Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
CA 2652930 2017-06-22
IN-SITU RECOVERY OF BITUMEN OR HEAVY OIL
BY INJECTION OF DI-METHYL ETHER
DESCRIPTION
The present invention is directed to a process for efficient, environmentally
friendly, in-situ
recovery of bitumen or heavy oil by injecting pressurized, heated di-methyl
ether (OME) into the
reservoir using equipment comparable to that applied for steam assisted
gravity drainage
(SAGO) or cyclic steam stimulation (CSS), recovering the mobilized
bitumen/heavy oil from the
reservoir, separating the OME from the bitumen/heavy oil by depressurizing
followed by
pressurizing, heating and re-injecting the recovered OME into the reservoir.
Background of the Invention
Field of the invention: Nowadays most of the bitumen is recovered by mining
the oil sands ore
and separating the bitumen from the mined ore. Only a minor fraction of the
Alberta deposits of
bitumen can be economically recovered by mining. Over 80 wt of the bitumen and
essentially
all heavy oils have to be recovered by a variety of in-situ processes for
which the common
denominator is injection of steam into the reservoir to raise its temperature
and lower the
viscosity of the bitumen/heavy oil in order to deliver it to the surface,
clean and pipeline the
bitumen/heavy oil for processing/upgrading.
Description of Prior Art: Increasing demand for heavy oil and bitumen in
particular resulted in
developing, over the last twenty years, a commercial steam assisted gravity
drainage (SAGO)
technology for in-situ recovery of bitumen from Alberta oil sands deposits.
The SAGO concept is
based on horizontal well technology. The steam is injected into horizontally
positioned steam
dispersing pipe (injection well) placed in the center of a gravity drainage
chamber. Sometimes,
suitable additives, surfactants or collectors are also injected, in addition
to steam, into the
chamber. Product collection pipe is placed beneath the steam dispersing pipe,
at the bottom of
the gravity drainage chamber. The steam delivered into the gravity drainage
chamber heats the
oil sands ore, lowers the viscosity of the bitumen and converts into water.
The liquefied bitumen
and water mixture flows downward, enters the product collection pipe from
which it is delivered
to the surface (production well). The gravity drainage chamber has dimensions
of
approximately: length - 700 m; width - 150 m; height - 20 m. As a rule several
chambers are
constructed in close vicinity and operated to maximally utilize the heat
delivered and optimize
the production of bitumen. The temperature of steam supplied to the chambers
usually exceeds
200 C.Typically over three volumes of steam are required to produce one volume
'of raw
bitumen. The production well delivers one volume of bitumen per three volumes
of water. The
water recovered from the gravity drainage chamber is contaminated and requires
treatment
prior to recycling and steaming. About 80-90 wt of produced water can be
recycled after
treatment. Required make-up/fresh water amounts to about 0.5 volume for every
volume of
bitumen produced. The high mineral content, salty water that cannot be
recycled has to be
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condensation of injected steam. The water pumped out from the reservoir is
contaminated and requires treatment prior to recycling and steaming. About 80-
90 wt%
of produced water can be recycled after treatment. Typically required make-
up/fresh
water amounts to about 0.5 volume for every volume of bitumen produced. The
high
mineral content, salty water that cannot be recycled has to be disposed. The
gas from
the production well is either treated and partially utilized or flared. Huge
volumes of
natural gas are required for generation of steam from the treated and make-up
waters.
Natural gas cost accounts for significant portion of the cost of producing 1
barrel of
bitumen by SAGD technology. The consumption of natural gas by SAGD technology
results in generation of ever increasing volumes of CO2. Projected increase in
bitumen
production in Athabasca region to 5 million barrels per day using SAGD does
not
appear to be sustainable. There is growing evidence that Northern Alberta
region
cannot supply sufficient volumes of water and natural gas to maintain the
rapid
development of the oil sands industry. Disposal of the contaminated produced
water
becomes a major environmental problem. Collection and sequestration of CO2,
the gas
that is considered to be the main cause of climate change, while technically
proven,
may increase the cost of oil sands processing to a point of making the oil
sands industry
economically unviable.
The inability of SAGD to meet the environmental and economic growth
expectations of
the oil sands industry has sparked development of a new generation of in-situ
bitumen
recovery technologies based on application of low boiling hydrocarbons ¨ VAPEX
(vapour recovery extraction) technologies. In general VAPEX technologies use
the
hardware developed by SAGD but either partially (hybrid processes) or totally
(hydrocarbon processes) replace steam with selected hydrocarbons or a mixture
of
selected hydrocarbons. So far the development of the new generation of in-situ
processes for bitumen/heavy oil recovery is limited to bench scale, continuous
bench
scale and pilot plant (field) testing and modelling. As a rule low boiling
hydrocarbons
are injected into the gravity drainage chamber in the form of vapours and/or
liquids. The
mixture of hydrocarbon vapours and/or liquids injected into the chamber
delivers the
latent and condensation heats to the perimeter of the chamber and mobilizes
the
bitumen. The flow of bitumen results from lowering its viscosity due to
increase in
temperature and from solubilisation of some components of the bitumen in the
hydrocarbon solvents. The product composed of the components of bitumen
dissolved
in hydrocarbon-solvent is, after recovery from the production well, subjected
to flash
distillation; the hydrocarbon vapours are recovered, pressurized, and re-
injected in the
form of liquids and/or vapours into the chamber; the bitumen is utilized as
required.
Attempts are being made to eliminate the recycling of the low boiling
hydrocarbons
recovered from the production well by distilling them off from the
bitumen/hydrocarbon
mixture prior to the mixture leaving the gravity drainage chamber. This is
accomplished
by using heaters placed in the product collection pool and/or product
collection pipes.
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Attempts are also being made to separate from bitumen, in-situ, some of the
coke
precursors, namely the asphaltenes, so that the bitumen product should be more
amenable to upgrading compared to bitumen generated by other processes that do
not
involve in-situ de-asphalting. For this purpose the N-Solv Process (1) applies
propane
or butanes - well known de-asphalting agents.
The new generation of proposed in-situ bitumen recovery processes, based on
application of low boiling hydrocarbons or a mixture of hydrocarbons and
steam, offers
significant advantages compared to commercial SAGD technology. The new
generation
processes have the potential to reduce consumption and processing of water by
50-
90%. The consumption of energy is expected to be reduced by up to 50%. The
generation of CO2, the main component of the green house gas (GHG), may be
reduced by 50-90%. The bitumen production rates can be increased by 70% or
more
while the volumes of produced sand can be reduced. There is a potential for
significantly reducing the operating and capital costs. The
shortcomings/challenges
facing the new generation of hydrocarbon based in-situ bitumen recovery
processes
are: uncertainties regarding losses of hydrocarbon solvents- so far the field
trials show
losses in the range of 10-25%; the need for using high purity solvents ¨
specifically N-
Solv process performance is hampered by presence of methane in the gravity
drainage
chamber; growing scarcity of low boiling hydrocarbons required for bitumen
recovery
and pipelining; high cost of low boiling hydrocarbons compared to bitumen
cost;
uncertainties regarding the ecological impact of low boiling hydrocarbons lost
during in-
situ operations and released to atmosphere.
It is the object of the present invention to provide a process for effective
and
environmentally friendly in-situ bitumen recovery that will encompass and
surpass all
advantages of the proposed hydrocarbon based in-situ bitumen recovery
processes.
It is another object of the present invention to provide a process that will
be freed of the
shortcomings/challenges facing the new generation of hydrocarbon based in-situ
bitumen recovery processes.
These and other objects of the present invention will be apparent from the
following
description of the preferred embodiments, the appended claims and from
practice of the
invention.
SUMMARY
The present invention provides an efficient method for injecting pressurized
di-methyl
ether (DME) liquids and/or vapours into the gravity drainage chamber,
mobilizing the
bitumen in the chamber by lowering its viscosity due to the latent and
condensation
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heats of the DME and the capacity of DME to act as solvent significantly more
powerful
' compared to propane and butanes, draining the binary liquid product composed
of
DME/bitumen and DME/water solutions towards the product collection pool,
accumulating the product in the collection pipe, delivering the product to the
surface via
the production well, separating the binary liquid, subjecting the DME/ water
solution to
flash distillation by depressurizing, separating the DME vapours, pressurizing
the
separated vapours and recycling the DME liquids and/or vapours and cleaning,
pipelining and utilizing the DME/bitumen solution as required. The present
invention, as
summarized above and compared to prior art replaces costly and scarce
hydrocarbons
with DME, requires less energy, has the capability to remove some water from
the
gravity drainage chamber prior to raising its temperature, enhances the
solubilisation
and mobilization of bitumen by removing the water and the polar and other
components
of the bitumen which are not soluble in propane/butanes and thus increasing
the
porosity of the oil sands ore and the rate of penetration of DME vapours into
the ore,
reducing the viscosity of the generated DME/bitumen solution, using DME
solvent
costing less compared to liquefied petroleum gas (LPG) or condensate from
which the
hydrocarbon solvents are separated, using non-hydrocarbon solvent that can be
readily
manufactured, is widely accessible, environmentally benign, well known as
excellent
Diesel fuel and decomposes over relatively short period of time when released
to
atmosphere.
BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1 presents changes in saturated vapour pressures of DME (di-methyl
ether),
propane and butane at different deposition depths and as a function of
temperature.
Figure 2 presents changes in kinetic viscosities for selected bitumen/DME (di-
methyl
ether) blends as a function of temperature.
Figure 3 depicts the applicability of various bitumen recovery technologies
depending
on the depth of the reservoir containing the oil sands ore or heavy oil.
Figure 4 presents the schematics of DME fired 02-0O2 drive two-stroke Diesel
engine
co-generation system with re-burning 02-0O2 drive boiler and cryogenic CO2
capture.
Figure 5 depicts the concept of Skin Electric Current Tracing (SECT) method
for heating
DME to be applied as solvent and diluent.
Figure 6 presents the schematics of the experimental set-up employed for
extraction of
oil sands ore with liquid DME.
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DESCRIPION OF THE PREFERRED EMBODIMENTS
The starting material used in the process of the present invention for in-situ
recovery of
bitumen or heavy oil from their reservoirs is the di-methyl ether (DME). DME
has a
chemical formula CH3 ¨ 0 ¨ CH3; it is produced commercially in many countries
(2, 3).
DME can be produced by gasification of coals, bio-mass or other solid fossil
fuels
followed by subjecting the generated gas to water shift reaction and reacting
the
generated syngas in a catalytic ebullated bed to form the DME. DME can also be
produced from natural gas (methane) via auto-thermal reaction (3) that
requires steam,
oxygen and utilizes CO2 that is recycled in the process.
At temperatures above -25.1 C DME occurs as a gas that can be readily
liquefied at
moderate pressures and temperatures below 127 C. DME has exceptionally high
cetane number estimated at 55-60 compared to quality hydrocarbon based Diesel
oil
(45-53). It performs very well when fired in Diesel engines and its
application at low
temperatures is free of problems typical of hydrocarbon based Diesel oil. DME
suppresses corrosion, does not contain any sulphur or nitrogen and, therefore,
the
products of DME combustion in nitrogen free atmosphere do not contain any
sulphur
and nitrogen oxides (SO), and N04. DME reduces Diesel engines emissions by 95%
as
compared with conventional Diesel fuel.
Some DME properties relevant to its application for in-situ recovery of
bitumen are
presented in Table 1 and compared to those of propane. Propane is considered
by prior
art to be the most promising hydrocarbon solvent for in-situ recovery of
bitumen. In
terms of boiling temperatures, gravity of liquids, gas gravities, critical
temperatures and
critical pressures the differences between DME and propane are insignificant.
The
major difference that results from structural make-up of both solvents (ether
versus
hydrocarbon) is the capability of DME to dissolve water and polar compounds.
This
results from hydrophobic ¨ hydrophilic character of DME. Propane, a highly
hydrophobic
compound, does not show any capability for water dissolution. Propane, butanes
and
pentanes (C3-05), have been well known for their capabilities to precipitate
some polar
compounds from bitumen solutions and are applied as de-asphalting agents.
According
to Hagight (4) application of C3-05 as solvents for in-situ bitumen recovery
causes
precipitation of asphaltenic fraction that often results in severe damage to
the formation
thus leading to significant drop in bitumen production.
The capability of DME to dissolve water and polar compounds indicates that
injecting
DME into the gravity drainage chamber shall remove the water and polar
compounds, in
addition to oily components, from the oil sands ore. Removal of water and
polar
compounds should increase the porosity of the oil sands ore, make it more
accessible
CA 02652930 2015-04-15
to DME vapours, facilitate the heat transfer and mobilization of the bitumen,
and reduce
the viscosity of the solution composed of bitumen and DME. The capability of
DME to
remove the water from high water content bitumen ore, at reservoir temperature
and
prior to commencement of heating, shall allow for additional savings of
energy.
The important advantage of the present invention is that DME can be generated
at low
production cost, from non-petroleum, solid fossil fuels (2, 3). There is a
consensus
among DME producers that subject to availability of inexpensive low rank solid
fossil
fuel DME market price shall be significantly lower compared to conventional
Diesel fuel,
liquefied petroleum gas (LPG) and condensate. Japanese DME process developers
estimate that the production cost of DME synthesized directly from coal
gasification gas
can be as low as US$ 100/tonne (4). In 2011 market prices for propane/butanes
and
bitumen were in the range of Can.$ 560-920/metric ton and Can.$ 390/metric
ton,
respectively.
Propane recommended by prior art for in-situ recovery would have to be,
according to
prior art (1), high purity, methane free propane. The cost of propane
separation would
further increase its cost. Propane and butanes are typically the products of
natural gas
processing. Limited availability of propane, butanes and condensate in
Northern Alberta
is of considerable concern to the oil sands industry and impedes its growth.
The other major advantage of the present invention is that DME has the
capacity to
recover from the deposit the whole bitumen including the asphaltenic fraction
composed
mainly of polar components namely, asphaltenes, some resins and some high
molecular weight aromatics ¨ the asphaltenic fraction. Using any of the
existing de-
asphalting procedures the asphaltenic fraction can be separated from the DME
recovered bitumen and subjected to co-processing (5) yielding distillable oils
in
quantities essentially equivalent to the mass of the separated asphaltenic
fraction. The
de-asphalted fraction can be efficiently processed using conventional
upgrading
technologies. This approach, based on utilization of the asphaltenic fraction,
results in
increasing the yield of primary distillable oils by about 25 wt%, per barrel
of bitumen, as
compared to conventional bitumen upgrading technologies where the asphaltenic
fraction is either rejected, gasified or converted into undesirable, high
sulfur content
coke. Primary distillable oils produced by co-processing (5) would be,
according to
Alberta Energy, exempted from royalty payments.
The propane based in-situ recovery of bitumen leaves in the reservoir some
organics of
which, reportedly (1) about 60-70 wt% are asphaltenes. However, in the
recovered
bitumen there still remains up to 40 wt% of the original asphaltenes plus
unspecified
content of resins and high molecular weight aromatics ¨ of which some are also
coke
precursors. These coke precursors, unless they are separated by de-asphalting
process
prior to upgrading, will generate coke and impede the upgrading process.
Therefore, the
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propane assisted bitumen recovery generates product that still requires de-
asphalting.
= The hydrogen rich (-8.5 wt% H) asphaltenic fraction left in the reservoir
when propane
is used for bitumen recovery is irreversibly lost and cannot be utilized for
generation of
distillable oils (5) or hydrogen.
The other major advantage of the present invention is that at set pressure the
application of DME for in-situ bitumen recovery allows to operate at higher
temperatures
as compared to propane (Fig. 1). Within the pressure range of 1-2 MPa, most
likely to
be maintained in the gravity drainage chamber, the DME will generate
temperatures
about 20 C higher compared to propane. Consequently, the DME will lower the
viscosity of the binary liquid in the chamber significantly more compared to
propane.
Furthermore, if the operating temperature in the chamber reaches 97 C, the
heat of
propane condensation cannot be transferred to the perimeter of the chamber due
to
propane critical temperature, Table1. By contrast, DME can effectively
transfer the heat
of condensation at temperatures up to126 C.
The other major advantage of the present invention is that DME delivered by a
pipeline
from its production facility to in-situ bitumen production site can also be
utilized as a
quality Diesel fuel for Diesel vehicles as well as for electric power and heat
generation.
Such utilization of DME will eliminate the need for pipelining natural gas
that is required
for SAGD.
The other major advantage of the present invention is the application, at the
central
bitumen processing facility, of two-stroke DME fired Diesel engines. The
engines are
capable of utilizing oxygen and recycling the flue gas to increase thermal
efficiency and
separation of CO2. They will generate electric power and heat that can be
utilized in the
central facility for a variety of applications. Two-stroke Diesel engines are
expected to
simplify the operations of the in-situ bitumen recovery plants and lower their
capital
costs.
The other major advantage of the present invention is the reduction in
kinematic
viscosities of blends composed of bitumen and DME liquids (Fig. 2). At
temperatures
over 50C and pressures over 1 MPa the viscosity of the blend composed of 75
wt%
bitumen and 25 wt% DME would be less than 7 cSt. Increasing the content of DME
in
the blend to 30 wt% would reduce the viscosity to below 3 cSt. Reducing the
content of
DME in the blend to 20 wt% would result in viscosity of about 12 cST or less.
It is,
therefore, expected that removal of blends composed of 80-85 wt% of bitumen
and 20-
15 wt% DME from the gravity drainage chamber operating at depth over 130 m,
temperatures over 50C and pressures of more than 1 MPa shall be very
effective.
The other major advantage of the present invention is the potential of DME to
substitute
for the condensate (C3-C8 hydrocarbons) required for pipelining of bitumen or
heavy oil.
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The content of condensate in either bitumen/condensate or heavy oil/condensate
blend
= has to be adjusted in such a way that the kinematic viscosity of the
blend shall be about
250 cSt or less. Within the temperature range of 10-50 C bitumen/DME blend
containing 10-15 wt% DME would satisfy this requirement. The pressure
generated by
saturated DME vapours at temperatures up to 50 C will be about 1.0 MPa.
Typically the
pipelines are designed to withstand pressures significantly higher than that.
Additional
advantage of DME as a substitute for the condensate is that DME content in
DME/bitumen solution below approximately 45wrio will not result in
precipitation of
bitumen components. Propane and butanes will spark a precipitation under such
conditions. Precipitation increases the pressure drop thus reducing pipeline
economy
and is believed to be the source of plugging the flow lines at downstream
bitumen
processing/upgrading facilities.
The other major advantage of the present invention is the capability of DME to
be
applied for in-situ recovery of the bitumen from relatively shallow to the
deepest Alberta
reservoirs (Fig. 3). The pressure in Alberta oil sands reservoirs increases by
about 0.75
MPa per every 100 m of depth. It is believed that the oil sands ores do not
occur at
depths exceeding 700 m (600 m for Athabasca deposit). At 700 m the pressure in
the
reservoir is about 5.37 MPa. Surface mining of the oil sands ore can be
economically
practised to a depth of about 70-75 m. SAGD system does not operate smoothly
at
saturated steam pressures lower than 1.0-1.1 MPa. That indicates that it is
unsafe to
carry out SAGD operations at depths less than 130 m. To eliminate the
possibility of
blow-outs, SAGD operations are carried out, as a rule, at depth significantly
more than
130m. Cold injection of propane, butanes and DME could be carried out, due to
low
pressure of saturated vapours of these compounds, at depth less than130 m.
Specifically, operations with propane could be carried out at depths of about
90 m down
to about 570 m. Operations with butane could be, theoretically, carried out at
depth 20-
30 m down to about 500 m. Application of DME for in-situ bitumen recovery can
be
carried out over the range of 50-700 m which in terms of pressure is
equivalent to 1.15-
5.37MPa. It therefore appears that as compared with the most promising
hydrocarbons,
DME has significant advantage for in-situ recovery of bitumen from oil sands
and
carbonate deposits that cannot be recovered by mining.
Another important advantage of the present invention was unravelled recently
based on
results of the capital and operating costs estimates for SAGD plant carried
out by
General Electric and Halliburton Corporation. General Electric (6) estimated
the cost of
replacing the steam-generation, water-treatment and natural-gas-combustion
components of the SAGD plant and concluded: "As much as 80% of the capital
cost and
65% of the operating cost associated with facility development and operation
is
dedicated to treatment of produced water". Halliburton estimate for such
replacement is
65% reduction in operating cost (8). NALCO's published estimate (9) for SAGD
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operating cost associated with steam generation, water treatment and gas
consumption
by boiler amounts to 60-70%.
The DME Process replaces the steam generation, water treatment and natural gas
combustion components of the SAGD plant. In addition, the DME plant has the
capacity
to recover approximately 80% more bitumen compared to equivalent SAGD plant.
Another very important advantage of the present invention is that DME can be
applied
for both, in-situ bitumen recovery and as a diluent for bitumen pipelining.
Application of
DME eliminates the demand for heat to produce steam and reduces the electric
power
consumption, as compared to propane, by a factor of two. Numerous in-situ DME
based
bitumen recovery plants in the Athabasca area could be supplied with power by
one
central co-generating plant. Such central power plant with flue gas recycling
would use
DME fired 02/CO2 drive two-stroke Diesel co-generation engine with DME re-
burning
02/CO2 drive boiler and cryogenic CO2 capture system (Fig. 4). The oxygen
required for
such plant could be produced on site or could be supplied by pipeline from the
plant
generating oxygen for coal gasification facility. Pure CO2 generated by
central co-
generating plant would be suitable for EOR (enhanced oil recovery), CBMR (coal
bed
methane recovery) and its capture would not present any technical challenge.
The
central power and heat co-generation plant would not be effective in providing
the
individual DME based bitumen recovery plants with the heat required to raise
the
temperature of DME injected into the gravity drainage chambers. Such heat
could be
provided by application of the Skin Electric Current Tracing (SECT) method
(Fig. 5).
SECT has been successfully applied all over the world for heating
pipes/pipelines to
temperatures as high as160C. Provision of heat using the SECT method would
further
simplify the operation of the individual DME based in-situ bitumen recovery
plants. The
plants would be supplied with DME and electric power only. Under such
circumstances
there would be no need to locate the power and heat co-generation plant in
bitumen
producing region. The power and heat cogeneration plant (Fig. 4) could be
constructed
as one of the components of the integrated coal gasification, DME synthesis,
co-
processing and bitumen up-grading central facility. The heat generated by co-
generation plant would be fully utilized by the integrated facility. The DME
based in-situ
bitumen recovery plants would pipeline the DME/bitumen dilbits freed of
particulates
directly to the central integrated facility for separating, processing and re-
cycling of the
recovered DME. That would further simplify the operation and reduce the
capital and
operating costs of the bitumen recovery plants and the whole integrated
facility. The in-
situ DME based bitumen recovery plants would not emit any CO2, volatile
organic
hydrocarbons (VOC's), SO. and NO.; they would not require natural gas, natural
gas
pipeline, condensate, condensate gas pipeline, oxygen pipeline, CO2 pipeline
and the
auxiliary equipment associated with natural gas combustion, generation of heat
and
steam, water treatment, separation and disposal of CO2.
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Having described the foregoing features and advantages of the present
invention the
= following examples are provided by way of illustration, but not by
limitation.
Example I:
Extraction of oil sands ore with liquid DME at ambient temperature
The starting material used was oil sands ore containing 12.1wt% moisture on as
received basis and 11.8 wt% of di-chloro methane (CH2Cl2) extractable
material, on dry
basis.
The set-up used for extraction with liquid DME is presented in Fig. 6. The set-
up
included cylinder A containing liquid DME under nitrogen. Cylinder A was
supplied with
nitrogen at a flow rate that resulted in discharging 50 ml per min. of liquid
DME from
cylinder A. The DME discharged from cylinder A was passed through a compacted
layer of oil sands ore placed in tube B and the liquid effluents containing
the DME, the
bitumen, extracted materials and water were introduced into vessel C. Vessel C
was
connected via pressure release valve (PRV) with vessel D that was immersed in
liquid
CO2 and vented to atmosphere.
The experiment was carried out as follows. About 1,000 (+I- 1) g of oil sands
ore was
placed and compacted in tube B and the set-up was assembled. The nitrogen flow
regulator (FR) valve was adjusted in such a way that liquid DME was flown
through the
layer of the oil sands ore at a rate of about 50 ml per minute at ambient
temperature
(18-20 C) while the pressure in the set-up was maintained, using PRV valve, at
0.6
MPa. The flow was maintained for three (3) hours that resulted in about 8 L of
liquid
DME passing through the oil sands ore layer. Subsequently the flow of DME was
terminated using FR and FR1, the pressure in vessel C was reduced to
atmospheric
pressure and tube B was separated. The residual solids were removed from the
tube
and vented for a few minutes until the DME evaporated. The DME free solids
were
blended, placed in a tightly closed glass jar and subjected to moisture
determination
followed by extraction with di-chloro methane (CH2Cl2). The results of
analyses show
that the moisture content of the treated oil sands ore was reduced from 12.1
wt% to 2.4
wt%, a reduction of close to 80 %. The content of the CH2Cl2 extractable
material was
reduced from 11.8 wt% to 4.1 wt%, a reduction of about 65 wt%.
Example 2:
Extraction of oil sands ore with liquid DME at temperature of 50 C
The same starting material (see Example I) was used.
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The set-up used for extraction was the same as employed in Example I and
presented
. in Fig. 6 except that tube B was placed inside of a hinged heater
maintaining the
temperature of 50 (+1- 2) C and the PRV valve was set to maintain a pressure
of 1.2
MPa. in the set-up.
The results of analyses of oil sands ore extracted with liquid DME at 50 C
showed that
the moisture content of the treated product was reduced from 12.1 wt% to 0.3
wt%, a
reduction of approximately 97-98%. The content of CH2Cl2 extractable material
was
reduced from 11.8 wt% to 0.2 wt%, a reduction of over 98%.
13.
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REFERENCES
1. Press Release, Calgary AB, November 20, 2006, Enbridge and Hatch Invest
in
N-Solv to construct New Oil Sands Technology Pilot Plant
2. DME (Di-Methyl Ether) Perspectives in China, Huang Zhen, Shanghai Jiao
Tong University, P.R. China, World CTL 2008, Paris, France
3. Coal Conversion into Dimethyl Ether as an Innovative Clean Fuel, Yotaro
Ohno, Tetsuyma Tanishima, Seiji Aoki, DME Project, JFE Holdings, Inc.,
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4. DME Handbook; Edited and Published by Japan DME Forum, 2006
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