Note: Descriptions are shown in the official language in which they were submitted.
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The present invention relates to methods for fluidi-
fying heavy hydrocarbons present in oil sand material, whereby
the high-visco~ity hydrocarbons may be recovered. of chief
interest for the purpo~e of the invention is the oil sand found
in Alberta. This oil sand contains high-viscosity hydrocarbons
cf high average molecular weight, typically in excess of about
600 or 700, in intimate admixture with finely divided, solid,
inorganic particles and other impurities, often together with
substantial amounts of water and quantities of natural gases.
Deposits of comparable minerals containing high-viscosity, heavy
hydrocarbons are also found in other localities, and as with the
Albertan oil sand, recovery of hydrocarbons from deposits of
the~e minerals through a well by normal petroleum recovery methods
i8 difficult or impracticable. The term "oil sand materials" is
to be understood to include all such minerals.
In the natural state, and especially where the deposits
are underground, these oil sand materials exist at low temperatures.
In large areas of the underground Alberta oil sand deposits, for
example, ths underground temperature i8 usually around 40F. At
these temperature~ the hydrocarbons have a thick, semi-solid
con~istency and they are substantially immobile.
Prior proposals for recovering hydrocarbons from such
materials have largely relied on applying heat to the oil sand
so that the hydrocarbons become less viscous and can be made to
flow. However, the heating operation expends an unduly high
proportion of the recoverable energy.
It has now been found that a considerable reduction in
the viscosity of the hydrocarbon, often to a point where the
hydrocarbon flows like water, can be obtained without needing to
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heat the oil sand material, by contacting the material with a
pressurised solvent gas at a temperature below its critical
temperature and not substantially above the ambient temperature
of the material, and under a pressure close to and not
substantially above the saturation vapour pressure at the
temperature of the oil sand material. When a pure gas is
employed, the most rapid viscosity reductions are obtained when
the gas is at a pressure equal to, or slightly less than the
saturation vapour pressure of the gas at the ambient temperature.
10 At these conditions, the gas will be close to the liquid state,
and in the preferred form the pure gas is applied at a pressure
such that at the temperature of the oil sand material the
solvent gas will be in the gaseous state but close to the line
of transition between the gaseous and liquid state.
When mixtures of gases containing one or more solvent
gases are employed, it is not necessary for the partial pressure
of the solvent gas to be close to or above the saturation vapour
pressure at the oil sand temperature. In such a case, however,
when a rapid viscosity reduction is obtained it has been
20 observed that the total pressure of the gas mixture is not
substantially less than the saturation vapour pressure of the
solvent gas at the temperature of the oil sand material.
By the term "solvent gas" we refer to normally gaseous
materials which are miscible with and dissolve in naturally-
occurring high-viscosity hydrocarbons. Examples include carbon s
dioxide, the lower alkanes e.g. methane, ethane, propane, etc.,
and alkenes such as ethylene, propylene, and the isomeric
butenes. Of these, carbon dioxide and ethane are preferred.
Carbon dioxide is generally available at reasonably low cost
and ethane may be
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available at low cost depending on the refining processes sub-
sequently applied to the recovered hydroc æbon. Both of these
gases have excellent viscosity-reducing effects. Under the more
usual temperature conditions, the critical temperature of methane
is exceeded and so it is impossible to bring methane close to
the liquefaction point. Thus, the use of methane is in most
circumstances inconvenient.
The higher molecular weight of alkanes higher than
ethane can be disadvantageous since the degree of viscosity
reduction depends on the molar concentration of the dissolved
gas in the hydrocarbon, and moreover, as the higher alkanes
condense easily to a liquid, large amounts of the gas will tend
to condense out as a liquid during injection into uhderground
deposits, because of the low initial temperature of the deposits,
without coming into effective contact with the hydrocarbons
contained in the deposits.
In the preforred practice, the solvent gases applied
to the oil sand consist substantially wholly of carbon dioxide,
ethane, or mixture of carbon dioxide and ethane. These solvent
gases may be diluted with other gases such as methane, propane,
butane, and liquefied petroleum gas mixtures but greater total
quantities of gas may then have to be applied for more prolonged
periods in order to obtain a comparable fluidity of the hydro-
carbon, and in the preferred form the gas applied to the oil sand
material contains at least 10% by volume of ethane or carbon
dioxide.
In the normal practice of this invention, the solvent
gases are contacted with the oil sand material at ambient
A temperatures normally in the range of 400F to 85F, and under a
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pressure suitable for the oil sand material to be treated,
until the viscosity of the hydrocarbon is reduced to the
point where the hydrocarbon is flowable. The solvent gas
should be at a pressure not less than about 95% of the
saturation vapour pressure of the gas at the temperature of the
oil sand. At pressures substantially less than the saturation
vapour pressure at deposit temperatures, the effects of the
solvent gas may be much slower than when the gas pressure is
raised to close to the liquefaction point. The applied pressure
of the solvent gas is controlled so that it is not substantially
above the saturation vapour pressure at the relevant
temperature, so that the process is conducted substantially
without any formation of a liquefied solvent gas phase, as this
results in the condensation underground of larger amounts of gas
than are required for adequate viscosity reduction. The
reduced-viscosity hydrocarbon can be withdrawn as a fluid from
the oil sand under pressure sufficient to maintain the content
of the dissolved gas in the hydrocarbon. The recovered hydro- ;
carbon may then be treated to separate the dissolved gases,
which can be recycled.
This method may be applied to oil sand in its native
state either in underground deposits or at the surface to mined
material.
In the treatment of oil sand above ground, the method
can be applied directly to the mineral material at ambient
temperature and under quiescent conditions without needing to
preheat or comminute the material. In the treatment of mined
material it is, however, necessary to confine the material
within pressure vessels capable of withstanding the applied
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pressure of the solvent gases, while in in situ underground
operation, the natural deposit pressures or the relatively
low porosity of the oil sand due to its hydrocarbon content
can serve to confine the solvents and maintain the required
pressures.
In underground treatments, a single or multiple
well boring may ~e employed. A single well may serve both as
an injection well and a production well. The solvent gases are
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initially in~ected under high pressure for a period of time,
which in most cases extends to several days or weeks, sufficent
to fluidify an extensive volume of the hydrocarbon. Thereafter,
production through the well may be commenced, the pressure at
the well head being controlled so as to be at a sufficiently
high level to maintain in the produced hydrocarbon a concentration
of dissolved solvent gases adequate to preserve the low-viscosity
fluid state of the hydrocarbon. In the treatment of certain ~ -
deposits it may be necessary to employ a deep well pump to main-
tain adequate pressure on the hydrocarbon in its upward delivery
path.
In the preferred practice, however, mutually distant
injection and production wells are employed. An example is shown
in the accompanying drawings.
Figure 1 illustrates in schematic form an example of the
practice o~ this invention applied to an underground oil sand
deposit.
Figures 2, 3, and 4 are graphs plotting visco~ity
against timo or a heavy hydrocarbon in contact with pressurised
solvent gases.
Referring to Figure 1, an oil sand deposit 1, or other
comparable deposit, i8 penetrated by an injection well 2 and a
production well 3, both extending deeply into the deposit. A gas
storage tank 4 containing liquid solvent ga~ is connected to the
injection well through a steam-heated heat exchanger 6, having a
steam inlet 7, and through a line 8 connecting the heat exchanger
6 to the injection well. A pump 9 is also provided, connectable
directly between the well and the tank 4 through a line 11, whereby
liquid gas can be ~upplied direct to the well 2.
An outlet line 12 connects the production well head to
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a pressure controller 13 and a flash evaporator 14. The
evaporator 14 is heated by a steam line 15. The evaporator 14
has outlets 16 and 17 for evaporated solvent gas and for the
hydrocarbon residue, respectively.
Provision is made for recycling the separated solvent
gas through a cooling heat exchanger 18, a compressor and inter-
cooler 19, and a further cooling heat exchanger 21, each having
cooling water inlets and outlets 22 and 23.
In starting-up the recovery operation, the solvent gas
is initially passed to the injection well with the production well
clo~ed. The solvent gas may be supplied in the gaseous form from
the heat exchanger 6 or directly from the compressor 19 through a
line 24,-or in the liquid form pumped by the pump 9 from the
storage tank 4. The supply is continued until an extensive under-
ground volume of the hydrocarbon has been permeated and saturated
with the solvent. The initial injection period may last for
several day~. Thereafter, with the injection of solvent gas
through well 2 continuing, the production well is opened to allow
outflow of the fluidified hydrocarbon through the line 12. In
production, the pressure in the line 12 is controlled by regulation
of the pressure controller 13 so as to maintain an adequate
viqcosity-reducing content of dissolved gas in the produced hydro-
carbon. where the vertical rise to the surface is great, a deep
well pump in the production well can be employed to maintain the
required pressure on the fluidified hydrocarbon and prevent the
evolution of gas in the pipe line with consequent substantial
viscosity increase.
Where the underground pressure is inadequate to propel
the hydrocarbon from the depo~it, a displacement medium, e.g. a
displacement water drive or other inert fluid drive may be used
to move the hydrocarbon to the production well.
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In order to facilitate the initial permeation of thesolvent gases into the underground formation~, and to speed the
flow of the fluidified hydrocarbons underground, it is normally
preferred to establish a pervious or increased porosity under-
ground communication path between the injection and production
wells before commencing the injection of the solvent gas. This
can be readily accomplished by conventional procedure~, e.g.
hydraulic fracturing.
The production of low-viscosity hydrocarbon is delivered
to the flash evaporator 14 where, after preheating typically to
a temperature of about 150 to 200F, the hydrocarbon is rapidly
depressurised, and under the heating supplied from the steam line
15 the solvent gas is flashed off to the line 16. The hydrocarbon
i8 heated within the evaporator so that it is maintained in a
flowable state and is withdrawn from the production outlet 17 as
refinable product.
The recycled gas is compre~sed and cooled to the injection
temperature and passed to the injection well 2 along line 24.
Altornatively, all or part of the separated ga~ is cooled and is
liquofied at the heat exchanger 21 and returned to the storage 4.
An auxiliary supply of the solvent gas is fed as necessary from a
further solvent gas storage tank 25, to make up for any gas
losses from the system.
In typical operating conditions, the oil sand or other
viscous hydrocarbon deposit may lie beneath an overburden of depth -;
in the range of from several hundred feet to several thousand feet.
of the known A~berta oil sand depo-~its, for example, over 90~ lies
deeper than 200 feet. Such deposits exist at temperature~ greatly
less than 85F, typically less than about 60F, and temperatures
of about 40F are mo~t usual.
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The natural or applied deposit pressures may range
up to about 1000 psia depending on their depth and at these
pressures, the viscosity of the hydrocarbon can be reduced by
dissolution of the solvent gas to the point where the applied
pressure is adequate to propel it from the injection well to the
production well. In some instances, however, a driving force
of increased pressure over the natural pressure may have to be
applied to cause the hydrocarbon to flow.
When the solvent gases are injected through the
injection well in the gaseous form at pressures and temperatures
such that they are close to the liquefaction point, once
equilibrium conditions are reached the gases dissolve in the
hydrocarbon direct from the gaseous form. However, until
equilibrium conditions are reached, in the initial injection
and at relatively cooler regions of the underground deposit, the
solvent gases can condense as a liquid on cooler mineral material
in the underground formation. As a result of release of latent
heat, the mineral material becomes warmed as the solvent gas
condenses, and under continuing injection the gas will pass
through the underground deposit and effect a vigorous
dissolving or condensing action on fresh areas of the deposit.
In this manner, the possibility of the solvent gases
by-passing the hydrocarbon and flowing directly to the
production well as free gas can be reduced. By way of an
example, it can be mentioned that in the case of underground
deposits at temperatures of about 40F to about 85F, a typical
solvent gas such as ethane or carbon dioxide may be supplied
in a state close to its liquefaction point at temperatures less
than the critical temperature of from about 40F and 85F and
at corresponding pressures of from about 385 psia to 648 psia
in the case of ethane and 570 psia to 1000 psia in the case
of carbon dioxide, the gas
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conden~ing out as a liquid on contact with the cooler mineral
material. In this manner, the condensed gas is brought into
intLmate dissolving contact with the mineral material, and -
increased operating efficiency is obtained, without any, or any
significant amount of, free gas being produced at the production
well. As a result of the underground condensation of the gases,
the underground deposits will be warmed, thus contributing
further to the viscosity reduction of the hydrocarbon.
Some natural gas may be recovered along with the
fluidiæed hydrocarbon withdrawn from the production well, and -
the recovered gas can be recycled to the system, thus at lea~t
partially compensating for gases lost underground and avoiding
or reducing the need to make up for gas losses by feeding
auxiliary solvent gas to the system.
In examples of typical conditions, the solvent gases
supplied through the injection well 1 may be at 250F to 90F
and at a pressure of 500 psia to 1000 psia. The hydrocarbon
recovered through the line 12 from the production well 2 may
bo at 300F to 60F and a pre~sure in the range of 400 to 1000
psia. In separating the solvent gases at the flaqh evaporator,
the hydrocarbon may be raised to temperature~ in the range of
150F to 200F, prior to and ~ubsequent to the pressure being
reduced to 0 to 55 psia.
Figures 2 to 4 illustrate examples of the viscosity
roductions that can be obtained by applying the solvent gases
to a bituminous hydrocarbon obtained as an extract from oil
sand material.
The hydrocarbon was maintained in a pressure ves~el
cooled to below room temperature, the so1vent gase~ being
contacted with the hydrocarbon at the pressures indicated and
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at a temperature of about 57F in the example of Figure 2,
50F for Figure 3 and about 540F for Figure 4. The
viscosities were compared at intervals over the periods
indicated by recording the amperage demand drawn by a constant-
voltage motor for driving an agitator immersed in the hydro-
carbon at a given speed.
It should be noted that under the conditions of
Figure 2, the ethane is under pressure greater than its
~aturation vapour pressure at the temperature of the hydro-
carbon.
By way of comparison Figure 2 also shows theviscosities obtained when the hydrocarbon is heated to elevated
tempePature, and also the viscosity with the agitator immersed
in water.
Figure 3 shows as a comparison the viscosity of the
hydrocarbon heated to 54.8-C and also the viscosity value
obtained with the agitator in water. under the conditions of
pressure of 500 to 510 psig of Figure 3, the carbon dioxide is
at a state just outside the liquidus of the carbon dioxide
phase diagram, i.e. it i8 under a pressure slightly less than
its saturation vapour pressure at the temperature of the
hydrocarbon.
In Figure 4, pure compressed methane was applied
initially, and at the temperature of the hydrocarbon, the
methane is above its critical temperature. As can be seen,
only a very slow rate of viscosity reduction was obtained. on - -
introducing C02 in a quantity to give an approximately 90% CH4,
10% C02 volume mixture, the viscosity immediately dropped
sharply to a value comparable with the viscosity of water.
The partial pressure of the C02 is considerably less than its
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saturation vapour pressure at the temperature of the hydro-
carbon. It will be observed that the total gas pressure is
greater than the saturation vapour pressure of C02 at this
temperature.
In an example cf viscosity reduction using ethane at
pressures lower than those employed in Figure 2, a sample of
the hydrocarbon was ~ooled to ~2-F and ethane at a pressure of
325 psig was contacted with the hydrocarbon. In measurements
of the agitator amperage demand, the amperage continued to fall
10 by 18% during the period from 10 min~tes after the addition of ~ -
the ethane until 21 minutes after the addition of the ethane.
Under the conditions of this example the ethane pressure is
approximately 6% fielow its saturation vapour pressure at 420P.
In three further examples, in order to further
demonstrate the fluidification which is achieved, oil sands were
treated with carbon dioxide or ethane at pressures in equilibrium
with the respective liquefied gases at the temperatures concerned.
Firstly, a sample of Albertan oil sand was compacted
over a porous bed of inert particulate material and was subjected
isostatically to a pressure 0~ from 725 to 865 psig of C02 for
101 hours at temperature~ in the range 66 to 72F. Fluidified ~!.
bitumen flowed from the oil sand into the porous bed. The porous
bed was then separated from the sample and weighed. 29 per cent
of the bitumen originally present in the sample had flowed into
the porous bed.
When the same procedure was followed using a small
quantity of water placed on top of the oil sand sample 80 as to
tend to displace the fluidified bitumen by its own weight, it was
found that 40~ of the bitumen originally present had passed into
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the porous bed.
When the same procedure was followed using ethane
at pressures of 515 to 535 psig, about 55% of the bitumen
migrated out of the sample by gravity without water being used
as a displacement medium.
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