Note: Descriptions are shown in the official language in which they were submitted.
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RECOVERY OF BITUMEN FROM TAR SAND MATERIAL
This invention relates to an improved method for
the recovery of bitumen from tar sand material. More
particularly, it relates to a process involving contacting
the tar sand materlal with a heated aqueous fluid containing
certain amines.
One embodiment of the invention provides a thermal
recovery process involving injection of steam and the amine
into a tar sand formation. Another embodiment provides
a hydraulic mining process involving passing high velocity
jets of the heatea aqueous fluid into a cavit~ of the
formation and recovering bitumen and sand with the aqueous
fluid from the cavity. A further embodimen~ provides a
method involving contacting mined tar sand material with
the heated aqueous fluid.
There are many subterranean petroleum-containing
formations from which petroleum cannot be recovered because
the petroleum viscosity is so high that it will not flow or
cannot be pumped to the surface of the earth without first
applying a treatment to reduce the petroleum viscosity.
The most extreme example of viscous petroleum-containing
formations are the so-called tar sand or bituminous sand
deposits. The largest and most famous deposit of tar sand
is the Athabasca tar sand deposit of Alberta, Canada.
Although this deposit contains in excess of 700 billion
barrels of petroleum, essentially no recovery of petroleum
has ~een af~ected by commercial means from these deposits
because of the very high viscosity o~ the oil. Other
viscous oil formations are found in the United States and
in various other countries throughout the world.
Thermal recovery techniques have been used success-
fully for recovering viscous petroleum from subterranean
forma'ions in many applications~ although they have been
unsuccessful on a commercial basis in other deposits for a
variety of reasons. The most successful thermal recovery
technique involves introducing sLeam into the formation to
raise the temperature of the viscous petroleum, thereby
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decreasing its viscosity sufficiently for it to flow or
be displaced to a well, which may be the same well as ~Jas
used for steam injection or a spaced-apart production well.
Although most viscous oil formations can be stimulated to
produce some oil by steam injection, the cost effectiveness
is such that steam flooding can be applied to viscous oil
formations on a profitable basis in only a limited number of
instances. The principal cost factor in steam flooding
operations is the cost of fuel re~uired to generate the steam
for injecting into the formation. Obviously, the amount of
oil recovered per unit of fuel required to generate steam
used in the recovery of oil is a critical factor, and is the
principal reason that many viscous oil formations cannot be
successfully exploited by steam stimulated recovery.
Various additives have been proposed in the prior art for
improving the effectiveness of steam flooding oil recovery
processes. Various solvents have been injected or mixed
with steam, and generally result in some improvement in the
oil recovery, although it has often been found that the
amount of additional oil recovered is not sufficient to
justify the cost of the solvents introduced into the forma-
tion in combination with steam. The use of liquid, gaseous,
and combinations of liquid and gaseous hydrocarbon solvents
with steam are disclosed in many prior art references.
U.S. Patent No. 3,822,749 discloses the use of a
pretreatment comprising a gaseous phase aliphatic polyamine
injected into a formation containing water sensitive clays
before injecting steam thereinto, the polyamine being
utilized to reduce the water sensitivity of water sensitive
clays.
Methods for the recovery o~ bitumen from tar sand
deposits can be generally classified as strip mining or in
situ separation. Strip mining requires removal of the
overburden by mechanical means and the mixture of bitumen
and sand that constitutes the tar sand deposit is then
similarly removed by mechanical means and transported to
a surface processing plant for separation of bitumen and
sand. In situ separation processes make use of techniques
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for separating the bitumenfrom the s~d within the tar sand
deposit itself, so the bï~u~enin sOme modified form may be
transported to the surface with at least a major portion of
the sand left in the tar sand deposit. Techniques proposed
in the prior art for in situ separation may be classified as
thermal or emulsification processes. The thermal techniques
include in situ combustion, (fire flooding), and steam
flooding. Emulsification processes may also involve the use
of steam in addition to an additional chemical to promote
emulsification o~ the high viscosity bitumen so that it may
be transported to thesurface where the emulsion is resolved
into bitumen and water. Although many in situ separation
techniques have been proposed in the prior art, none have
been both economically and technically successful.
Most known in situ processes involve injection of
fluid under fairly high pressures. Injection of high
pressure fluid can be conducted safely only if the formation
overburden thickness is sufficiently great to contain the
high pressure fluids injected thereinto without rupturing.
Strip mining of a tar sand deposit is economically feasible
only if the ratio of overburden thickness to tar sand deposit
thickness is around 1:1 or less. Even when the tar sand
deposit is fairly shallow, strip mining is still very
expensive; the cost of removing overburden and tar sand
material represents from 50-60 percent of the total cost of
producing a pipeline-acceptab}e product. Many deposits have
overburden which is too thick to permit exploitation by strip
mininy, and not great enough to contain high pressure fluids
for in situ separation processes.
In view of the foregoing it can be appreciated
that there is a substantial, unfulfilled need for a method
,for recovery of bituminous material from tar sand deposits,
particularly those intermediate depth deposits which are not
suitable for strip mining or for in situ recovery processes
in~7Olving injecticn OI a high pressure fluid.
U.~. Patents No. 3,951,457 and 3,B58,654 describe
hydraulic mining processes for recovering heavy oil from
oil sand deposits.
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~ ethods taught in the prior art for processing tar
sands recovered from open pit mines or strip mines include
direct coking, anhydrous solvent extraction, cold water
separation techniques which make use of a wetting agent, and
several hot water techniques, some of which also employ
wetting agents or other chemicals in combination with hot
water.
The fuel costs for the direct coking technique are
presently prohibitive, and the solvent cost for the anhydrous
solvent technique is excessive, even with solvent recovery
processes.
The hot or cold water separation techniques appear
to hold great promise for processing mined tar sand. Several
problems have been encountered, however. Emulsion formation
is almost spontaneous when bituminous petroleum contacts hot
water containing an alkalinity agent such as sodium
hydroxide. ~hile formation of a stable oil-in-water emulsion
is useful in some in situ recovery processes, emulsions of
both the oil-in-water and water-in-oil type are frequently
formed as a by product of cold or hot water separation
processes. In either case, the emulsion must be broken or
resolved into its individual phases. Resolving emulsions
involving bituminous petroleum is usually difficult for
several reasons. Asphaltic substances are very effective
emulsifying agents and form very stable emulsions.
Furthermorerthespecific gravity of bitumen is almost
exactly equal to that of water, which means there will be
no gravity-related forces due to density differences to aid
in phase separation, even if surface forces responsible for
emulsification can be neutralized. The bituminous petroleum
has a very great affinity for sand grain surfaces, and many
hot water processes do not effectively strip the bituminous
petroleum from the sand grains.
Another very serious problem, which has been encoun-
tered in commercial separation projects, is formation of astable froth. The air- or other gas-entrained froth is very
stable, and quite often huge, unmanageable volumes of tne
froth are produced.
In view of the foregoing, it can be appreciated
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that there is a substantial, unfulfilled need for a surface
processing method for separating bitumen or bituminous
petroleum recovered from surface or subterranean tar sand
deposits by mechanical means such as strip mining, which
does not result in formation of an emulsion or froth.
U.S~ Patent No. 3,846,276 describes a separation
process employing hot water and a polyphosphatewetting agent.
In its broadest aspect, the present invention
comprises a method for recovering bit~en from tar sand
10 material by contacting the tar sand material with a heated
aqueous fluid containing an amine having the formula:
1 2 3
wherein Rl and R2, which may be the same or different, are
each hydrogen or a Cl to C6, and preferably a C2 to C4, alkyl,
linear or branched, R3 is a C3 to C20 and preferably C4 to
C12 alkyl, linear or branched, or -R4NH2 wherein R4 i5 C2
to C18, and preferably C3 to Cll alkylene, linear or branched,
and the sum of the number of carbon atoms in Rl, R2 and R3 is
rom 3 to 20, and preferably 7 to 13.
One example of a material which is within ~he scope
of the above formula, which has been tested and found to
effectively dislodge bitumen from sand grains is
diethylaminopropylamine (C2H5)2NC3~6NH2. This material is a
water-white substance with a typical amine odor, having a
boiling point of 159C and a freezing point of -100C.
The specific gravity is 0.82 (20/20C) and the flash point is
145 C. It is known for use as a curing agent for epoxy
resins, and as a chemical intermediate for other manufacturing
and processes.
Another example of a preferred amine within the
above formula, which has been examined and found to improve
greatly the oil recovery effectiveness of steam flooding, is
a C10-Cl3 sec alkyl primary amine. This compound is
available commercially ~rom Texaco Petrochemical Sales under
the designation PT-9108, ana has a boiling point of 259c,
and is only slightly soluble in water.
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In the drawings which accompany this specification
and form a part thereof, Figure 1 shows a tar sand deposit
in which a combination injection-production well has been
drilled, in accordance with one embodiment of the present
invention. Figure 2 shows in a semischematic form the
separation of bitumen from mined tar sand material by hot
aqueous fluid containing amine.
- In one embodiment, the amine is introduced into a
tar sand formation by mixing the amine with steam and
injecting it into the formation, or the amine may be
introduced
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separately in the form of one or more slu~s of amine,
followed by steam to accomplish mixing ln the formation.
From 0.1 to 30, and preferably from 2 to 10, pore volume
percent of amine should be utilized, the amount o amine
being nearer the upper end of the preferred range with
formations containing very viscous petroleumr i.e., the
amount of amine required increases roughly in proportion to
the viscosity of petroleum present in the formation. The
amine effectively reduces the attraction between the viscous
lo oil and the surface of the sand grains or other îormation
mineral matrix, thereby greatly increasing the amount of oil
recovered from the zone thro-ughwhich the steam passes.
This embodiment of the present invention concerns
an improved thermal oil recovery method, introducing steam
into the formation fox the purpose of heating viscous oil
contained therein, therehy reducing the viscosity of the
oil so it may be displaced to a well. Conventional steam
flooding is applied commercially in two somewhat different
ways, one being a steam drive process in which steam is
injected into the formation by one or more injection wells
to pass through the formation, displacing and mobilizing
petroleum, the petroleum being displaced to a spaced-apart
production well from which it can be recovered to the surface
of the earth. The other commonly used method is the steam
push-pull, or huff-and-puff, method, in which steam is
injected into a formation, allowed to remain in the formation
for a period of time sufficient to transfer thermal energy to
the viscous petroleum, and then fluids including petroleum
are recovered from the formation by the same well as was
used for introduction of steam into the formation. Both
methods are successful for recovering viscous oil, to varying
degr,ees depending on the viscosity of the oil, the attractive
~orces between the oil and the formation mineral surfaces,
as well as many other factors.
Steam drive is thepreferred method in most applications,
since it achieves oil recovery at greater distances from
the wells, and its thermal efficiency is greater than that of
push-pull steam methods.
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In applying the process of this invention to a
subterranean, viscous oil-containing formation, the
preferred method comprises introducing the steam and amine
into the formation by one or more injection wells, and
recovering oil mobilized and displaced by the steam and amine
from the formation from one or more production wells, which
are spaced apart from the injection wells. This involves
the commonly known steam-drive oil recovery process, and
effects recovery at much greater depths in the formation
from the well than is possible with the push-pull steam
flooding me-thod.
In applying the process of the invention, either
saturated or superheated steam may be utilized. The most
practical method involves the use of saturated steam, and
the preferred steam quality ranges from 20 to 100~, and
preferably from 60 to 80~.
If it is desired to mix the amine described above
with steam, then the concentration of amine should be from
0.5 to 25, and preferably from 2 to 10, percent by weight.
The steam and amine mixture may be injected into the
formation in the early phase of the steam flooding operation,
until the total amount of amine introduced into the
formation is in the range of from 0.1 to 30, and preferably
2 to 10, pore volume percent, based on the pore volume of
the recovery zone being treated. After this amount of
amine has been injected, steam (without amine ) may be
injected for a period of time sufficient to displace the
previously injected fluids as well as mobilize oil through
the formation. It is more efficient to introduce the
~ amine into the formation during the early stages of steam
injection, rather than injecting steam for any prolonged
period of time and then injecting amine mixed with or
sequentially with additional steam.
Another method of applying the process of the
invention involves injecting one or more discrete slugs of
the amine irto the formation, before or interspersed with
periods of injecting substantially pure steam into the
formation. Since some of the preferred species are only
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slightly soluble in water, this is an effective means of
accomplishing intimate contact between the amine and steam
with bitumen present in the formation.
Another embodiment of the invention involves the
recovery of bitumen, by a hydraulic mining technique,
wherein the tar sand is contacted by a fluid comprising hot
water or steam and the amine. In one embodiment, an
injection string capable of both rotation and axial
(vertical) movement, equipped near its lower end with jet
nozzles which direct the aqueous hydraulic mining fluid as
one or more jet streams against the face of the iar sand
deposit, s employed. A separate communication path to
the surface o~ the earth facilitates movement of the injected
hydraulic mining fluid, with bitumen dispersed therein,
to the suxface for further processing. The injection strin~
is constructed so as to permit simultaneous rotation and
vertical movement as the aqueous hydraulic mining fluid is
injected down the injection string and out through the jet
nozzles, so that a stream of fluid sweeps the tar sand
deposits.
This embodiment can best be understood by referring
to Fig. 1 of the attached Drawings, in which a tar sand
deposit 1 is located at a depth which is too great for
economical strip mining and not deep enough to permit using
an in situ recovery technique requiring injection of a high
pressure fluid. A combination injection-production well
2 is drilled to the bottom of the tar sand deposit, and
casing 3 is set to the top of the formation. A separate
injection string 4 is run inside the casing 3j to the top of
the tar sand deposit. The injection string 4 is equipped
with nozzles 5 near the bottom thereof, and the completion
equipment on the surface includes means r such as kelly
drive bushing 7, fo~ rotating the injection string ana
lifting hook 6 for raising and lowering the string as fluid
is pumped down the string. A swivel 8 provides an essentially
leak-proof seal between the non-rotating upper portion and
the rotating lower portion of inJection string 4. P~p 9
pumps the aqueous hydraulic mining fluid down the injection
string 4 with sufficient pressure to form high velocity je~s
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10, and ensure that jets 10 contact the tar sand with
considerable impact velocity to dislodge bitumen and sand.
The rotatable, vertically moveable injection string
4 contains an interior flow path 11 for pumping the aqueous
hydraulic mining fluid down the string, where a portion of
it passes out through jets 5 to form jet streams 10, which
impinge against the walls 12 of the cavity which has been
formed in tar sand deposit 1. Some means for pumping
the dislodged hitumen from the lower portion of the cavity
must be provided, e.g. jet pump 13. The fluid for operating
the jet pump is the aqueous hydraulic mining fluid in this
embodiment, although a separate hydraulic fluid may be used.
A portion of the aqueous hydraulic mining fluid passes to
the jet pump _ via flow line 14, where it exits through
nozzle 15, and then through venturi 16. The passage o~
fluid through the venturi creates a zone of reduced pressure
in the venturi, which draws bitumen and other material
from the bottom of the cavity and forces it upward toward
the surface via return flow path 17. The fluid including
bitumen passes out through flexible fluid discharge line 18
into settling tan~ 19. More than one tank in series may
be utili~ed, although only one is shown for simplicity.
The fluid separates into oil or bitumen and water, with the
sand separating to the bottom of settling tank. The
water is recycled through holding tank 20 via line 21. The
water is heated in heat exchanger 22 and pumped via 1uid
inlet line 24 into the top of injection flow path 11, where
it passes back to jets S as described above.
A noncondensible gas such as nitrogen, air, methane,
carbon dioxide, etc., or a mixture of one or m~ore of the
gases, is used in the embodiment shown in the Drawing.
The gas is supplied from compressor or vessel 23, to mix
with the aqueous hydraulic fluid and pass via flexible
input line ?4 to injection flcw path 11. The use of gas
in this process is very desir~ble since it aids in supporting
the overburden, improves pumping efrectiveness, and by
maintaining the cavity gas filled, allcws the jets of
hydraulic mining fluid to penetrate deeper into the ~ormation.
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The top of the injection string contains a high
pressure swivel assembly 25 into which fluid injection and
discharge lines connect. A loop 26 is also provided for
engaging lifting hook 6 connected to the drawworks (not
shown). This arrangement allows theentire assembly to be
lowered into the well and moved up and down as needed to
allow the jet streams 10 to sweep the entire vertical
thickness of the formation. The hydraulic mining string
is rotated by a convenient means such as a drilling rig
kelly ~not shown), engaging the kelly drive bushing 7
The surface apparatus should also include a sealing
element 27 so that no blow-by occurs between the hydraulic
mining injection string assembly 4 and casing 3. This
allows maintenance of positive fluid pressure within cavity
12, for purposes to be described below.
On the very bottom of ~he assembly of this illus-
trative embodiment is a conventional drill bit 28, which
permits drilling the well through the tar sand interval with
the same equipment asis used for the hydraulic mining
operation. The drill bit is also useful ~or breaking up
clumps of tar sand material, which are dislodged and
accumulate in the bottom of the cavity in the tar sand
deposit.
The overall equipment as embodied in the attached
Drawing is known in the art of hydraulic mining. For
e~amplç, an axticle titled "Subsurface Hydraulic Mining
Through Small Diameter Boreholes": pages 24-27, Mining and
Minerals Engineer ng, November, 1969 describes an essentially
identical apparatus used in drilled consolidated formations
such as limestone with an abrasive laden fluid pumped by an
explosion type pumping system..
The particularly rotating in~ection string shown in
the Drawing is not an essential fea~ure of the invention,
although it is the preferred method for obtaining the desired
jetting action. A non-rotating string with a plurality of
horizonially displayed nozzles could also ~e used.
In operation, the aqueous hydraulic mining fluid is
pumped from supply tank 20. The fluid injection pressure
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need not be as high at the start of the operation as will be
required later in the process, since the hydraulic mining
fluid jet will only have to tra~el a relatively short
distance before contacting the face of the cavity in the tar
sand deposit. If a noncondensible gas such as air, nitrogen,
carbon dioxiae, methane or natural gas is used, it is mixed
with the aqueous hydrualic mining fluid, and a two phase
mixture is pumped down string 11 and out jets 5. The
presence of a noncondensible gas is a highly desirable
embodiment of the process of the in~ention for several
reasons. The cavity in the tar sand deposit should be
filled with gas rather than liquid, especially after
application of the process for a sufficient period to create
a large cavity, to increase the distance that the jets
travel away from the hydraulic mining apparatus. Also,
maintaining a positive gas pressure in the cavity helps
support ~he overburden and assists in the pumping action in
the bottom of the cavity.
As the bitumen and some sand are removed from the
tar sand deposit, a cavity is created adjacent to the nozzles
on injection string 4, and the size of this cavity increases
with time. As the cavity size increases, it is necessary to
increase the hydraulic mining fluid injection pressur~, so
that fluid jet stream 10 will reach to the cavity walls with
sufficient velocity to dislodge bitumen and sand.
Throughout the process o the invention, a mixture
of bitumen and aqueous hydraulic mining fluid, with sand
suspended therein, flows back of the surface of the earth via
the return flow path 17. The bitumen/hydraulic mining fluid
mixture passes via flow line 18 into separation tank 19.
Sand settles to the bottom and may be removed mechanically.
Bitumen separates into one phase, and is removed by line 29
and then to surface processing equipment. Aqueous hydraulic
mining fluid constitutes the other liquid phase, passing via
line 21 back to tank 20, where it can be reheated and recycled
into the injection string 11.
The temperature of the aqueous hydraulic ~luid may
be from 80 to lQ5 C (180 to 220F3 or above. In one
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preferred embodiment, the temperature of the bitumen-
aqueous fluid pulp being produced is monitored, and the
temperature is adjusted to yield a pu~p temperature in the
range of from 70 to 95 C (160F to 200F) and preferably
as near 82 C (180 F) as possible.
The bitumen-hot water mixture more closely resembles
the pulp of the hot water surface processes used in
separating bitumen from tar sand material obtained by strip
mining, than it does any of the produced fluids obtained
from known tar sand in situ separation techniques.
The effectiveness of the fluid for separating oil
and sand increases with temperature. It is highly preferred
that the fluid be in the liquid phase at the temperature and
pressure in the extraction zone of the formation, since
greater penetration is achieved with liquid jets than with
vapor phase jets. The fluid temperature may, however, be
such that the fluid is at least partially in the vapor phase
at atmospheric pressure; The preferred temperature is
greater than 65 C tlS0F) and preferably greater than 82C
(180F), and below the boiling point of the fluid at the
pressure in the cavity or treatment zone of the formation.
In a slightly different embodiment, a smalI but
effective amount of a solvent for bitumen is included in the
hydraulic mining fluid. Monocyclic aromatic solvents, such
as benzene, toluene or xylene, as well as saturated hydrocarbon
solvents having from four to eight carbon atoms, naphtha, or
mixtures thereof, may be injected with the hot aqueous fluid.
The presence o~ a small amount of solvent increases the
effectiveness of the process substantially. The preferred
ratio of solvent to aqueous hydraulic mining fluid is from
about 0.01 to about 0.50.
The amine described above is mixed with hot water
or steam in a concentration of from 0.5 to 25, and preferably
from 2 to 10, percent by weight.
Noncondensible gas is, in a preferred embodiment,
injected into the formation simultaneously with the hydraulic
mining ~luid. The use of a noncondensible gas in this
process improves its operation considerably and in several
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ways. Maintenance of a positive pressure aids in supporting
the overburden and helps the pumping action. By keeping the
cavity formed in the formation by this process filled with
gas rather than with liquid, the jets of fluid travel ~urther
away from the injection string. Also, some gas is dissol~ed
and/or entrained in the pulp of bitumen and aqueous fluid,
and this gas forms small bubbles during the surface
separation to aid in separating bitumen and aqueous fluid.
Any readily available substance, at least a
10 substantial portion of which remains gaseous at the
temperature and pressure of the formation, and which is
unreactive with the fluid injected and with petroleum may be
used. Air is a suitable material when hot water is used, but
steam and air should not be used together, because of the
likelihood of initiating an oxidative reaction. Nitrogen may
be used safely with steam, as well as with hot or cold water.
Carbon dioxide may also be used with any of the hydraulic
mining fluids described above. Hydrocarbons such as methane
or ethane may also be used. Dependiny on the temperature and
20 pressure of the tar sand formation, propane may sometimes be
used. Mixtures of any two or more of the foregoing materials
may also be used. The volume ratio of noncondensible gas to
aqueous hydraulic mining fluid may be from about 1/10 to
about 10. The noncondensible gas may be introduced simultan-
eously as a mixture using the same injection string, orsimultaneously using separate injection strings, or slugs of
aqueous hydraulic mining fluid may be alternated with slugs
of non-condensible gas.
According to another embodiment, bitumen may be
separated from mined tar sand materials by a technique wherein
the tar sand is contacted by the hot aqueOus fluid containing
the amine. The tar sand is fed continually into a mixing
vat where contact with the hot water-amine treating fluid
occurs. The mi~ture is fed to a settling tank for
separation into sand, bitumen and an aqueous phase having a
minor amount of bituminous material contained therein.
The mixture may be contacted with a hydrocarbon treating
fluid which solubilizes the bitumen and facilitates separation
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thereof, if needed.
This embodiment of the invention can best be under-
stood by referring to Fig. 2 of the attached Drawings, in
which tar sand material which has been dug from an open pit
mine and transported by mechanical means, is dumped into
container 101. Screw conveyor 102 conveys tar sand at a
steady rate into mixing vessel 103, which is equipped with
a stirring device 104. An aqueous treating fluid comprising
water and from 0.05 to 25, and preferably from 2 to 10,
percent by weight of an amine, is prepared in container 105,
from which the solution is pumped by pump 106 through heat
exchanger 107 wherein the fluid is heated to a temperature in
excess of 37C (100F) and preferably between 37 and 99 C
(100F and 210F). The heated aqueous fluid mixes with tar
sand in tank 103, where the mixture is agitated by mixer
104 and them pumped by pump 108 into separation tank 109.
For a continuous process, a series of separation tanks may
be used in parallel, with sequential routing of the fluid
to the several tanks, so the mixture can remain quiescent
for a period of time sufficient to facilitate settling of
sand 110 in the bottom of the tank. Most of the bitumen
a~cumulates in a zone immediately above the sand layer.
An aqueous layer forms on top, which is comprised of the
aqueous, amine-containing fluid having a small amount of
bitumen dispersed therein. Sand is removed from the lower
zone in tank 109 continuously or intermittently, by some
means such as the screw conveyor 113.
A hydrocarbon fluid from tank 114 is metered by pump
115 into the separation tank 109 at a predetermined flow
rate. The aqueous treating fluid and hydrocarbon are
mixed in separation tank 109 by stirrer 116. Bituminous
material from the lower layer, as well as from the a~ueous
suspension, dissolves in the hydrocarbon and forms layer
117. The hydrocarbon with bitumen dissolved therein is
transported via line 118 to a refinery. Presence of
hydrocarbon in the bitumen aids pumping to the refinery
process unit. Separation an2 recovery of hydrocarbon
treating fluid may be accomplished in the refinery unit.
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Of course, hydrocarbon recovery may be accomplished immediately
after leaving separation unit 109 if desired.
The hot aqueous treating fluid 119 is pumped via line
120 and pump 121 through filter 122 to tank 5 for recycling
through the separation process equipment.
The amine is generally mixed with hot water in a
concentration of from 0.5 to 25, and preferably from 2 to
10, percent by weight.
Although concentrations greater than this may be used,
there is no particular advantage in using larger concentra-
tions, and while the cost of the material is low,
ecomomics of the process are optimized by using the lowest
concentration of amine which is effective for separating
bitumen and sand.
Sufficient alkalinity agent should be added to the
solution to bring the pH thereof to a value above 7, and
preferably above 9.
Heating the aqueOus fluid to a temperature in excess
of 37 C (100F) will increase the effectiveness of this
2Q separation technique. The preferred operating temperature
is from about 37 to 99C (100F to about 210F) and the
especially preferred range is from 65 to 99 C (150 F to
210F)
One attractive ~eature of the process of the invention
is the fact that bitumen is not emulsified and no froth
is formed on contact with the hot aqueous amine-containing
fluid. Bitumen is removed effectively frcm the sand, but
remains in a separate phase, which will orm a discretè
layer distinct from the aqueous fluid if agitation is
stopped. The bitumen may be pumped to the refining process
unit, the water-amine fluid being recycled through the
separation equipment.
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EXAI~ LE
A pilot field project is undertaken utiliz:ing an
inverted five-spot pattern with one injection well in the
5 center of a square grid and a producing well on each of the
four corners of the square. The distance of each side of
the square is 200 feet (60.96 m.). The wells are cornpleted
in a viscous oil formation containing 11 API crude, which
is too viscous to flow or be displaced by ordinary primary
10 or secondary recovery techniques. The porosity is 39
percent and the permeability is 1200 millidarcies. The oil
saturation is 61 percent. The formation thickness is 45
feet (13.71 m.).
The total pore volume of each grid unit is 0.39 x 200 x
15 200 x 45 = 702,000 cubic feet (0.39 x 60.96 ~ 60.96 x 13.71 -
19,880 cubic meters). Since the horizontal sweep efficiency
of such a pattern is 70 percent and the vertical conformance
is ~0 percent, only 42 percent or 294,840 cubic feet
(8350 cubic meters) will be contacted by steam. The
20 process applied to this pilot involves the use of a 5
percent pore volu~ne treatment of a dodecyl amine. Five
percent amounts to 14,740 cubic feet (994 cubic meters),
which requires about 340 tonnes of the dodecyl primary amine.
In applying the process, 80 percent quality steam
25 is injected into the injection well for two days to preheat
the portions of the formation immediately around the
injection well, to facilitate injection of the amine into
the formation. The total amine treatment is applied in four
discrete slugs, each involving injecting 190,000 pounds
30 (86.26 tonnes) of amine into the formation followed by
injection of steam for 60 days. Steam and amine comingle
in the formation with one another and with the formation
petroleum, effecting viscosity reduction of the petroleum
and also effectively reducing the retentive forces between
35 the viscous petroleum and the formation sand grains. After
the last treatment of amine is completed, steam injection is
continued in the formation until a total of two pore volumes
of steam (based as water) have been injected into the
formation. This requires approximately 90 weeks of injection.
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As a result of the above described process, the residual
oil saturation is reduced from 51 percent to 12 percent,
within the zone contacted by the injected fluids, which is
considered as excellent for this particular reservoir.
EXAMP~E 2
Laboratory tests were conducted utilizing samples of
tar sand material. The samples were mixed at room temper-
ature with diethylaminopropylamine as a solvent, and it was
observed that under static conditions at ambient temperature,
essentially all of the viscous tar sand materials were
dislodged and removed from the mineral surfaces of the tar
sand sample, thus indicating the effectiveness of this
material for removing viscous petroleum from sand grains~
Tar sand materials are bituminous in character and there is a
great affinity between the hydrocarbon portion and the sand
grains which is a major cause of the great dif~iculty that
has been encountered in obtaining recovery of petroleum from
tar sand deposits. Accordingly, the above-described
observation is quite significant ~or application to
bituminous, viscous petroleum ~ormation as well as other `
viscous oil formations.
A series of displacement tests were conducted in small,
seven-inch cells which were packed with 10.5 API crude
oil, sand and water to give an initial oil saturation of
about 0.55 and a permeability of about 0.36 darcies. The
first cell was steam ~looded at a 120 gram per hour steam
rate at an injection pressure of 2~0 PSI (16.33 atmospheres)
while maintaining 200 PSI (13.6 atmospheres) backpressure~
The second cell was treated first with 10 percent pore
volume amine additive before injecting the same quality
steam at the same steam injection rate. The amine used in
this test was a C10-Cl3 (secondary alkyl) primary amine
available commercially from Texaco Petrochemicals ~epartment
under the desingation PT-9108.- A11 of the amine was
injected in a single 10 percent pore volume slug be~ore
injecting steam into the core. The ~irst steam flood
succeeded in reducing the oil saturation to 0.195 which
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is equivalent~to 63.6 percent recovery. In the second
flood, employing the amine, the oil saturaticn was reduced
from the same 0.55 initial level to 0.051, for 90.7 percent
recovery, which is 40 percent greater than the base steam
S run. This is considered to be an excellent recovery for
such viscous crude, and readily illustrates the effectiveness
of the process of the invention for recovering viscous
petroleum.
To illustratethe comparative effectiveness of the steam
amine oil recovery method of the invention, the following
is a tabulation of the residual oil saturation of
laboratory steam displacement tests with steam or mixtures
of steam and various additives.
15 Oil Recovery Fluid Residùal Oil Saturation
Steam alone (average of several
runs) 25
Steam plus ethanol 24.4%
Steam plus carbon dioxide 21.6%
Steam plus propane and ethanol 19.4
Steam plus condensate 17.4
Steam plus t-butyl alcohol +
pentane 17.0
Steam plus BZ Raffinate 16.4
Steam plus aromatic solvent 16.2
25 Steam plus heavy CR gasoline 14.0
Steam plus benzene 13.0
Steam plus light SR gasoline 11.1~
Steam plus Udex Extract 9~3Q
Steam plus Amine 5.1~
The above data clearly indicate the surprising
superiority of the use of steam plus a~ine as compared to
steam or mixtures of steam and other additives.
EX~LE 3
A tar sand deposit is to be exploited and it is
determined that the thickness of the tar sand deposit is
65 feet (19.8 m) and the thickness of the overburden is 275
feet (83.8 m). Since the ratio of overburden thickness to
tar sand deposi~ thickness is considerably greater than 111,
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strip mining is not economic. Moreover, the overburden
thickness is not thick enough to make high pressure gas
injection safe.
A well is drilled to the bottom of the deposit and a
casing is set to the top portion of the tar sand deposit
and cemented. A hydraulic mining apparatus similar to
that shown in the Drawing is used. The lower portion of
the assembly is equipped with four horizontally oriented
jet nozzles so that fluids pumped into the assembly will
exit through these nozzles in a generally horizontal
direction with considerable velocity. The surface equipment
includes means for rotating the assembly ~y an electric
motor, and sealing devices to establish a liquid tight
seal between the rotating and non-rotating members are also
provided. The hydraulic mining fluid chosen for this
field trial is initially water at 93C (200F) containing
5.0~ by weight of dodecylamine. Methane is injected with
the hot fluid to insure a gas-filled cavity and to provide
support for the overburden. The volume ratio of methane
to hydraulic mining fluid is about 2:10. Initially the
injection pressure is approximately 6.8 atmospheres (100
pounds per square inch~, since the jet of aqueous hydraulic
mining fluid emerging from the nozzles must flow only a
short distance before it impinges against the tar sand
deposits. The mixture of bitumen from the tar sand and
the hot aqueous hydraulic mining fluid is pumped by a jet
pump in the bottom of the hydraulic mining assembly, and
flows to the surface through a return flow path integral
to the hydraulic mining assembly. The fluid produced at
the surface contains "free" bitumen (not emulsified),
hydraulic mining fluid, gas and sand separation is accomplished
in two gravity settling tanks in series. Bitumen is sent
to processing facilities and the aqueous rluid is recycled.
The pH and temperature of the fluid mixture ~pulp)
being produced are monitored continually. The ~emperature
of the hydraulic mining fluid being injected is adjusted to
maintain the pulp temperature at 82 C (180 F)~
The hydraulic mining assembly is positioned so the jets
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are initially adjacent the top of the tar sand deposit.
The assembly is rotated at 4 rpm and slowly lowered. The
rate of lowering is initially about 30 cm (one ~oot) per
minute. As the bottom of the assembly reaches the bottom
of the tar sand deposit, the direction is reversed and the
assembly is raised at about 30 cm. (one foot) per minute,
while rotating and injecting hydraulic mining fluid.
As the cavity diameter increases, the aqueous hydraulic
mining fluid jet streams from the nozzles must travel ~urther
away from the injection point before contacting the wall
of the cavity in the tar sand deposit, and so the injection
pressure must be increased. The need for an increase in
injection pressure is deter~ined by monitoring the ratio
of bitumen and sand to aqueous fluid in the pulp being
produced to the surface of the earth. A decrease in the
concentration of bitumen and sand in the produced pulp
indicates that the jets of aqueous hydraulic mining fluid
are not moving sufficiently far away from the nozzles to
contact virgin tar sandr and so the injection pressure
must be increased. By increasing the injection pressure
in small increments, e~g., 5 or 10 psi (0.3 or 0.6
atmospheres) at a time, the injected aqueous hydraulic
mining fluid stream may be made to continually contact the
outer cavity walls within the tar sand deposit. The static
gas pressure in the cavity is maintained constant since- it
is not desired to create a fracture between the pressurized
tar sand formation and the surface of the earth, which would
establish an undesired return communication path through
the overburden to the surface. While the static pressure
in the cavity expressed in pounds per square inch must not
exceed the overburden thic~ness expressed in feet, the
injection pressure may go much higher, up to 70 atmospheres
(1000 pounds~ or more. This process is continued until a
substantial decrease in bitumen sand content of the produced
bitumen sand water slurry is observed, and an increase in
injection pressure up to 102 atmospheres (1500 psi) fails
t~ cause a corresponding increase in the bitumen sana
content of the produced fluid pulp. This indicates that
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The maximum range of the hydraulic mining fluid jet within
the cavity has been reached and no additional bitumen can
be recovered by this technique from the cavity.
After it has been determined that the hydraulic mining
process has been extended as far into the tar sand deposit
as possible, the hydraulic mining fluid remaining within the
cavity may be recovered by pumping to the surface for reuse
in adjacent areas of the deposit.
i0 EXAMPLE 4
A tar sand deposit having an overburden varying ~rom
3 to 12 meters (10 to 40 feet) in thickness, said deposit
having an average thickness of 19.8 m. (65 feet~ is exploited
by means of open pit strip mining. After stripping away
lS the overburden, tar sand is dug from the deposit using
scrapers and transported by truck to the separation process
equipment. The equipment is theoretically capable of removing
the tar sand at a rate of 1500 tonnes per hour, although
actual production rate is 1000 tonnes per hour. The bitumen
20 content of the tar sand is 14 percent by weight.
Separation is accomplished by using a number of units,
each with a capacity of 200 tonnes per hour. The tar sand
is fed by screw conveyor into a 15750 liter ~5000 gallon)
mixing tank. An aqueous ~luid comprising water and 10
25 percent by volume dodecylamine is formulated in a 3150 liter
~1000 gallon) tank and fed into the 15750 liter (5000 gallon)
tank at a rate of 3150 liters (1000 gallons) per hour. The
water-amine is heated to a temperature of 96C (205F3 by
passinq through a gas ~ired heater prlor to being added to
30 the 15750 liter (5000 gallon) tank.
Two separation tanks are provided for each mixing tank,
so the mixing tank output is passed first to one separation
tank and then to the other. Each separation tank has a
volume of 9450 liters (3000 gallons). A screw conveyor
35 removes sand from the bottom of tne separation tanX. Bituminous
petroleum accumulates in a layer immediately above the sand
layer, and an aqueous layer having a small amount of bitumen
dispersed therein accumulates on top. Diesel oil is added to
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the separation tank and mixed. Bitumen from the layerimmediately above the sand as well as that dispersed in the
aqueous phase, dissolves in the diesel oil. After mixing
is stopped, a layer of diesel oil and bitumen forms on top,
which is decanted and sent to the refinery.
The hot aqueous amine-containing fluid is passed
through a sand pack filter and then back to the treating
fluid make up tank for recycling through the unit.
Sand from the setting tank is placed in excavations
lo formed in earlier stagès of strip mining operations.
The separation technique effectively removes approximately
90 percent of the bitumen from the tar sand.
