4,648,964 Separation of hydrocarbons from tar sands froth

Patent Number/Link:

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

10 16

14 24

Fig.1 26

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170

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u.s. Patent Mar. 10, 1987 Sheet 2 of4 4,648,964'

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TEMPERATURE,oC

u.s. Patent Mar. 10, 1987 Sheet 3 of4 4,648,964

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TEMPERATURE, OC

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

FIELD OF THE INVENTION

BACKGROUND OF THE INVENTION

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

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

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

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-

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

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.

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 %

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

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

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

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

4,648,964

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

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

Treatment

Weight %

Test

Number

Froth #2

16/171

Test

No.

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

4,648,964

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

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.

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

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:

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. • • • • •