon fraction is
destined for a coker process, for example, the hydrocar- 10
bon fraction should contain less than about 1 weight
percent solids, and less than about 5 weight percent
water. Similarly, it is not necessary that the separated
hydrocarbon fraction contain 100 percent of the hydrocarbons
present in the froth. The separated hydrocar- 15
bon fraction preferably contains a substantial portion,
typically greater than about 75 percent, of the total
froth hydrocarbon content.
Tar sand froths which can be advantageously treated
by the method of the present invention may include, 20
besides water, hydrocarbon and clay and sand solids,
other types ofliquids suCh as dissolved alkali pH modifiers
or detergents, gaseous components such as gaseous
ammouia or C02, and matter derived from living material
such as algae, bacteria, etc. 25
Referring now to FIG. 1, a feed stream 10 is provided
to the process. As discussed above, the feed can be any
hydrocarbon-containing fluid and preferably comprises
a tar sands flotation froth comprising hydrocarbons,
water and non-hydrocarbon solids such as clay or sand 30
or a combination thereof. The stream 10 is conducted to
a heat/pressure treatment zone 14 where it is subjected
to elevated temperature and pressure. The product
exiting the heat/pressure treatment zone 14 is a treated
stream 15. The treated stream 15, at the point ofleaving 35
the heat/pressure treatment zone 14, can be unseparated,
i.e. with solids and/or water still substantially
dispersed with the hydrocarbon fraction, or the hydrocarbon
fraction can be partially or fully separated from
the other components of the treated stream. However, 40
the treated stream 15 is in such a condition that if allowed
to settle, the hydrocarbon phase separates from
the treated stream at an enhanced rate, i.e. at a rate
faster than the rate of separation of hydrocarbons from
the untreated stream. When hydrocarbon-water phase 45
separation is to be based on density differences, it is
important that the hydrocarbon fraction of the treated
stream 15 have a density less than water.
In order to assist in raising the bulk temperature of
the feed stream 10 to the preferred treatment tempera- 50
ture described below, the stream is preferably passed
through a heat exchanger 12 to recover heat from the
outgoing heat/pressure treated stream 15. The heat
exchanger 12 can be of a number of designs suitable for
transfer of heat between fluids, including a design 55
which involves juxtaposition of a conduit carrying the
untreated incoming fluid stream 11 and a conduit carrying
heat/pressure treated stream 15.
The stream which has been optionally heated in the
heat exchanger 12 is subjected to a heat/pressure treat- 60
ment comprising heating the stream to a treatment temperature
above about 300· C., and pressurizing the
stream to a treatment pressure above about 1000 psig.
By "heating and pressurizing" the stream it is meant
that any given macroscale volume or "parcel" of the 65
fluid stream is subjected to an elevated bulk temperature
and pressure. Although, in the preferred embodiment,
heating, pressurizing and separating are con-
6
ducted in a continuous flow process, the process of the
invention can also be conducted by treating the stream
in a discontinuous or batch mode. The stream is preferably
maintained at the treatment temperature and pressure
for a time between about 1 and about 60 minutes to
produce a treated stream.
A variety of apparatus can be used in the heat/pressure
treatment step of the present invention including
autoclaves and tubular reactors. Apparatus, such as
high pressure pumps, for achieving elevated pressures is
typically elaborate and expensive. Hess et al. (U.S. Pat.
No. 3,716,474, 1973) disclose high pressure pumps connected
to an insulated pressure vessel. Such pumps
would be quickly abraded by the solids present in tar
sands froth if the method of Hess et al. was employed to
achieve pressurization ofthe feed. The examples in Cole
et al. (U.S. Pat. No. 3,606,731, 1971) disclose using an
autoclave to achieve pressurization. Because of the
abrasive nature of solids-containing tar sands froth, the
apparatus disclosed in Cole et al. and Hess et al. would
be subject to operational difficulties and high maintenance
costs.
In the preferred embodiment ofthe present invention,
the heat/pressure treatment is conducted in a vertical
tube reactor. In this fashion, the fluid pressure can be
substantially continuously increased to the desired
level. In such a reactor, at least part of the pressure is
provided by the hydrostatic head of the feed stream. In
such a reactor, the heat exchange step previously described
can be conveniently accomplished by arranging
downcomer and riser tubes adjacent to one another or
concentric to one another. A vertical tube reactor is
inexpensive to install and operate, compared to previous
froth separation apparatus, and can be installed at
field sites, for example near tar sands extraction operations.
Vertical tube reactors are capable of continuous
operation and do not require the types of high pressure
pumps and valves used by previous methods for treating
mixtures ofhydrocarbons, water and/or solids. Vertical
tube reactors are not greatly susceptible to the breakdowns
and maintenance costs associated with high pressure
pumps and valves which would be quickly abraded
by the solids present in a tar sands froth.
Methods of producing pressure in a continuous manner
by hydraulic or hydrostatic systems have been disclosed
for applications other than separation of hydrocarbons
from froths. Titmus (U.S. Pat. No. 3,853,759,
1974) and McGrew (U.S. Pat. 4,272,383, 1981) disclose
hydrostatic pressure developed in a vertical tube reactor
to be particularly useful in treating sewage. Land
(U.S. Pat. No. 3,464,885, 1969) discloses treatment of
wood chips in a vertical tube reactor. Lawless (U.S.
Pat. No. 3,606,999, 1967) is particularly directed to
liquid-gas reactions in a vertical tube reactor, including
chlorination, oxidation or hydrogenation of oil sands.
Lawless, however, does not discuss hydrocarbon separation.
In the preferred embodiment, a vertical tube reactor
for separating hydrocarbons from a tar sands froth comprises
substantially concentric downcomer and riser
conduits of sufficient height that a column of froth in
the downcomer conduit produces a hydrostatic pressure
at the bottom of the column of at least about 1000
psig. The process of this embodiment comprises continuously
flowing the froth down the downcomer conduit
and up the riser conduit. The downcomer and riser
flows are preferably in heat exchange relationship. The
flow rate of the stream is such as to maintain the stream
4,648,964
7 8'
at a treatment pressure above about 1000 psig for be- addition of diluent 18. However, regardless of the prestween
about 1 minute and about 60 minutes. While the ence or absence of additional operations and regardless
stream is at least at the treatment pressure, it is heated to ofthe type ofseparation employed, it is advantageous to
a treatment temperature above about 300· C. The perform all steps subsequent to treatment in the heat/-
treated stream which exits the riser conduit, is gravita- 5 pressure treatment zone 14 in a manner which minitionally
settled to separate the hydrocarbon fraction. mizes mixing of the treated stream. Rough handling of
Temperatures greater than the minimum temperature the treated stream which results in substantial mixing
of 300· C. and pressures greater than the minimum adversely affects the speed and completeness of separapressure
of about 1000 psig may be employed according tion. Mixing can be minimized by such measures as
to the process of this invention. Such increased temper- 10 reducing turbulence of the flow, for example, as by
atures and pressures will, for some types of feeds, such designing the post-heat/pressure treatment flow so that
as those comprising particularly viscous hydrocarbons the treated stream is conducted to the separating step in
or those with a high solids content, produce a higher a substantially laminar flow mode, or by avoiding vigordegree
ofseparation or produce a separation in a shorter ous agitation or overturning until after the desired sepaamount
of time than less severe conditions. For exam- 15 ration of constituents has occurred.
pIe, if the separation step includes a fIltration process, it Post-heat/pressure treatment handling is rendered
is preferred to conduct the heat/pressure treatment at more convenient by cooling the treated stream prior to
temperatures and pressures, and for a time sufficient to the separation step. By such cooling, it becomes possiproduce
a treated stream filtration rate of more than 30 ble to avoid vaporization of constituents of the treated
gallons/ft2/hour. 20 stream without the necessity to maintain substantially
In many applications it will be desirable to avoid superatmospheric pressures. Thus, treatment in a cooltemperatures
and/or pressures which are sufficiently ing device is particularly an advantage when postelevated
to produce certain chemical changes in the heat/pressure treatment steps will be performed at atconstituents
of the fluid. In particular, it is often desired mospheric pressure, such as gravity separation in setto
avoid or minimize coking of the hydrocarbon constit- 25 tling vessels. As discussed above, it is preferred to peruents
as, for example, when the fluid comprises a tar form at least part of the cooling of the treated stream in
sands froth and coking of the hydrocarbon values ofthe a heat exchanger 12 so as to conserve the energy supfroth
is to be avoided. Coking is particularly to be plied in the heat/pressure treatment zone 14. Altemaavoided
or minimized when the reactor is a vertical tively or additionally, cooling oftpe treated stream Can
tube reactor. When the feed stream comprises a tar 30 be accomplished by such devices as conventional tube
sands froth flotation emulsion, it is preferred to conduct and shell heat exchangers or air-cooled heat exchangthe
process at temperatures less than about 450· C. and ers.
preferably less than 415· C. and at pressures less than Speed and/or effectiveness of the separation step Can
about 3700 psig, preferably less than about 3400 psig, be optionally enhanced by addition of diluent 18. The
most preferably less than about 3000 psig. 35 useful diluent is a liquid soluble in the hydrocarbon
Although avoidance of coking places some limita- which, when mixed with the hydrocarbon, produces a
tions on the maximum treatment temperature and pres- mixture with a lower viscosity and lower density than
sure for particular applications, some advantages, such the undiluted hydrocarbon. The diluent is preferably a
as enhanced rate or effectiveness of separation, can be light hydrocarbon or a mixture of hydrocarbons boiling
obtained from employing treatment temperatures above 40 below about 250· C., and most preferably is naphtha,
the minimum temperature ofabout 300· C. and/or treat- particularly when the stream 10 is a tar sands froth
ment pressures above the minimum pressure of about emulsion. The preferred amount of naphtha added is
1000 psig. In general, it is desirable to accompany an such as to produce a naphtha to treated stream weight
increase in the treatment temperature and pressure ratio of between about 0.5 and 1, preferably between
above the minimum treatment temperature and pressure 45 about 0.75 and 1. When the process also includes a
with a decrease in the residence time, i.e. the time for cooling step, the diluent addition 18 Can precede or
which the stream is maintained above the treatment follow the cooling device 16. It is preferred to add
temperature and pressure, particularly when it is de- diluent after the treated stream has been cooled suffisired
to avoid coking. In particular, when conducting ciently to avoid thermal degradation or vaporization of
the process at a treatment temperature above about 400· 50 the diluent. In an embodiment wherein naphtha is
C. and/or a treatment pressure above about 2100 psig it added, it is preferred to add the naphtha while the
is preferred to limit the residence time to less than about treated stream feed is at a temperature above about 80·
30 minutes and most preferably to less than about 15 C. Other diluents usable with the process of the present
minutes. invention include heavy condensate and light kerosene.
The pressure created in the heat/pressure treatment 55 Diluent addition is particularly useful when the hyzone
14 can be at least partially adjusted by adding drocarbon fraction of the stream is especially viscous.
water or by otherwise adjusting the amount of water However, even in these cases the process of the present
present in the stream 10. All other factors being equal, invention can be practiced without any addition of
an increase in the weight percent of water in the stream diluent to the treated stream. Fluids with viscous hydrowill,
in general, increase the pressure achieved in the 60 carbons can be effectively treated by utilizing more
heat/pressure treatment zone 14 by producing a larger severe process conditions, i.e. higher than minimum
amount of steam during the treatment. treatment temperatures and/or pressures or longer resi-
After the heat/pressure treatment, the treated stream dence times than those effective for less viscous hydrois
in condition for gravity separation of the hydrocar- carbons.
bons from the other constituents. Optionally, separation 65 The hydrocarbon fraction of the treated stream Can
can be preceded by steps which can assist in handling or be separated by a number of means including gravity
further augment the rate or degree of separation settling, fIltration, decantation, etc. Gravity settling
achieved, such as treatment in a cooling device 16 or may be accomplished by a settling vessel 20 in FIG. 1.
4,648,964
10
and 9.0. Steam 116 is added to raise the temperature to
between 180· and 190· F. (82" to 88· C.). Sufficient
make-up water 118 is added to adjust the solids content
to about 70 percent. The conditioned pulp is sent to a
screening apparatus 120 which removes oversized material.
The screened pulp is subjected to a primary froth
flotation 122 to produce a primary froth 124 and a primary
tailings 126. The primary tailings 126 is sent to a
secondary "scavenger" froth flotation device 128 to
produce scavenger froth 130 and scavenger tailings 132.
The scavenger tailings 132 are sent to disposal 140. The
primary froth 124 and scavenger froth 130 are combined
to produce a froth feed 134. The froth feed 134 is
heated in heating zone 136. Heated froth 138 is directed
to a heat/pressure treatment zone 142, in which the
froth is heated to above about 300· C. and pressurized to
above about 1000 psig. Preferably, the pressure is produced
by the hydrostatic head of a column of the froth.
The treated stream 160 is directed to a cooling step
162 to bring the temperature of the treated stream to
about 80· C. Naphtha 164 is added in a naphtha to
treated stream weight ratio of between about 0.5 and 1.
The mixed stream 166 is directed to a gravity settler 168
where the treated stream separates in a continuous
stream process. Within the gravity settler 168, the
stream 166 is contacted with a layer of water comprising
a previously separated water fraction of tar sands
froth whereby said treated froth gravitationally separates
into a hydrocarbon fraction 170 and a solids-containing
water fraction 172. The hydrocarbon fraction
170 is continuously removed while a portion of the
water fraction 172 is continuously bled off. The water
fraction 172 is directed to a settling apparatus 174 for
separation of the solids 176 for disposal 178. The substantially
clarifIed water fraction 180 may be disposed
of or may be treated to place it in condition for recycle
to, for example, the conditioning step 112.
The following examples are provided by way ofillustration
and not by way of limitation.
9
The separation process is conducted for a period sufficient
to obtain the desired degree of separation. The
amount of separation required will, of course, depend
upon the intended use of the hydrocarbon fraction.
When, for instance, the hydrocarbon fraction is to be 5
subjected to a coking process, it is preferred that the
separation proceed to a point resulting in a hydrocarbon
fraction with a solids concentration less than 1 weight
percent and preferably less than 0.5 weight percent and,
preferably, a water concentration less than 5 weight 10
percent.
When the feed comprises a tar sands froth comprising
water and solids, settling produces a hydrocarbon phase
and a water phase. Substantially all non-hydrocarbon
solids are dispersed in the water phase. Typically, less 15
than 10 percent by weight and more preferably less than
5 percent by weight of the solids originally present in
the froth are dispersed in the separated hydrocarbon
phase.
Particularly rapid and effective solids separation has 20
been noticed in cases when the process of this invention
was applied to a tar sands froth comprising clay solids.
Without intending to be bound by any theory, it is postulated
that separation of solids from the hydrocarbon
fraction is assisted by a process wherein the elevated 25
heat/pressure treatment renders some types of solids,
particularly clay solids, hydrophiI1ic so that upon separation
of the hydrocarbon and water phases, the solids
will preferentially be dispersed in the water phase. In
some cases it may be desirable to add water to the froth 30
prior to the heat/pressure treatment to facilitate the
solids removal.
It has been found that when a tar sands froth is subjected
to the heat/pressure treatment described above,
the treated froth separates into hydrocarbon and water 35
phases substantially instantaneously. Since the solids
contained in the froth are preferentially dispersed in the
water phase, solids separation is thus also substantially
instantaneous.
When the desired degree of separation has been 40
achieved, the separated constituents such as the hydro- EXAMPLE 1
carbon phase 24 and the solids, possibly dispersed in a Two flotation froth products were obtained from a
water phase 26, are directed to their ultimate destina- tar sands extraction operation. The compositions of
tion. For example, the hydrocarbon fraction 24 can be these products is shown in Table lA. Tests 1-3 used
sent to a refIning operation such as a cracking or coking 45 froth # 1 as the feed and tests 4-9 used froth #2 as the
operation. The water and solids fraction 26 may be feed. Froth #1 had a 63.3 weight percent bitumen confurther
treated to separate the water from the solids, or tent and froth #2 had a 65.1 weight percent bitumen
to eliminate contaminants from this fraction so as to content. In each test, the product was added to a rockallow
for environmentally acceptable disposal or for ing bomb autoclave. After purging air from the system,
recycle to another step of the operation such as a froth 50 the autoclave was slowly brought to the reaction temflotation
step. perature and pressure set forth in Table lA in about 2
It has been found that when a hydrocarbonaceous hours with constant rocking. After treating the mixture
feed is treated according to the process of the present for a specifIed time (residence time), the contents were
invention, a certain amount of the 950· F.+ residual allowed to cool overnight with the rocker in motion.
fraction is converted to lower boiling materials. Other 55 After treatment, the product was diluted with naphtha
changes in the character of the hydrocarbons as a result in a 1:1 ratio and the mixture was settled at 80· C. using
of the present process include changes in the amount of a separatory funnel. Results are presented in Table IB.
Conradson Carbon present in the hydrocarbon and a Solids content of the separated hydrocarbon fraction
certain amount of gas make. When the treated stream was less than the feed solids content in every test. The
contains a substantial amount of gaseous material, such 60 variability of the settling characteristics of the froth
material can be vented by vent 22 from the settler 20 as product appears to be due to the processing steps perit
evolves. formed on the froth after thermal treatment. Vigorous
In a preferred embodiment, the solids separation pro- agitation at elevated temperatures emulsifIed the process
of this invention is applied to the froth from a tar cessed froth, encapsulating solids in the oil phase.
sands hot water extraction process. Referring now to 65 . An analysis of the 950· F.+ (510· C.+) residual con-
FIG. 2, tar sands 110 which have been mined from a tar version and Conradson Carbon content of the hydrosands
deposit are forwarded to a conditioning drum 112. carbon fraction produced by tests 2, 3, 6 and 8 was
Caustic soda 114 is added to raise the pH to between 7.5 conducted. Results are presented in Table lB. The froth
A second series of rocking bomb autoclave tests was
made on flotation froth No.2. The autoclaving procedure
was the same as that described for Example 1. Care
was taken with the autoclave product to prevent agitation
which would result in the formation ofa solids-containing
emulsion. The treated froth was removed from
the autoclave at 80· C., gently mixed with naphtha, and
placed in a 4 inch diameter gravity settler. Hot water
had previously been added to the settler to simulate
4,648,964
Froth #2 Particle Size Distribution
micron wt %
11
feeds and the product of tests 3 and 8 were subjected to
coking at 500· C. in a laboratory-scale coker. Yields
from the laboratory scale coker for these tests are presented
in Table lC.
Differential thermal analyses (DTA) of the product 5
solids from tests 5 and 7 and from untreated froth were
performed at a heating rate of 20· C. per minute in
nitrogen. The results are shown in FIG. 3. As can be
seen, the clays in the unprocessed froth begin to lose
water ofhydration at about 400· C. Test 5 gave a similar 10
DTA curve, and had poor settling and f1ltration characteristics.
In test 7, the clay solids were partially dehydrated
as shown by a lack of a DTA peak at 400· C.
This test showed good settling and f1ltration, suggesting
that the clays in the bitumen are made hydrophillic with 15
thermal treatment due to the loss of water in the clays at
400· C.
A particle size distribution analysis was conducted
for the solids from froth #2. The results are presented in
Table 10. 20
TABLEIA
mesh
plus 100
100 by 200
200 by 325
minus 325
12
TABLE 10
plus 149
149 by 74
74 by 44
minus 44
EXAMPLE 2
0.8
11.8
20.2
67.2
Froth Treatment Tests for
Removal of Water and Solids
Conditions Solids (wt. %) Water (wt. %) Asphaltenes (wt. %)
Residence Start End Separated Separated Separated
T.est Time Temp. Pressure Pressure Untreated Hydrocarbon Untreated Hydrocarbon Untreated Hydrocarbon
No. Minutes ·C. psig Feed Fraction Fraction Feed Fraction Feed Fraction
I 60 350 2250 2250 3.1 1.7 33.6 15.0 16.6 13.3
2 IS 400 2250 2275 3.1 0.5 26 2.1 16.6 12.3
3 60 400 1800 2000 3.1 1.5 21 0.7 16.6 12.5
4 60 400 1350 1550 7.9 4.4 10 6.7 15.7 15.3
5 60 400 1700 1700 7.9 6.9 27 4.8 15.7 14.4
6 60 400 2600 2700 7.9 4.3 27 27.1 15.7 8.7
7 IS 400 2600 2670 7.9 4.0 27 20.2 15.7 13.5
8 0 400 2650 2650 7.9 5.9 27 24.5 15.7 14.0
9 IS 425 3100 3100 7.9 2.5 27 31.3 15.7 22.9
13.4
20.6
14.7
II.O
Calculated
Whole Oil
Con Carbon,
from 950· F.+
Data, Wt %
19.3
28.9
30.3
17.4
Con
Carbon of,
950· F.+,
Weight %
14.1
TABLE 1B
13.0 ± 0.2
11.5
18.4
Direct
Con Carbon,
of Whole Oil
Weight %
Conradson Carbons of Oil Fractions
o
15.5
-2.6
30.6
9.6
Residual
Conversion
in Treatment
Weight %
Laboratory Scale Coker Yields
Test Residual Basis Whole Oil Basis
Number Coke Oil Gas Coke Oil Gas
Froth #1 19.4 68.8 II.8 12.1 80.5 7.4
3 24.2 65.2 10.6 17.3 75.1 7.6
Froth #2 17.2 69.8 13.0 12.0 78.9 9.1
8 17.5 70.1 12.4 11.0 81.2 7.8
feed
2
3
6
8
Test
No.
continuous operation. The processing conditions and
results for these tests are presented in Table 2A. For
comparison, analysis is also given in Table 2A for froth
40 which was diluted and settled, but not subjected to a
heat/pressure treatment. Solids content of the hydrocarbon
fraction was consistently less than the solids
content of either the feed or diluted but untreated froth.
An analysis of the 950· F.+ (510· C.+) residual con-
45 version and the Conradson Carbon content of the oil
fraction produced by some of these tests was conducted.
Results are presented in Table 2B. The product
oftests 11, 12 and 16 were subjected to coking at 500· C.
in a laboratory-scale coker. Yields for these tests are
TABLE IC 50 presented in Table 2B.
------------------- Differential thermal analyses (DTA) were performed
on solids from tests 11 through 14 at a heating rate of
20· C. per minute in nitrogen. The results are shown in
FIG. 4. These curves show that the solids drastically
55 change with increasing processing temperature and
residence time. The solids from the raw froth shows to
large endotherms at 450· and 550· C. At processing
temperatures of 250· to 300° C., the fIrst of these endotherm
nearly disappeared. Above 300° C., the fIrst endotherm
vanished.
TABLE2A
Froth Treatment Batch Autoclave Tests
Reaction Conditions Dilution Product
Test pressure (NaphthalFroth Hydrocarbon Loss Oil Analysis! % Solids
No. Temp, ·C. psig Time, min WtlWt (Wt % of Total) % Water % Solids Removed
Froth No.2 1:1 1.2 2.1 1.74 87.2
10 400 2900 IS 1:1 1.9 0.1 0.38 99.7
II 350 2150 IS 1:1 0.7 0.4 2.27 98.3
13
4,648,964
14
TABLE 2A-continued
Froth Treatment Batch Autoclave Tests
Reaction Conditions Dilution Product
Test pressure (NaphthalFroth Hydrocarbon Loss Oil Analysis! % Solids
No. Temp, ·C. psig Time, min WtlWt (Wt % of Total) % Water % Solids Removed
12 300 1460 15 1:1 0.6 0.1 \.98 98.2
13 400 2850 15 0.5:1 2.9 0.4 1.30 98.8
14 250 770 60 1:1 3.0 0.2 0.64 9\.2
15 400 3000 0 0.5:1 4.8 0.7 0.40 98.9
162 400 3300 15 0.5:1 ( \.7 0.15 98.1
172 400 3710 15 0.5:1
1Analysis includes naphtha.
2The products of tests !6 and 17 were combined for analysis.
IThe products of tests 16 and 17 were combined for analysis.
TABLE 3
Froth Treatment Micro-Tube Tests
Froth #2, Initial Solids: 7.9%
Press. Time Sample Naphtha %
Test Temp. psig (Min- Weight, Weight, Solids
No. ·C. (±200 psig) utes) grams grams inHC
18 400 3500 0 10.04 10.03 1.25
19 400 3500 I 10.51 8.48 0.99
20 400 3500 5 10.59 7.01 0.75
21 400 3500 10 10.66 7.22 0.97
22 400 3500 15 10.18 8.30 0.64
23 400 3500 30 11.07 7.06 1.28
EXAMPLE 4
35
30
Differential thermal analyses (DTA) were performed
on solids from the micro-tube tests at a heating rate of
20· C. per minute in nitrogen. The results are shown in
FIG. 5. The raw froth DTA curve shows two large
20 endotherms at 450· and 500· C. The fIrst endotherm
disappears at a residence time of 5 minutes or greater.
These curves suggest that the solids become hydrophillic
due to the evolution of water from the clay minerals
in the solids.
16.9
14.1
14.3
13.0
Calculated
Whole Oil
Con Carbon,
from 950· F. +
Data, Wt %
28.2
18.1
20.5
23.9
Con
Carbon of,
950· F.+,
Weight %
12.9
14.0
13.5
12.4
Direct
Con Carbon,
of Whole Oil
Weight %
17.2 69.8 13.0 12.0 78.9 9.1
15.8 7\.4 12.8 12.4 77.5 10.1
17.7 71.4 10.9 12.5 80.0 7.6
20.3 7\.6 8.1 11.1 84.5 4.4
Laboratory Scale Coker Yields
Residual Basis Whole Oil Basis
Coke Oil Gas Coke Oil Gas
TABLE2B
TABLE2C
14.3
-13.0
0.0
2\.6
Conradson Carbons of Oil Fractions
Residual
Conversion
in
Treatment
Weight %
Test
Number
Froth #2
II
12
16/171
Test
No.
10
II
12
16/171
1The products of tests 16 and 17 were combined for analysis.
EXAMPLE 3 An oil-water-solids emulsion was prepared by mixing
In order to test the procedure for heating and cooling 40 a heavy oil from the Cold Lake area with water. In tests
. times shorter than those possible with the rocking bomb RBT 2 and RBT 3, -200 mesh silica sand was added to
autoclave, a series of tests was made in one-half inch this mixture. In tests RBT 4 and RBT 5, solids containinside
diameter tubes heated by a fluidized sand bed. ing clays previously derived from a froth flotation prod-
The tubes were fIlled half full with froth No.2 and were 45 uct and with the size distribution shown in Table ID
sealed. The tubes were immersed in the hot fluid bed, were added. The heat-pressure treatment was perand
brought to the treatment temperature in about 3 formed in the manner described in Example 1. After
minutes. The tubes were maintained at the treatment cooling to 80· C., the product was removed. In these
temperatures and pressures for the residence times indi- tests, there was no addition of naphtha to the product
cated in Table 3. After this residence time, the tubes 50 Hot (~bo~t 90· C.) water was placed in a settler and the
were quenched in water to achieve a cooling time of hot oil IlllXture was slowly poured on the water. The
about two minutes. Following the quenching naphtha settler rake was turned on gently agitating the contents
was added to the product, and the mixture was heated of the separator. The solids and water separated from
to 80· C. The water and solids were separated in a the oil, with the solids dropping to the bottom of the
separat~ry funnel which contained additional water. 55 separator, ~d the water mixing into the aqueous phase..
The solIds content of the hydrocarbon was determined After 30 mmutes, the three phases were collected sepaby
washing with benzene. The reaction conditions and rately. The solids and water content of the underflow
results for these tests are presented in Table 3. Pressure and overflow phases were analyzed The test conditions
was calculated from the treatment temperature, tube and results are presented in Table 4. Settler overflow
volume and fluid volume. 60 had a solids content consistently less than that of the
feed.
TABLE 4
Separation of Solids-Oil-Water Mixtures
Temp Press Time Feed Analysis, % Product Analysis, % Distribution %
Test Solid ·C. psi min Oil Water Solids Product Oil Water Solids Oil Solids
RBT-2 Sand 400 2550 15 65.5 24.6 9.9 Overflow 95.8 3.8 0.4 92.9 6.3
Underflow 41.3 24.7 34.0 7.1 93.7
RBT-3 Sand 415 2800 15 64.9 25.1 . 10.0 Overflow 85.0 13.5 1.5 98.6 34.0
15
4,648,964
16
TABLE 4-continued
Separation of Solids-Oil-Water Mixtures
Temp Press Time Feed Analysis, % Product Analysis, % Distribution %
Test Solid ·C. psi min Oil Water Solids Product Oil Water Solids Oil Solids
Underflow 24.9 16.2 58.9 1.4 66.0
RBT-4 Clay 400 2680 IS 74.0 18.6 7.4 Overflow 98.6 0.8 0.6 99.0 18.0
Underflow 25.2 9.0 65.8 1.0 82.0
RBT-5 Clay 415 2670 IS 66.8 25.2 7.9 Overflow 78.7 20.4 0.9 97.6 11.2
Underflow 18.6 13.6 67.8 2.4 88.8
TABLE 5
EXAMPLE 6
EXAMPLE 7
1800 16.2 3.9 1.11 0.39
3350 25.6 9.7 1.11 0.85
2250 25.6 3.4 1.11 0.58
Low·Solids (Oil·Water Emulsion) Tests
Press. Water (%) Solids (%)
(psig) Feed Product Feed Product
400
415
360
Temp.
rc.)
One untreated froth and one sample of froth treated
according to the process of the present invention were
contacted with water to simulate separation in a con- 35
tinuous-operation settler. Each sample was poured into
a 1500 ml beaker containing 800 ml of 80° C. water. The
untreated froth used was froth #2. Upon contact of
untreated froth with water, there was substantially no
separation of the hydrocarbon phase from the water 40
and/or solids component of the froth. The one sample
of froth treated according to the process of the present
invention was treated froths from test no. 16. Upon
contact with the water in the beaker, the oil and water
phases of the treated froths 16 separated substantially 45
instantaneously with the oil phase residing above the
water phase. In less than 15 seconds, substantially all the
solids had settled to the bottom of the water phase.
EXAMPLE 5 temperature and pressure with about a 25 weight per-
A low-solids (1.11 percent) oil-water emulsion was 15 cent steam and about 2 weight percent gas content.
prepared by mixing oil from the Huntington Beach area The froth feed enters the reactor string and travels
with water. The mixture was treated in an autoclave downward through the annular portion of the coaxial
according to the procedures described in Example 1. pipe downcomer-riser system. The froth is heated
The tests conditions and results are presented in Table through indirect heat exchange with treated froth
5. Product solids content was consistently less than that 20 which is traveling upward in the center riser pipe. The
of the feed. froth stream is heated to within 50° F. (28° C.) of the
treatment temperature before it enters the outer reactor
pipe. Supplemental heat is supplied by means of indirect
heat exchange with a high-temperature pressure-bal-
25 ance fluid which occupies the void volume surrounding
the reactor string. With a 50° F. (28° C.) approach temperature
at the hot end of the riser downcomer heat
exchanger, the system heat duty is 12.75 million
BTU/hr. A heat exchange fluid flow rate of 1,600 gal/-
3D min is required to supply this heat duty at a hot fluidreactor
approach temperature of 25° C. The heat transfer
fluid is circulated via a 3 in. diameter pipe using a 50
psi high-temperature centrifugal pump. A gas cap is
maintained above the heat exchange fluid to provide the
primary pressure drive forced to overcome the pressure
head. A small air-compressor system is provided for this
purpose. A surface gas-fired tube heater rated at 15
million BTU/hr is used to heat the heat exchange fluid.
The feed stream which has been heated to about 375°
C. and whose pressure has increased from an inlet pressure
of 50 psi to a pressure of 2000 psi enters the outer
reactor pipe. The temperature ofthe stream is increased
to a treatment temperature above about 400° C. The
pressure is increased to a treatment pressure above
about 2000 psi. The stream passes through the outer
reactor pipe and into the inner reactor pipe at a flow
rate which provides a total reactor residence time of
about 15 minutes at a stream feed rate of 10,000 barrels
of bitumen per day. As the treated stream passes out of
50 the inner reactor pipe and into the riser pipe, cooling of
A tar sands froth is passed through a separation pro- the treated stream is initiated by heat exchange contact
cess to separate the hydrocarbon fraction. The process- with the incoming froth feed stream. The temperature
ing unit is located in a vertical shaft having a depth of and pressure of the treated stream decreases as it flows
about 7,200 ft and a fInished casing diameter of 24 in. upward from the reactor zone. When the treated stream
Suspended in the vertical shaft is the reactor string 55 exits the riser pipe the temperature is about 150° C. and
which consists of two coaxially oriented pipes which the pressure is about 250 psi.
comprise a downcomer-riser system. Attached to the Upon leaving the reactor system the treated stream is
bottom of the downcomer-riser system is the reactor fed into a gravity settler in which the hydrocarbon
which consists of an inner reactor pipe and an outer fraction, comprising less than 1 weight percent solids
reactor pipe. The downcomer pipe is a 16 in. pipe 5,000 60 and less than 5 weight percent water, is separated from
ft in length. The riser pipe which is located inside the the treated stream.
downcomer is 10 in. diameter pipe 5,000 ft in length. Although the foregoing invention has been described
The outer reactor pipe has a 20 in. diameter and is 2,000 in some detail by way of illustration and example for
ft in length. The inner reactor pipe, which is located purposes of clarity and understanding, it will be obvious
within the outer reactor pipe, is 2,000 ft in length with 65 that certain changes and modifications may be practiced
a 10 in. diameter. The inner and outer reactor pipes within the scope of the invention, as limited only by the
together comprise a reactor volume of 4,360 cubic ft scope of the appended claims.
which provides a 15 minute residence time at reaction What is claimed is:
4,648,964
50
17
1. A process suitable for separating the hydrocarbon
fraction from a fluid stream comprising a tar sands froth
comprising:
pressurizing said stream to a treatment pressure above
about 1000 psig and heating said stream to a treat- 5
ment temperature above about 300° C., said pressurizing
and heating being effective to produce a
treated stream capable of gravity separation of the
hydrocarbon fraction;
reducing the pressure on said treated stream to pro- 10
duce a separation pressure which is less than said
treatment pressure; and separating said hydrocarbon
fraction from said treated stream at said separation
pressure.
2. The process of claim 1 wherein said separating step 15
comprises gravitationally settling said treated stream.
3. The process of claim 2 wherein said gravitational
settling occurs substantially instantaneously.
4. The process of claim 1 wherein said froth comprises
between about 15 weight percent and about 35 20
weight percent water and between about 65 weight
percent and about 85 weight percent hydrocarbons.
5. The process of claim 1 wherein said froth comprises
more than about 1 weight percent solids and 25
wherein said separated hydrocarbon fraction comprises
less than about 1 weight percent solids.
6. The process of claim 5 wherein said separated
hydrocarbon fraction comprises less than about 0.5
weight percent solids. 30
7. The process of claim 1 further comprising adding a
diluent to said treated stream.
8. The process of claim 7 wherein said diluent is
added at a treated stream temperature above about 80°
C ~
9. The process of claim 7 wherein said diluent comprises
naphtha.
10. The process of claim 9 wherein sufficient naphtha
is added to produce a naphtha to treated stream weight
ratio of between about 0.5 and about 1. 40
11. The process of claim 10 wherein said ratio is be-
-, tween about 0.75 and about 1.
12. The process of claim 1 further comprising conducting
said treated stream to said separating step in a
substantially laminar flow mode. 45
13. The process of claim 1 wherein said pressure is
produced by the hydrostatic head of a column of said
fluid stream.
14. The process of claim 1 further comprising cooling
said treated stream.
15. The process of claim 1 wherein said heating step
comprises placing said fluid in heat exchange relationship
with said treated stream.
16. The process of claim 1 wherein said treatment
pressure is between about 1800 psig and about 3700 55
psig.
17. The process of claim 1 wherein said treatment
pressure is between about 2100 psig and 3000 psig.
18. The process of claim 1 wherein said treatment
temperature is above about 350° C. 60
19. The process of claim 1 wherein said treatment
temperature is between about 400° C. and about 450° C.
20. The process of claim 1 wherein said treatment
temperature is less than about 415° C.
21. The process of claim 1 further comprising main- 65
taining said fluid stream at said treatment temperature
and said treatment pressure for a time period between
about 1 and about 60 minutes.
18
22. The process of claim 21 wherein said period is
between about 1 minute and about 30 minutes.
23. The process of claim 21 wherein said period is
between about 1 minute and about 15 minutes.
24. A process suitable for separating the hydrocarbon
fraction from a tar sands froth comprising:
pressurizing a fluid stream comprising a tar sands
froth to a treatment pressure between about 1800
psig and 3700 psig and heating said stream to a
treatment temperature above about 350° C.;
maintaining said fluid stream at said treatment temperature
and said treatment pressure for a time
period between about 1 minute and about 30 minutes,
said pressurizing and heating being effective
to produce a treated stream capable of gravity
separation of the hydrocarbon fraction;
reducing the pressure on said treated stream to produce
a separation pressure which is less than said
treatment pressure;
separating said hydrocarbon fraction from said
treated stream at said separation pressure.
25. The process of claim 24 wherein:
said treatment temperature is between about 400° C.
and about 450° C.;
said treatment pressure is between about 2100 psig
and 3000 psig; and
said period is between about 1 minute and about 15
minutes.
26. In a process for extracting hydrocarbon values
from tar sands comprising forming a pulp of tar sands
with steam, caustic soda and makeup water, subjecting
said pulp to a froth flotation operation, removing the
froth fraction produced by said froth flotation operation,
and recovering hydrocarbons from said froth fraction,
the improvement comprising performing said recovering
of hydrocarbons by a process comprising:
heating the froth above about 300° C. at a treatment
pressure above about 1000 psig, said heating at said
treatment pressure being effective to produce a
treated froth capable of gravity separation of the
hydrocarbon fraction;
reducing the pressure on said treated froth to produce
a separation pressure which is less than said treatment
pressure; and
separating a hydrocarbon fraction from said treated
froth at said separation pressure.
27. The process of claim 26 wherein said separating
step comprises:
cooling said treated froth to above about 80° C.;
adding diluent to said treated froth;
gravity settling said treated froth to produce a hydrocarbon
fraction and a water fraction; and
separating said hydrocarbon fraction from said water
fraction.
28. The process of claim 27 wherein said diluent is
naphtha.
29. The process of claim 26 wherein said froth comprises
more than about 1 weight percent solids and
wherein said separated hydrocarbon fraction comprises
less than about 1 weight percent solids.
30. The process of claim 26 wherein said separating
step is a continuous stream process comprising:
contacting said treated froth with a layer of water
which comprises a previously separated water
fraction of tar sands froth;
gravitationally separating said treated froth into a
hydrocarbon fraction and a solids-containing water
fraction; and
19
continuously removing said hydrocarbon fraction
and said water fraction.
31. The process of claim 26 wherein said pressure is
provided by the hydrostatic head of a column of said 5
froth.
32. A process suitable for separating the hydrocarbon
fraction from a fluid stream comprising a tar sands froth
comprising:
10
15
20
25
30
35
40
45
50
55
60
65
20
a continuous flow treatment including substantially
continuously pressurizing said stream to a treatment
pressure above about 1000 psig and heating
said stream to a treatment temperature above about
300· C.'to produce a treated stream; and
separating said hydrocarbon fraction from said
treated stream at a pressure less than said treatment
pressure. • • • • •